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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.

Dentons will be holding a breakfast discussion on the Winter Package at our London office on 8 December 2016 (8.30 to 10 am).  If you would like to attend, please email  .

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

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

Conventional

  • November 29, 2016 – Raging River Exploration Inc. closed a Viking consolidation transaction. The company acquired approximately 620 boe per day — 97 per cent light oil — of production and 24 net sections of land prospective for Viking light oil, for total cash consideration of approximately CDN$58 million subject, to customary adjustments. In a separate release, Northern Blizzard Resources Inc. said it completed the sale of Viking light-oil assets in the Coleville area of Saskatchewan for cash consideration of CDN$58 million, subject to customary adjustments.
  • November 23, 2016 – Lightstream Resources Ltd. announced that sale procedures under the Companies’ Creditors Arrangement Act (CCAA) have concluded and that the credit bid submitted by the ad hoc committee of holders of approximately 91.5 per cent of the company’s 9.875 per cent second lien secured notes due 2019 is the successful bid. In accordance with the sale procedures, the company will seek to implement the credit bid by finalizing the terms of the definitive agreements and applying to the Court of Queen’s Bench of Alberta for an approval and vesting order anticipated to be heard on Dec. 8, 2016.
  • November 23, 2016 – Baytex Energy Corp. entered into an agreement to acquire heavy oil assets located in the Peace River area of northern Alberta for cash consideration of CDN$65 million, subject to customary adjustments. The assets add approximately 3,000 boe per day of production and more than double Baytex’s land base in the area. The acquisition will be funded through a concurrent $100 million bought deal financing.
  • November 18, 2016 – Spartan Energy Corp. entered into an agreement with ARC Resources Ltd. to acquire assets in southeast Saskatchewan for cash consideration of CDN$700 million, subject to customary adjustments. The acquisition will be funded through Spartan’s pro forma credit facility and through committed concurrent equity financings totalling CDN$505 million.
  • November 11, 2016 – ConocoPhillips announced plans to divest of US$5 billion to US$8 billion in assets, which will include assets in Western Canada. “These will be primarily North American gas assets, including some assets from our Western Canada Business Unit,” company spokesperson Rob Evans said, when asked following an analyst day event whether assets from Canada would be included.  “Specific details on Western Canada assets to be [marketed] are currently being worked out,” he added.
  • November 8, 2016 – Delphi Energy Corp. has entered into a non-binding Letter of Intent with an existing working interest partner. This transaction is intended to accelerate the development of its liquids-rich Deep Basin natural gas play at Bigstone in northwest Alberta. Under the LOI, the partner will undertake a CDN$40 million (gross) joint drilling program, to be completed before July 15, 2017, of which Delphi will contribute CDN$6 million while retaining a 65 percent working interest, in approximately five to six wells to be drilled at Bigstone Montney. The partner will contribute CDN$20 million in capital, along with its 35 per cent working interest share of CDN$14 million. In addition to the above drilling capital contribution, Delphi will receive CDN$30 million in cash at closing for equalization consideration.
  • November 2, 2016 – Tamarack Valley Energy Ltd. and Spur Resources Ltd. entered into an arrangement agreement providing for the acquisition by Tamarack of all the issued and outstanding common shares of Spur. As consideration, Tamarack will issue an aggregate of 90.1 million common shares of Tamarack and CDN$57.3 million in cash. Tamarack will also be assuming Spur’s net debt, estimated to be CDN$25.7 million as at Nov. 30, 2016, after accounting for proceeds from the exercise of all outstanding options of Spur, and severance and transaction costs. Based upon the previous 10-day VWAP of Tamarack of CDN$3.60 per share, the total consideration payable by Tamarack, including the assumption of debt, is approximately CDN$407.5 million.

Unconventional

  • November 7, 2016 – Woodfibre LNG will commence construction on British Columbia’s first liquefied natural gas processing and export terminal in 2017. The facility near Squamish, north of Vancouver, will export 2.1 million tonnes a year once it is operational in 2020, according to a company statement.
  • November 4, 2016 – Athabasca Oil Corporation announced an upsizing of the previously completed contingent bitumen royalty on its thermal assets with Burgess Energy Holdings L.L.C. for additional cash consideration of CDN$128.5 million. Including the initial royalty, Athabasca has now raised total cash proceeds of CDN$257 million.

