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

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

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

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

The story so far

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

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

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

What is in the Winter Package?

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

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

The Revised IMED

Overall impressions

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

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

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

A market for consumers (and prosumers)

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

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

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

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

Active consumers are to be:

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

Local energy communities:

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

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

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

DSOs (and EVs)

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

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

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

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

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

The Revised Market Regulation

General organisation of the electricity market

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

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

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

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

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

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

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

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

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

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

Institutions

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

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

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

The Revised RED

Target for 2030

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

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

Power (plus)

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

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

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

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

Heat, cooling and transport

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

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

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

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

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

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

Biomass

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

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

The Governance Regulation

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

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

In outline, the Regulation works as follows.

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

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

The Risk Regulation

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

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

The ACER Regulation

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

The Innovation Communication

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

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

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

Energy Efficiency

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

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

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

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

Brexit

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

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

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

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

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

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

Provisional conclusions

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

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

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

UK electricity interconnectors: all coming together (by about 2020)?

One of the problems faced by the UK in achieving security of electricity supply at an affordable cost is its comparatively low level of interconnection with the electricity networks in other countries.  But recent developments offer some prospect that the UK may become a bit less of a “power island”.

The EU’s goal of a single electricity market has the potential to help national Governments with all three horns of the energy trilemma (how to maintain security and decarbonise whilst keeping energy prices at a reasonable level).  But it cannot be realised without adequate interconnection capacity.  As long ago as 2002, the European Council set EU Member States a target of having electricity interconnections equivalent to at least 10% of their installed production capacity by 2005.  Twelve years on, the UK is only half way to meeting this target.  In May 2014, as part of its work on European energy security, the European Commission proposed an interconnection target of 15% for 2030.  This was adopted by the European Council in its 23 October 2014 conclusions on the EU’s 2030 Climate and Energy Policy Framework.

Meanwhile, as Member States connect increasing amounts of intermittent renewable generating capacity to their networks, leaving them in some cases with total generating capacity that is much greater than the amount of power they can reliably generate at any given moment, the goal of achieving 10% or 15% of total installed generating capacity becomes more challenging (see the statistics and charts below).  While such targets are undoubtedly useful, the optimum proportion of interconnection capacity is not the same for each Member State and is bound to change over time with the evolution of its generating mix and electricity consumption profile.  However, it is not always easy for the market to respond quickly and produce more interconnection capacity where it is most needed given the amounts of capital and the regulatory processes involved.

Achieving an interconnection target of 10% or 15% of installed generating capacity in the UK is particularly challenging.  Even before it began to add significant amounts of renewable generation, the UK had one of the larger generation capacities in the EU, and it is very much more expensive per MW to create connections between the electricity networks of Great Britain and other EU Member States than it is to connect networks between Member States which share a land border.  The costs per km of a subsea cable connection are several times greater than those of an overhead transmission line, and the distances involved in GB interconnectors tend to be larger than those which link the transmission systems of different countries in Continental Europe.

However, if the costs of interconnection are significant, so too are the potential benefits for UK consumers.  In a paper entitled Getting more connected published earlier this year, National Grid estimated that: “each 1GW of new interconnector capacity could reduce Britain’s wholesale power prices up to 1-2%…4-5GW of new links built to mainland Europe could unlock up to £1 billion of benefits to energy consumers per year“.  As the European Commission’s most recent report on energy prices and costs in Europe notes, in some of the countries to which the GB system either is not yet connected or with which it could be much more interconnected, average baseload wholesale electricity prices are up to 40% lower than those in the UK.

So is the potential for new UK interconnection capacity going to be exploited anytime soon?  There are encouraging signs both from a regulatory point of view and in terms of actual projects.

The regulatory treatment of projects is crucial to the development of more interconnection.  In this respect, there have been a number of helpful recent developments for potential UK interconnectors.