Midstream

  • November 30, 2016 – The federal government announced that it had approved Kinder Morgan Inc.’s proposal to more than double the capacity of its Trans Mountain pipeline. Prime Minister Justin Trudeau also said Ottawa had vetoed Enbridge Inc.’s proposed Northern Gateway line, which would have taken crude from Alberta’s oilsands to the Pacific coast. It approved Enbridge’s plan to replace Canadian segments of Line 3, which carries crude from Alberta to Wisconsin.
  • November 16, 2016 – Tidewater Midstream and Infrastructure Ltd. entered into an agreement with to acquire an approximate 50 per cent working interest in 150 kilometres of gas gathering pipelines which are directly connected to Tidewater’s existing Brazeau River Complex (BRC), in addition to three natural gas storage reservoirs that are also directly connected to the BRC by means of the acquired pipelines, for a purchase price of CDN$15 million in cash.
  • November 3, 2016 – Union Gas announced the commercial in-service of a CDN$391 million expansion of natural gas pipeline and compression facilities that will move an incremental 0.4 PJ/d (.36 Bcf/d) of natural gas supplies through its Dawn-Parkway System, which links markets in eastern Canada and the northeast U.S. with the Dawn Hub. The facilities placed into commercial service comprise approximately 20 kilometres of 48-inch diameter pipeline between Hamilton and Milton, Ont., and an additional compressor facility at the existing Lobo Compressor Station near London.

Petrochemicals Manufacturing

  • November 4, 2016 – A part of the acquisition by Inter Pipeline Ltd.  (IPL) of The Williams Companies Inc.’s and Williams Partners L.P.’s  Canadian natural gas liquids midstream businesses, IPL assumes responsibility for the potential construction of a CDN$1.85 billion propane dehydrogenation (PDH) facility located near the Redwater Olefinic Fractionator. This facility would convert locally sourced propane into more valuable polymer grade propylene. Inter Pipeline is also assessing the commercial viability of constructing an additional processing facility, which would convert propylene into polypropylene, a solid plastic used in manufacturing a wide range of finished products. The preliminary estimate for the polypropylene facility is approximately CDN$1.3 billion. IPL is currently pursuing long-term, fee based offtake agreements with a number of global plastics manufacturing and marketing companies. Subject to securing appropriate commercial contracts, Inter Pipeline anticipates making final investment decisions on the PDH and polypropylene facilities by mid-2017, with both plants operational by mid-2021.

Oilfield Services

  • November 24, 2016 – Calfrac Well Services Ltd. entered into an agreement with Peters & Co. Limited, as lead underwriter on behalf of a syndicate of underwriters, pursuant to which the underwriters have agreed to purchase, on a private placement basis, 14,040,000 common shares of Calfrac at a price of CDN$2.85 per share for total gross proceeds of approximately CDN$40 million.
  • November 24, 2016 – Total Energy Services Inc. announced an intention to make an offer to purchase all of the issued and outstanding common shares of Savanna Energy Services Corp. for consideration consisting of common shares of Total. Total anticipates that, if the offer is successful, holders of Savanna shares will receive, in exchange for each Savanna share, 0.1132 of a common share of Total.
  • November 23, 2016 – Alberta Investment Management Corporation (AIMCo) signed a letter of commitment and a subscription agreement, on behalf of certain of its clients, to enter into a strategic financing relationship with Savanna Energy Services Corp. The financing relationship provides for a CDN$200 million debt-with-warrants financing and a private placement of 13 million common shares of Savanna at a price of CDN$1.45 per common share for gross proceeds of CDN$18.85 million.
Significant Developments in Canadian Energy – For the Month of November 2016

Sanctions in Energy: Russia and Iran

US and EU sanctions related to Russia and Iran have a direct and targeted impact on the energy sector. The sanctions regimes against Russia and Iran differ substantially and seem to be moving in different directions. In this article, we explore the challenges facing US and EU energy companies seeking to operate in Russia and Iran.