  • In August 2014 Ofgem confirmed its intention to implement, with only minor modifications, its previously consulted-on proposals for the regime that will apply to the regulation of near term GB interconnector projects (i.e. those expecting to be commissioned by the end of 2020 and likely to be taking significant investment decisions in 2015).  Ofgem recognises that if the development of new UK interconnection capacity is left to proceed without any form of regulated “consumer underwriting”, it is likely that insufficient new capacity will be built.  It therefore proposes a 25 year regulatory regime of a “cap and floor” on revenues, based on its assessment of the need case and efficient level of costs for projects.  The new regime, building on Ofgem’s approach to the Project Nemo interconnector, aims to combine advantages of both the traditional regulated revenue model and more purely market-based approaches.  Ofgem’s 27 October 2014 consultation on the Caithness Moray transmission project shows how far a regulator’s assessment of efficient costs for a project involving subsea cables can vary from a developer’s estimates.
  • Also in August 2014 the UK Government published a paper entitled Contract for Difference for non-UK Renewable Electricity Projects.  This raises the prospect of Contracts for Difference (CfDs) under the Energy Act 2013 being competed for by and awarded to renewable electricity generating projects outside the UK by 2018.  This is a significant step, given the continuing importance of subsidies for the renewables sector (and coming as it did shortly after the approval by the Court of Justice of EU Member States’ historic tendency not to extend their national renewables support schemes to generators in other Member States – notwithstanding the potential for such restrictions to impede free movement in the single market for electricity).
  • In September 2014, the Government included in a consultation on supplementary design proposals for the Capacity Market established by the Energy Act 2013 an outline of how interconnector owners could participate in future Capacity Market auctions.  This had been promised in the context of obtaining state aid clearance, so as to ensure that the Capacity Market, like similar measures being put in place by other Member States, does not militate against the integration of national markets – clearly a matter of concern to the European Commission.
  • Interconnection is most effective when the interconnector capacity is allocated most efficiently and facilitates the flow of electricity from areas of lower to areas of higher prices (see study on this).  These outcomes should be brought closer by the progress there has been in integrating EU national electricity markets through the Target Model.  In February 2014, the markets in GB and 14 other EU Member States became part of the day-ahead price coupling regime for North-West Europe (and in May 2014 they were joined by Spain and Portugal).  In April 2014, a number of Central European Transmission System Operators, National Regulatory Authorities and Power Exchanges signed an MoU to develop flow-based market coupling, which in time will enable better calculation of the network capacities that are allocated through the price coupling process.
  • Finally, the 2013 EU Regulation on cross-border infrastructure (“projects of common interest” or “PCIs”, which are to be fast-tracked through national consenting processes) should make it easier to get interconnection projects funded and built.

In terms of actual projects, Ofgem’s October 2014 preliminary decision on eligibility of projects to benefit from the cap and floor regime identifies five projects that aim to commission by 2020 and, having come forward in the first cap and floor application window, have been judged sufficiently mature to proceed to the three to six month initial project assessment stage.

The five projects are: FAB Link between GB and France; Greenlink, between GB and the Republic of Ireland; IFA2, between GB and France; NSN, between GB and Norway (recently granted a licence by the Norwegian Government); and Viking Link, between GB and Denmark.

According to Ofgem, these projects, together with Project Nemo and the Channel Tunnel-based ElecLink, could add up to 7.5GW of interconnection – more than doubling existing GB cross-border apacity.  They have a number of points in common.   A number of these projects feature in the ENTSO-E Ten Year Network Development Plan and the European Commission’s list of PCIs.  Most of them involve the Transmission System Operators of one or both of the countries they would run between or companies affiliated to them.  Establishing links between GB consumers and renewable generation outside GB is an important part of the rationale for many of them (the FAB Link project even involves plans for up to 300MW of electricity generated from the tides around Alderney). Recent publicity for the TuNur project to export large amounts of solar-generated electricity from North Africa to Europe, including the UK, shows the scale of the possibilities in this area.

It now remains to be seen whether the further development of the Government’s proposals on non-UK renewable and interconnected capacity – and perhaps more significantly the outcomes of the first CfD and Capacity Market auctions (which will not be open to interconnected / non-UK capacity) – will enhance or detract from the business case for these projects.

 

Illustrative statistics and charts (drawn from EU Energy in Figures: Statistical Pocketbook for 2014 and other European Commission and ENTSO-E publications)

1. Ratio of available cross-border electricity interconnector capacities compared to domestic installed power generation capacities

Source: Ten Year Electricity Network Development Plan, 2012

Source: Ten Year Electricity Network Development Plan, 2012

2. Electricity generation across EU Member States

Table 4_2

3. EU Member States’ power generation supluses and deficits compared to gross inland consumption in Q1 2013 and 2014

figure 2

4. Electricity consumption across EU Member States in Q1 2013 and 2014

consumption

5. EU Member States’ renewable and non-renewable generation

Table 6

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UK electricity interconnectors: all coming together (by about 2020)?

State aid for Hinkley Point C (3): What hope for “no aid” arguments?

This post is the third in a series on the European Commission’s initial assessment of the package of measures by which the UK Government proposes to provide financial support for the proposed new nuclear generating station at Hinkley Point (HPC) by NNB Generation Company Limited (NNBG).  In this post we focus on the Commission’s analysis of the UK Government’s arguments that its support for HPC does not constitute state aid within the meaning of Article 107(1) of the Treaty on the Functioning of the European Union and that HPC would be performing a service of general economic interest (SGEI), effectively meaning that it fell outside the state aid rules (for a summary of the overall framework of the Commission’s appraisal, click here).

As noted in the previous post, any “no aid” decision, or categorisation of the HPC as an SGEI, effectively turns on the application of the so-called Altmark criteria.  The quality of the Commission’s arguments in this strategically important area is variable. 