Brief overview of energy related sanctions against Russia

US Sanctions

Since March 2014, the US has imposed an increasingly strict set of sanctions against Russian and Ukrainian individuals and companies. These sanctions generally fall into four categories: a list of blocked persons and entities, identified as Specially Designated Nationals, or SDNs; much more limited restrictions for specified Russian banks, oil companies and technology companies, identified as a Sectoral Sanctions Identification List or SSI List; export controls; and a full commercial embargo of Crimea. These sanctions are imposed pursuant to several Executive Orders promulgated by President Obama and the Ukraine-Related Sanctions Regulations[1]. US Persons—defined as US citizens and permanent residents, entities organized under US jurisdictions, and persons physically in the United States—must comply.

The US has designated as SDNs a number of key government and military officials (both Russian and from the former Ukrainian Government), individuals with close ties to the Russian Government, and Russian and Crimean entities[2]. US Persons are generally prohibited from transacting with any of these blocked persons, and must freeze such blocked persons’ property in their possession, custody, or control. These SDNs are also banned from traveling to the US. In comparison with the SSI List, SDNs targeted inter alia leaders of the Russian oil companies.

According to SSI List and its related OFAC’s Directives, the following activities by a US Person or within the United States related to oil companies are prohibited, except to the extent provided by law or unless licensed or otherwise authorized by the Office of Foreign Assets Control: the provision, exportation, or re-exportation, directly or indirectly, of goods, services (except for financial services), or technology in support of exploration or production for deep-water, Arctic offshore, or shale projects that have the potential to produce oil in the Russian Federation, or in a maritime area claimed by the Russian Federation and extending from its territory, and that involve any person determined to be subject to this Directive, its property, or its interests in property. The prohibition on the exportation of services includes, for example, drilling services, geophysical services, geological services, logistical services, management services, modeling capabilities, and mapping technologies[3]. The SSI List includes, among others, Russia’s largest energy companies.

EU sanctions

The US and EU sanctions are largely aligned. Like the US, the EU has also adopted sanctions that block persons, restrict financing, limit certain exports, and broadly prohibit trade with Crimea. EU persons—EU citizens and permanent residents, entities organized in EU member states and persons physically in the European Union—must comply.

While there are differences between the US and EU sanctions, these are more of a degree than of a kind. For example, the EU and US do not block an identical set of individuals and entities, but the implications for those blocked persons are the same: a visa ban (for individuals) and a freezing of all assets[4]. Notably for EU companies in the energy sector, EU sanctions prohibit the provision of loans or investment services to Crimean companies, ban exports of goods and technology and prohibit the provision of technical assistance, brokering, construction, or engineering services, in the energy sector and in the prospecting for, and exploration and production of oil, gas, and mineral resources, to any Crimean entity, or for use in Crimea. Contracts signed prior to 20 September 2014 are exempted[5].

Brief overview of energy related sanctions against Iran

On 14 July 2015, the “P5+1” working group (China, France, Germany, Russia, the UK and the US) reached a landmark agreement with the Government of Iran to adopt the Joint Comprehensive Plan of Action (the JCPOA). Under the JCPOA, the P5+1 agreed to implement broad UN, US and EU sanctions relief in exchange for Iran’s ongoing compliance with a number of nuclear-related measures. This sanctions relief will occur in two phases: (1) when the International Atomic Energy Agency (the IAEA) verifies Iran’s compliance with nuclear-related measures, which occurred on 16 January 2016; and (2) when the IAEA, together with the UN Security Council, confirms that Iran’s nuclear materials are being used for peaceful activities, or 18 October 2023, whichever is sooner[6].

US Sanctions

Most of the US sanctions that are suspended—both in the first and second phases—are extraterritorial, i.e., they apply to non-US Persons who do business with Iran. US companies seeking to engage the Iranian market, therefore, need to be aware of the limits of US sanctions relief under the JCPOA, namely:

1. US Persons generally remain prohibited from doing business with Iran. The JCPOA will not lift the general commercial embargo which prohibits US Persons from doing business with Iran, except for certain sales of civilian commercial aircraft to Iran, imports of Iranian-origin carpets and foodstuffs.
2. US companies’ overseas subsidiaries will be licensed to transact with Iran under OFAC’s General License H. The JCPOA will license overseas subsidiaries of US entities for activities consistent with the agreement. However, the licensing methodology and the definition of “overseas subsidiaries” are not described and remain to be clarified.
3. Other US sanctions including those related to counter-terrorism or human rights-related sanctions asserting extraterritorial application[7] will remain in place.
4. On 7 October 2016, OFAC issued updated guidance on several issues. The issues addressed include banking transactions with Iranian banks; dollar-denominated transactions; acceptable due diligence standards; and part-ownership of Iranian companies by entities who remain on the SDN list[8].

With regard to Iran’s vast oil and gas reserves, the first phase of relief will mean the US will no longer sanction non-US Persons who engage in transactions with Iran’s energy, shipping and shipbuilding sectors, or port operations[9]. Nor will the US any longer sanction non-US persons who invest in Iran’s oil, gas and petrochemical sectors; purchase, sell, transport, or market oil, gas and petrochemicals from Iran; export, sell or provide refined petroleum products and petrochemical products to Iran; or otherwise transact with Iran’s energy sector including Naftiran Intertrade Company, National Iranian Oil Company and National Iranian Tanker Company, and associated services[10]. Non-nuclear-related sanctions still remain in place on all companies and persons, regardless of nationality, who seek to do business with any Iranian people or entities which remain on the SDN List.

EU sanctions

EU sanctions relief is far more expansive. Unlike the US, the EU will allow its companies to invest directly in Iran and transact with Iranian persons. EU member states have agreed to terminate or suspend all “economic and financial sanctions” against Iran[11]. As a result of the first phase of sanctions relief under the JCPOA, EU persons are permitted to trade in Iranian crude oil and petroleum products, natural gas and petrochemical products, as well as related financing. Similarly, the sale, supply or transfer of equipment and technology, as well as the provision of technical assistance and training in this sector are permitted. In addition, EU Persons are free to grant financial loans or credit and to participate in joint ventures with any Iranian persons engaged in the oil, gas and petrochemical sectors in Iran or elsewhere.

Implications for energy companies

While the US and EU have both imposed a number of sanctions on Russia that aim directly to constrain investment in Russia’s energy sector—and in particular its future oil development—there are a number of reasons why Russia’s energy sector may possibly continue to attract US and European investment.

To begin with, US and EU sanctions are (thus far) narrowly targeted. Unless specifically prohibited, Russia’s economy, including its energy sector, is fully open to investment. Second, the sanctions against Russia could be lifted, if the situation in Eastern Ukraine and Crimea develops in certain directions. Finally, US and EU companies are more familiar with Russia and Russian business practices in comparison to Iran, a country where numerous other compliance and other business risks are encountered.

During the first phase of sanctions relief under the JCPOA, which began on 16 January 2016, EU energy companies and the overseas subsidiaries (again yet to be defined) of US energy companies will now have the opportunity to engage Iran’s vastly underdeveloped energy sector. It is estimated that the country will need hundreds of billions of dollars of investment to restore its petroleum fields and then further develop them. EU and the overseas subsidiaries of US companies seeking to engage Iran should therefore be prepared to understand and implement an updated sanctions compliance program that ensures they do not inadvertently risk breach of the ongoing EU and US sanctions. These companies will need to also actively monitor Iran’s compliance as determined by the IAEA and the JCPOA Committee, as a breach may trigger a mandatory wind-down and withdrawal.

The same is not true with regard to the remaining US sanctions against Iran, for example, which would require approval by the US Congress. Moreover, critically, the JCPOA provides for UN, US and EU sanctions to “snapback.” This means that while many companies may now be allowed to invest in Iran, they will face the prospect of having to wind down their operations in the event that Iran is found to have breached the JCPOA[12].