The Commission begins by making the point that it sees a service of general economic interest (SGEI), such as the Government claims would be provided by NNBG, as a service which an undertaking would not supply if it were considering its own commercial interest, and which serves a general economic interest.  In the context of HPC, the Commission’s starting point is that NNBG’s service would be to supply (baseload) electricity; yet that, the Commission says, is “normally considered a commercial activity and a market in which competition takes place”.  It suggests that nuclear generation is no exception to this principle, noting the “nuclear plants which are operated commercially” in the UK by NNBG’s parent EDF, and the “UK’s own assessment” that “private investors [would]…invest in nuclear energy in the UK by 2030 at the latest.  Finally, if the service which would not be provided without aid is the construction of HPC by an earlier date than the private sector would otherwise build new nuclear capacity, the Commission suggests that the UK has not made a convincing case for such early construction being in the general economic interest on security of supply or decarbonisation grounds.  

Almost every assertion that the Commission makes in the two pages or so which it takes to reach these provisional conclusions on “the existence of a SGEI” is questionable in terms of its accuracy or its relevance.  Electricity generation is indeed a commercial activity.  That does not mean that the construction of a new nuclear reactor is a service that will be provided without state aid.  Nor does the existence of the UK’s legacy nuclear fleet help the Commission’s case, constructed as it was by the CEGB in the days of nationalisation.  The Commission’s dismissal of security of supply and decarbonisation as interests served by the putative service of constructing and operating HPC is similarly one-sided.  For example, it effectively denies that there is any benefit in securing decarbonisation sooner if you think the market will decarbonise a few years later, and it ignores the effects on both security of supply and decarbonisation in both the longer and the shorter term which assurance about the viability of HPC (in the form of state aid clearance) could have.

The first Altmark criterion (which is also key to any attempt to justify a measure under Article 106(2)) is that the beneficiary be entrusted with a public service obligation (PSO).   The Commission argues that provisions of the CfD which limit the return which NNBG can make on its investment in HPC or penalise it for late delivery of the project are not capable of being PSOs.  The best claim that the CfD has to being regarded as placing NNBG under an obligation is that if it does not build HPC (or delivers it late), it will receive no money (or less money) under the CfD.  The Commission appears to be suggesting that in order to be a PSO, an obligation (e.g. to commission HPC by a certain date) has to be “enforceable” by some means other than the payment or non-payment of aid.  If the Commission is right about this, it may have implications for the design of the CfD contract terms more generally.  However, the Commission only engages very briefly with the case of Fred Olsen, which appears to offer some support to the UK Government’s view.  In that case, which concerned ferry services, the Court of First Instance remarked that the fact that an operator “unilaterally abandoned or altered the conditions for the operation of some maritime routes indicates at most” that it “failed to honour some of the obligations imposed on it by the provisional arrangements”, and seems to have found that not even the fact that an operator was subsidised at its own request prevented it from satisfying the first criterion.   

Looking beyond the particular circumstances of HPC, what the Commission seems to be saying here could have implications for the financing of other CfD-subsidised schemes.  If the Altmark criteria do truly require the state to have the means of enforcing compliance with requirements, such as the construction of HPC, that go beyond the stimulus provided by the absence of CfD revenues if no electricity is generated, it may not be possible to construct bankable CfDs which satisfy those criteria.  Elsewhere, in the analysis of Article 106(2) arguments, the Commission suggests that the absence of a true PSO is what excuses the UK from having to comply with the public procurement rules in respect of letting a CfD in respect of HPC, and that, conversely, if the requirements imposed on NNBG could be shown to constitute a PSO, the UK Government would have failed in its alleged obligation to follow the public procurement rules.

The Commission broadly accepts that the second Altmark criterion is satisfied – i.e. that the parameters on the basis of which the compensation is calculated are established in advance in an objective and transparent manner.  However, when it comes to the third criterion, that the compensation cannot exceed what is necessary to cover the costs incurred in the discharge of the PSO, its assessment is much less favourable.  Moreover, some of the arguments which emerge here also read across into the Article 106(2) and Article 107(3) analysis.

The Commission is concerned, firstly, that the Government does not appear to have a firm view of what the costs of discharging the PSO are (making the level of compensation by definition hard to assess); secondly, that the level of profit that NNBG can expect to earn over the lifetime of the CfD was negotiated with NNBG rather than being “established by reference to the rate of return on capital that would be required by a typical undertaking considering whether or not to provide the alleged SGEI”; and thirdly, that because the 35 year lifetime of the CfD is shorter than the 60 year lifetime of HPC, NNBG could earn super-normal profits in years 36 to 60. 

It is hard to comment on the first two of these points as far as HPC is concerned without access to the UK’s submissions to the Commission, although in response to the second one might ask: what is a “typical undertaking” considering whether or not to build HPC, let alone (as the Commission goes on to elaborate) “the average cost structure of efficient and comparable undertakings in the sector under consideration” – none of which have been built under exactly the same regulatory regimes as HPC would be built and operate under?  Moreover, for much of the period during which the Government was negotiating with NNBG, it was simply the only undertaking willing to contemplate any form of investment in new nuclear build in the UK.  On the other hand, prospective recipients of aid under enduring CfD regime for renewables in mind regime may take some comfort in this context from the fact that their strike prices will not be the result of bilateral negotiations. 

But the Commission’s point about the duration of the comparative lifetimes of the CfD and the generating station is something on which we can comment in the HPC context.  The strike price, we are told, has been set at a level which is designed to ensure that NNBG covers the costs of construction and operation and makes a return of 9.87% on the project as a whole over its lifetime (in post-tax, nominal terms).  Yet, as the Commission points out, once the CfD expires, the profitability of the plant is uncertain because the level of revenue accruing to the operator from the sale of electricity is no longer controlled by the strike price mechanism.  This makes it harder for the Commission to rule out the possibility of overcompensation during the post-CfD period of the plant’s operation.  The Commission suggests two ways of dealing with this problem: making the CfD coterminous with the life of the plant, or providing some means for the state to recover any overcompensation within the CfD itself (effectively a gain-share provision for the period when the strike price mechanism no longer applies).  One problem with the first of these, if taken in isolation, is that it is not possible to predict the lifetime of a plant with certainty when the strike price is initially calculated.  

In principle, it would seem that this arguments is not unique to the case of HPC and could be applied to the wider CfD regime.  The differences are that the periods of time involved – both CfD durations and plant lifetimes – are shorter for non-nuclear projects, so that the calculations are less dependent on very long range predictions of electricity prices; and that there is more comparative data on which to assess technology costs.  Whether the Commission will consider these differences to be sufficient for it to take a more favourable view of this aspect of the wider CfD regime than it has so far in the case of the HPC package remains to be seen.  In this context it is curious that the Commission states that “nuclear production, which requires very high levels of capital for the investment in the construction and hence before revenues can be generated, while also being characterised by a relatively low level of operating costs once the plant has been built, has few, if any, equivalents in commercial activities”: the CfD regime as a whole is surely predicated on the assumption that all the technologies it covers (renewable, nuclear, CCS) have in this sense a similar cost profile.

The fourth Altmark criterion is that where the undertaking which is to discharge a PSO is not chosen through a public procurement process, the level of compensation must be determined on the basis of an analysis of the costs which a typical, well run, undertaking would have incurred.  Here again, the problem is in finding the appropriate comparator.  Unsurprisingly, the Government has commissioned a review of NNBG’s cost estimates to determine whether they are “reasonable”.  The Commission says that this is not what the Altmark criterion requires.

The final sections of the Commission’s analysis of the UK’s “no aid” arguments deal with the credit guarantee and the proposal to compensate NNBG in the event of a “political shutdown” of HPC.  On the credit guarantee, the Commission essentially reserves judgment owing to the lack of detail available.  However,  it does lay down a marker when it observes that the guarantee “seems to differ from ordinary debt guarantees in that it would be drawn before equity, apart from equity already spent…It would therefore appear that [it] might diminish the risks borne by equity holders”.  The Commission appears prepared at this stage to accept the UK’s argument that political shutdown proposals do not constitute state aid, subject to the provision of more information “on whether this compensation…would also be available to other market operators placed in a similar situation”.  This is intriguing.  It is presumably possible that the UK Government would be prepared to offer a similar deal on political shutdown to another nuclear operator, but such a deal is clearly not on the table for operators of renewable technologies, for example, and whilst a political shutdown of UK wind farms may be a more remote possibility than something like the German reaction to Fukushima, will that point be sufficient to satisfy the Commission that the enduring regime for renewables should not in this respect be “levelled up”, to confer on its beneficiaries the additional protection offered to NNBG?

It is clear that the Commission is highly reluctant to reach a finding that there is “no aid” in the HPC package, or to find that there is an SGEI within the meaning of Article 106(2).  It does not want to treat nuclear power as a special case.  Yet unless it is prepared to recognise that nuclear power is not just another source of baseload electricity, how could the Commission find that there is no aid (or that there is a SGEI) in a CfD negotiated directly between a Government and the beneficiary undertaking which includes a generous strike price, a 35 year term and investor protection in the event of political shutdown – and still realise its ambition of cutting back on subsidies for renewables? 

To go by the evidence of the Commission’s initial assessment, the Government would – rightly or wrongly – have to do a lot more work both in terms of scheme design (including changing some features of the currently proposed CfD arrangements) and in terms of arguing its corner with the Commission if it is to persuade the Commission that there is “no aid” to NNBG.  It is possible that the Court of Justice might be more sympathetic to the Government on some of these points, but EU litigation would not help the timeliness of the delivery of EMR objectives.

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State aid for Hinkley Point C (3): What hope for “no aid” arguments?

State aid for Hinkley Point C (2): Outline of the Commission’s analysis

This is the second in a series of posts on the European Commission’s initial assessment of the package of measures by which the UK Government proposes to provide financial support for the proposed new nuclear generating station at Hinkley Point (HPC): click here for the first in the series.  The text of Commission’s letter is now also available in the Official Journal of the European Union: interested parties have one month from the date of its publication (7 March 2014) to comment.   