“We note that other countries, including Canada, also continue to maintain sanctions against Iran that go beyond the limited sanctions imposed by the UN. To the extent there is any connection to such other countries in particular transactions, country-specific sanctions compliance advice should also be sought.”


[1]31 CFR Part 589.
[2]Executive Orders of the President of the US on “Blocking Property of Certain Persons Contributing to the Situation in Ukraine,” No 13660 dated 6 March, 2014 and No 13661 as of 19 March 2014 “Blocking Property of Additional Persons Contributing to the Situation in Ukraine,” Section 1, 19 December 2014. As a result of blocking sanctions, all property and interests of designated persons which are within (or may come into) the possession and control of any US individual or entity (which extends to a foreign branch of a US entity) are blocked, and an entry into the US of designated persons is suspended.
[3]Directive 4 under Executive Order 13662 of the Office of Foreign Assets Control as of 12 September 2014.
[4]The Council of the European Union, giving force to its Decision 2014/145/CFSP authorizing travel restrictions and the freezing of funds and economic resources of certain individuals believed to have been responsible for actions “which undermine or threaten the territorial integrity, sovereignty and independence of Ukraine“ (“designated individuals”), adopted Council Regulation (EU) No. 269/2014 of 17 March 2014.
[5]US and EU embargo Crimea, and US adopts new Ukraine sanctions law, 29 December 2014.
[6]The second phase of sanctions relief is eight years after “Adoption Day,” defined as 18 October 2015. See http://www.state.gov/secretary/remarks/2015/10/248311.htm
[7]Executive Order of the President of the US on “Blocking the Property and Suspending Entry Into the United States of Certain Persons With Respect to Grave Human Rights Abuses by the Governments of Iran and Syria via Information Technology” No. 13606 dated 22 April 2012.
[8]https://www.treasury.gov/resource-center/sanctions/OFAC-Enforcement/Pages/20161007_33.aspx
[9]Iran Freedom and Counter-Proliferation Act as of 2012, Section 1244(c)(1),(d).
[10]President Obama directs key US agencies to prepare for sanctions waivers under the JCPOA, 21 October 2015 and The Joint Comprehensive Plan of Action: A First Look, 17 July 2015.
[11]In the second step, on Transition Day, the EU will seek to terminate the sanctions suspended in the first step and terminate EU proliferation-related sanctions. As such, EU proliferation-related sanctions, among some other measures, will remain in place for eight years after Implementation Day.
[12]Special thanks to former Managing Associate of Dentons US LLP, Mr. Kenyon Weaver, for his contribution to this article.
Sanctions in Energy: Russia and Iran