In this post we summarise the Commission’s analysis of the HPC support package.  This consists chiefly of a proposed Contract for Difference (CfD) and a credit guarantee conferred by participation in HM Treasury’s UK Guarantees Scheme: both are conveniently summarised in the opening paragraphs of the Official Journal notice.

Introduction: the state aid rules

It is worth beginning by reminding ourselves of the key EU Treaty provisions on state aid.  Article 107 of the Treaty on the Functioning of the European Union (TFEU) states:

1. Save as otherwise provided in the Treaties, any aid granted by a Member State or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain undertakings or the production of certain goods shall, in so far as it affects trade between Member States, be incompatible with the internal market.

Article 107(2) then lists certain types of aid which fall within Article 107(1) but which “shall” be considered compatible with the internal market.  These relate to aid having a social character or relating to natural disasters, economic crises or German unification and can therefore be disregarded for present purposes.  Article 107(3) contains a further list of types of aid which “may” be considered compatible with the internal market.  Article 108(2) and (3) TFEU state:

2. If, after giving notice to the parties concerned to submit their comments, the Commission finds that aid granted by a State or through State resources is not compatible with the internal market having regard to Article 107, or that such aid is being misused, it shall decide that the State concerned shall abolish or alter such aid within a period of time to be determined by the Commission.

If the State concerned does not comply with this decision within the prescribed time, the Commission or any other interested State may, in derogation from the provisions of Articles 258 and 259, refer the matter to the Court of Justice of the European Union direct…

3. The Commission shall be informed, in sufficient time to enable it to submit its comments, of any plans to grant or alter aid. If it considers that any such plan is not compatible with the internal market having regard to Article 107, it shall without delay initiate the procedure provided for in paragraph 2. The Member State concerned shall not put its proposed measures into effect until this procedure has resulted in a final decision.

Secondary legislation has established an administrative framework for dealing with state aid cases (for further detail, click here).  Measures that are put into effect without having been notified and approved under Article 108(3) are “unlawful aid”.  If the Commission finds unlawful aid is incompatible with the internal market, it may require Member States to recover it from the beneficiaries.

To gain the Commission’s approval for the HPC package, the UK Government must therefore persuade the Commission either that its support for HPC does not constitute state aid within the meaning of Article 107(1), or that such support is compatible with the internal market.  The Government has identified three possible ways to avoid a finding of incompatibility, as set out below.

The “no aid” arguments

Any claim that a measure does not constitute state aid depends on showing that one of the elements of aid set out in Article 107(1) – state origin of the aid, conferral of a “selective advantage”, impacts on intra-EU trade and competition – is not present.  We take each of these in turn below as they have been applied to the HPC support package.

  • Apparently, the UK authorities “do not contest” that the CfD is financed from resources under the control of the state.  The Commission points out that the CfD will be administered by a Counterparty body essentially controlled, and potentially underwritten, by the Secretary of State.
  • As regards distortion of competition and an effect on intra-EU trade, the Commission observes: “As in this case the notified measures will enable the development of a large level of capacity which might otherwise have been the object of private investment by other market operators using alternative technologies from either the UK or other Member States, the notified measures can affect trade between Member States and distort competition.”.
  • That leaves as the key battleground the question of whether the support package confers a “selective advantage” on HPC.  Would HPC be getting a deal that will give it an advantage in the market and that is not open to its competitors?  In order to show that this element of the definition of aid is made out, the Commission has to engage with the criteria laid down by the Court of Justice in the case of Altmark.  In that case, the Court found that in certain circumstances compensation provided to undertakings entrusted with a public service function would not constitute state aid.  The Commission considers the Altmark criteria (discussed in the Commission’s 2012 Communication on compensation for the provision of services of general economic interest (SGEI)) in some detail.  Overall, the Commission finds it hard to see that HPC would be entrusted with the kind of public service obligation (PSO) that the Altmark criteria envisage.  It also inclines to the view that the compensation which HPC stands to receive under the CfD would be more than the Altmark criteria permit. 

The “aid is compatible” arguments

The Government argues that if the HPC package is considered to be state aid, its contribution to the common EU objectives of decarbonisation, security of supply and diversity of electricity generation, and addressing related market failures, outweighs its negative impact on the internal market.  The Commission is not persuaded by these arguments in favour of a finding of compatibility under Article 107(3).  For example, it is sceptical of claims about decarbonisation on the basis that support for HPC could crowd out investment in other low carbon technologies; and it queries claims about security of supply on the grounds that the most immediate concerns about the adequacy of the UK’s electricity generation capacity relate to the current decade, not the 2020s when HPC would be commissioned.

But the Commission’s scepticism about the objectives of the HPC support package is only the beginning of its concerns from an Article 107(3) point of view.  Even if it were prepared to accept that the HPC package is aligned with one of the “common EU objectives”, the Commission queries whether state aid – in the combined form of the proposed CfD and credit guarantee – is needed to enable HPC to achieve these objectives.  Overall, the Commission suspects that the level of protection from ordinary market risks which the support package provides is excessive: more or less every aspect of the package, from the duration of the CfD to the way in which it has been negotiated, is viewed in sceptical terms, so that the Commission concludes by saying that it doubts “whether it effectively addresses a market failure”; questions “whether [it] can be deemed…to be proportionate”; and is “concerned about its distortive effects on competition”.

A “service of general economic interest”?

In between the “no aid” and “compatible aid” limbs of its case, the Government argues that the HPC package with the internal market, fulfils the conditions of the Framework which the Commission has put in place for determining whether larger SGEI schemes fall within Article 106(2) TFEU.   Article 106(2) states:

2. Undertakings entrusted with the operation of services of general economic interest or having the character of a revenue-producing monopoly shall be subject to the rules contained in the Treaties, in particular to the rules on competition, in so far as the application of such rules does not obstruct the performance, in law or in fact, of the particular tasks assigned to them. The development of trade must not be affected to such an extent as would be contrary to the interests of the Union.

Article 106(2) is in some ways the ultimate derogation provision.  It says, in effect, that certain undertakings will be exempt from the requirements of EU competition and state aid law if the application of that law would “obstruct the performance” of a service of general economic interest entrusted to a particular undertaking.  The meaning of Article 106(2) has therefore been the subject of many arguments between the Commission and Member States.

The Commission has, for example, argued that Article 106(2) “authorizes measures contrary to the Treaty only to the extent to which they are necessary to enable the undertaking concerned to perform its task of general economic interest under acceptable economic conditions and, therefore, only if they are necessary for the financial equilibrium of the undertaking itself”.  But the Court of Justice, whilst acknowledging that Article 106(2), like all derogations, must be interpreted strictly, has found that it “seeks to reconcile the Member States’ interest in using certain undertakings, in particular in the public sector, as an instrument of economic or fiscal policy with the Community’s interest in ensuring compliance with the rules on competition and the preservation of the unity of the common market”.  Moreover, Member States “cannot be precluded, when defining the services of general economic interest which they entrust to certain undertakings, from taking account of objectives pertaining to their national policy or from endeavouring to attain them by means of obligations and constraints which they impose on such undertakings”.  As a result, “for the Treaty rules not to be applicable to an undertaking entrusted with a service of general economic interest under Article 90(2) of the Treaty, it is sufficient that the application of those rules obstruct the performance, in law or in fact, of the special obligations incumbent upon that undertaking. It is not necessary that the survival of the undertaking itself be threatened”.  (See Case C-157/94, Commission v Netherlands.)

                                                   

                                                A service of general economic interest

The Commission’s analysis in response to the UK’s SGEI arguments overlaps to a large extent with what it says in relation to the Altmark criteria and/or the Government’s Article 107(3) arguments.  It concludes that the Commission doubts whether the HPC package qualifies as an SGEI within the meaning of Article 106(2) and the Framework, and that even if it did so qualify the Commission doubts that it would comply with the Framework.

Overall characteristics of the Commission’s analysis

In future posts we will examine some of the Commission’s arguments in more detail.  For now, it is worth noting some more general features of the Commission’s appraisal.

  • There is a degree of unevenness about the Commission’s analysis.  It makes some extremely good points and some decidedly weak ones. 
  • There are a number of points when the Commission appears to help the UK by indicating possible ways of correcting what it sees as deficiencies in the HPC package in state aid terms.  Whether these potential “escape routes” are in practice open to the UK Government is another matter.
  • The Commission – intentionally or otherwise – draws attention to a number of places where the HPC package is different from the rest of the CfD regime (or at least the enduring regime for renewables).  Sometimes this is to the latter’s advantage, but not always.  In an ideal world, the whole of the CfD regime would have been worked out in full before being notified together, but it so happens that the first part of the regime that the Commission examines in detail is not entirely typical or representative of the regime as a whole.
  • Inevitably, much of the analysis is somewhat tentative, because details of almost all parts of the package still remain to be fully worked out.

Behind everything lurks the question: how much (or how little) freedom do the EU state aid rules allow Member States to have as regards ensuring that a certain proportion of their electricity generating capacity belongs to a specified technology type? 

 

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State aid for Hinkley Point C (2): Outline of the Commission’s analysis

State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013

On 18 December 2013, the European Commission announced that it was opening an in-depth state aid investigation into the Government’s package of financial support for the proposed Hinkley Point C (HPC) new nuclear generating station.  On 31 January 2014 the Commission published a version of the letter setting out its reasons for launching a detailed investigation and the points on which it requires to be persuaded of before giving state aid clearance to the package.

What does the letter tell us?  It is a fairly closely-argued 67 pages, so it will take more than one post to cover it.  Today, we begin by setting the scene. 

The potential of HPC – an image from gov.uk

The critical tone of parts of the Commission’s analysis has been noted in a number of reports, but this is perhaps not the most surprising feature of the letter if one considers its context.