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 October 2016

Conventional

  • October 3, 2016 – DualEx Energy International Inc. has entered into an Alberta oil and gas asset purchase and sale agreement, and has also entered into two private Alberta oil and gas company share purchase agreements.
  • October 3, 2016 – Journey Energy Inc. (“Journey”) announced the closing of the disposition of an aggregate of 16.36 million common shares and restricted voting shares in the capital of Journey by Infra-PSP Partners Inc. pursuant to a share purchase agreement dated September 15, 2016.
  • October 6, 2016 – Velvet Energy Ltd., a private oil and liquids-rich natural gas producer in the Deep Basin of Alberta, has completed a private placement of US$125 million of senior secured second lien notes due 2023.
  • October 7, 2016 – Devon Energy Corp. has completed the sale of its 50% ownership interest in Access Pipeline to Wolf Midstream Inc., a portfolio company of Canada Pension Plan Investment Board, for C$1.4 billion.
  • October 7, 2016 – Alberta Investment Management Corporation has successfully entered into a strategic financing relationship with Journey Energy Inc. Journey Energy Inc. has completed a private placement of an aggregate of 30,000 units to Alberta Investment Management Corporation at a price of $1,000 per unit for aggregate gross proceeds of $30 million.
  • October 11, 2016 – Canbriam Energy Inc. purchased the British Columbia assets of Northpoint Resources Ltd. through the court appointed receiver for cash consideration of $7.5 million.
  • October 12, 2016 – SemCAMS entered into a 15-year agreement with NuVista Energy Ltd. to proceed with building a project that will have the capacity to process up to 200 mmcf per day of raw sour gas and 20,000 bbls per day of condensate in the Wapiti area of Alberta.
  • October 18, 2016 – Suncor Energy Inc. and Mikisew Cree First Nation signed a participation agreement for the purchase by Mikisew Cree First Nation of a 14.7% interest in Suncor’s East Tank Farm Development. Under the terms of the agreement, Mikisew Cree First Nation will pay 14.7% of the actual capital cost of the East Tank Farm Development once the assets become operational, which is currently anticipated to be in the second quarter of 2017.
  • October 21, 2016 – Tourmaline Oil Corp. has entered into an agreement with Shell Canada Energy to acquire strategic assets in the Alberta Deep Basin and the northeast B.C. Montney Complex for total consideration of $1.369 billion (before customary adjustments) including cash consideration of $1 billion and the remainder in Tourmaline common shares.
  • October 24, 2016 – Logan International Inc., which manufactures and sells drilling and production tools, announced that it acquisition by Rubicon Oilfield International UK Acquisition Co Limited, a wholly-owned subsidiary of Rubicon Oilfield International Holdings, L.P., by way of an arrangement under the Business Corporations Act (Alberta), has been completed. All of the outstanding common shares of Logan International Inc. were acquired for $1.49 per share.
  • October 27, 2016 – Husky Energy Inc. closed several outstanding Western Canada asset sales, in line with its objective to build a more capital efficient business with reduced sustaining capital requirements. In aggregate, about 27,000 boe a day, including royalty interests, has been sold in 2016 for gross proceeds of $1.3 billion.
  • October 31, 2016 – Suncor Energy Inc. announced it has reached an agreement to sell its Petro-Canada Lubricants Inc. business to a subsidiary of HollyFrontier Corporation for $1.125 billion, subject to customary closing adjustments.
  • October 31, 2016 – RMP Energy Inc. announced this morning the transformational sale of its Ante Creek asset for cash consideration of $114.3 million, subject to normal and customary closing adjustments.
  • October 31, 2016 – Vertex Resource Group Ltd. announced it has acquired Red Giant Energy Services Ltd., an oilfield service company specializing in storage, management and logistics of oilfield fluids in the Western Canadian Sedimentary Basin.
  • October 31, 2016 – Lightstream Resources Ltd. announced that the first phase of the sale procedures under the Companies’ Creditors Arrangement Act, in which non-binding indications of interest were received and considered, has concluded and, accordingly, qualified bidders will move to the second phase of the sale procedures. The company also confirmed that its common shares were delisted from trading on the Toronto Stock Exchange on October 27, 2016.
  • General Electric Co. (“GE”) and Baker Hughes Inc. announced that the companies have entered into an agreement to combine GE’s oil and gas business and Baker Hughes to create an oilfield technology provider with service and equipment capabilities and $32 billion of combined revenue and operations in more than 120 countries.

Midstream

  • October 20, 2016 – AltaGas Ltd. announced that its board approved an investment decision for the construction, ownership and operation of the North Pine facility, to be located approximately 40 kilometres northwest of Fort St. John, B.C. AltaGas will be constructing the North Pine facility with two NGL separation trains each capable of processing up to 10,000 bbls per day of propane plus NGL mix (C3+), for a total of 20,000 bbls per day. Site preparation for the first NGL separation train is expected to begin in the first quarter of 2017, with an expected commercial onstream date in the second quarter of 2018. The second 10,000 bbl-per-day NGL separation train is expected to follow after completion of the first train.

 

Significant Developments in Canadian Energy – for the Month of October 2016

Ukraine’s Energy Efficiency Fund

Efficiency dilemma

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

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

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

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

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

Savings opportunity

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

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

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

Creating the Energy Efficiency Fund

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

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

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

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

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

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

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

Ukraine’s Energy Efficiency Fund

Iran Issues Pre-qualification for Upstream Tenders

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

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

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

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

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

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

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

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

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Iran Issues Pre-qualification for Upstream Tenders

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

Aviation emissions – new global deal looks likely

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

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Aviation emissions – new global deal looks likely