  • The package of support for HPC inevitably treats new nuclear as to some extent a “special case”.  State aid policy is administered on the principle that free markets are best and that claims that a particular industry is somehow “special” are to be treated with scepticism – even if that industry is one in which there is already massive state intervention in various forms. 
  • The European Commission’s decision-making on state aid cases has sometimes been criticised for being too politically expedient.  Here we have a case where the UK Government has invested huge political capital and the aid is going to a subsidiary of a company 84% owned by the French state.  Even if the Commission is ultimately minded to approve the HPC support package it cannot afford to be seen to have given it anything less than an economically rigorous evaluation.
  • In 2007, the Commission ruled on alleged state aid for the Olkiluoto 3 nuclear plant, to be built in Finland with French technology.  The issue was whether a guarantee given by the French state gave Areva an unfair competitive advantage over other potential suppliers.  The guarantee was found to have been given on market terms, so that there was no aid under the state aid rules.  However, the proceedings still lasted three years and the Commission went through an in-depth investigation before reaching a final decision. 
  • In 2006, the Commission approved the arrangements for setting up the Nuclear Decommissioning Authority (NDA).  Although the Commission acknowledged that the purposes behind the creation of the NDA were fully in line with the objectives of the Euratom Treaty, it was also very concerned about potential distortions of competition arising from it.  For example, notably tight controls were set on the pricing of electricity sold by the UK’s Magnox nuclear plants, to be run by the NDA, for the few remaining years of their life.
  • Most recently, the Commission decided that aid granted by Slovakia in relation to nuclear decommissioning was compatible with the state aid rules.  In doing so, the Commission emphasised that the aid related to plants that had already been shut down; that it did not subsidize current electricity production; and that it was “strictly limited to what is necessary to cover the costs of decommissioning historic nuclear facilities, for which no adequate provisions were created in the times of a centrally-planned economy”.  Moreover, the Slovak scheme was unlike “the numerous schemes of compensation for stranded costs, public service obligations and support schemes for renewable electricity, where the Commission has found that the financing of the support scheme through a levy has a protective effect of national electricity production”.
  • The HPC support package is the kind of arrangement that is intrinsically harder for the Commission to get itself comfortable with than the Okiluoto or NDA measures.  It explicitly and intentionally provides, under the Contract for Difference (CfD) mechanism, a guaranteed level of price for electricity and therefore a degree of revenue security which the market would not provide.  It can therefore be characterised as “operating aid” (as opposed to “investment aid”), which the state aid regime regards as particularly problematic – since it shields operating businesses from normal market risks.
  • Although there is an entire EU Treaty devoted to the promotion of nuclear power, it is politically controversial within the EU, and there are those who will take any opportunity to put the case, whether in administrative or judicial proceedings, against the adoption or approval of any measure that brings a “nuclear renaissance” in the EU closer.
  • There are undoubtedly some features of the support package for HPC which, at least at first sight and taken in isolation, appear very generous.
  • The Commission is in the process of “modernising” the state aid framework and has just published draft Guidelines on environmental and energy aid.  The Guidelines do not cover nuclear projects, but take a notably tough line on e.g. support for renewables, even though the deployment of renewables is mandated by EU law in a way that nuclear power is not.  Anything other than a searching approach to scrutiny of the HPC package would be out of keeping with the general thrust of current Commission policy in this area.
  • Whatever the ultimate outcome of the Commission’s evaluation of the HPC support package, the final decision can only be robust against potential challenge if it has clearly stated the potential objections to what the UK Government is proposing.

The UK public may have been encouraged to think that the hard part of HPC was over once development consent, a nuclear site licence, marine licence and other environmental permits were granted, and agreement on the strike price had been reached.  But obtaining state aid clearance in this case was always going to be a challenge.  And for all sorts of reasons, it is not surprising if at this stage the Commission has stated the “case for the prosecution” in clear and strongly worded terms.  In future posts, we will examine some of the Commission’s arguments a little more closely, consider the possible outcomes of the Commission’s investigation into the HPC support package, and look at what the Commission’s letter indicates about the prospects for state aid clearance of the rest of the Electricity Market Reform (EMR) package.

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State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013

Coal still counts (2): decision time for generators (or it will be soon)

In a previous post we looked at how the UK’s existing fleet of coal-fired plant had been saved from being made subject to the “emissions performance standard” or EPS under the Energy Act 2013 provisions for Electricity Market Reform (EMR).  This happened when the Government reversed an amendment that would have applied the EPS to existing coal-fired plant if its operators were to choose to keep it running in the long term by fitting the equipment necessary for it to comply with the new limits on emissions (in particular of NOx) that will apply to it from 2016 under the Industrial Emissions Directive (IED).  In this post, we explore the choice which operators have to make under the IED – and why the Government may have thought it worth keeping them out of the EPS. 

Existing plant faces a choice under IED.  In broad terms, it must either upgrade to meet the new emission limits, or run for a limited number of hours – for example, by opting for the “limited life derogation” (LLD).  The LLD allows plant to run in its current form for 17,500 hours before closing no later than 2023.  Subjecting existing coal-fired plant to the EPS if and when it upgraded to comply with IED NOx limits would have made it likely that its operators would opt for the LLD rather than upgrading, and at the load factors at which UK coal plant has been operating recently, most plants would probably burn through their 17,500 hours by 2020, if not before.

Why should that worry us?  Wouldn’t it just be another example of EU legislation that isn’t about climate change being more effective at tackling CO2 emissions than the EU Emissions Trading System?  (Most UK coal plant closures to date have been driven by the Large Combustion Plants Directive, which the IED replaces, and which was designed to combat effects such as acid rain rather than “global warming”.)  To understand why the Government was so keen to keep existing coal plant out of the EPS, we have to look at the work it is doing in the generating mix. 

In 2012, the UK’s total combined cycle gas turbine (CCGT) capacity (35.57GW) exceeded its total coal and oil-fired “conventional steam” generating capacity (30.97GW) for the first time.  But that same year, gas’s share of electricity generation fell from 40% (in 2011) to 28% and coal’s rose from 30% to 39%.  (Greenhouse gas emissions from the UK energy supply sector increased by almost 6 per cent as a result.)  Coal’s high share of UK generation persisted, and appears to have increased slightly, in 2013. 

Why is this?  Coal-fired power over this period has simply been cheaper than gas-fired power (partly because the availability of shale gas has hit US coal prices).  It can keep the lights on at lower cost.

Much of our coal-fired electricity comes from just 10 coal-fired plants, with a combined capacity of over 18 GW – about a fifth of generating capacity connected to the grid.  Now that the 1 January 2014 deadline for indicating their operators’ intentions as regards the LLD has passed, and with the threat of EPS removed, we might expect that there would be some clarity as regards their future, but in fact there is still a degree of uncertainty about most of them.

  • The future plans of three (Drax, Eggborough and Rugeley, together representing some 6.8GW of capacity, and all owned by generators who are not in the “Big 6”) appear to depend in part on plans to convert to burning biomass.  The success of these plans is likely to depend on whether they are allocated EMR Contracts for Difference (CfDs), and meet the conditions for those CfDs to take effect (more on all this in a later post).
  • One (E.ON’s Ratcliffe, 2GW) appears fully prepared for IED compliance.  Another (SSE’s Fiddler’s Ferry, just under 2GW) has development consent to fit the necessary equipment.  A third (Scottish Power’s Longannet, 2.3GW) is testing new technology to comply with IED.
  • The operators of four of them (Aberthaw, Cottam, Ferrybridge and West Burton, representing together some 7.5GW) have provisionally decided not to invest in the equipment necessary to comply with the IED.  Instead, EDF, RWE and SSE have said they plan to use the LLD. 

The story is clearly not over.  EDF, RWE and SSE have all indicated that they may still choose to upgrade some of their plants to IED standards.  So their choice of the LLD may be more about keeping their options open than representing their preferred long-term option for these four plants.  RWE commented: “Only after we have political clarity on how the energy market will operate under the Government’s new energy legislation as well as any other political changes to be enacted, will we be able to make [a] final decision with confidence.”.

The reference to the uncertainties still surrounding a number of aspects of  EMR reminds us that some existing plant may be looking to the EMR capacity market as a means of funding investment in IED compliance.  More on how the capacity market may work for coal and other types of plant in further posts.  For the moment, though, note two more points.  First, if operators wish to revisit their decision to choose the LLD and opt back in to the IED, they will be relying on, and will need to fit in with, the UK’s Transitional National Plan (TNP).  The TNP permits plants to ease in to IED compliance by 2020 rather than 2016.  But the UK’s TNP has so far not been approved by the European Commission as required by the IED.  Second, according to Defra, RWE, EDF and SSE do not have to reach a final decision on IED until the end of 2015.  This may be a very convenient deadline, since it comes after the next election, when operators will know whether Labour’s ambitious “Green Paper” proposals for further market reform are likely to be enacted.   

So, we are a long way from having heard the last of the power-politics of coal – although there are a few more legal elements to the debate than there were in the good/bad old days of the 1960s and 1970s.  There is no doubt that coal still counts, but it looks as if we will have to wait a little longer to see how far we can still count on some of our existing coal-fired plant.

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Coal still counts (2): decision time for generators (or it will be soon)

Plugging in to a European Supergrid?

Interconnection is a hot topic.  “We need much better grid interconnectors around Europe to enable energy to flow across the EU”, UK Secretary of State for Energy and Climate Change, Ed Davey, recently told The Independent.  Mr Davey’s Department of Energy and Climate Change (DECC) has just published More interconnection: improving energy security and lowering bills.  And it was recently reported that the development of a proposed UK-Norway interconnector was at a critical stage.

Interconnectors are essential to the EU single market in energy, which is meant to be completed in 2014.  They are also likely to be part of the solution to the problem of how to include non-UK providers in capacity market auctions under UK Electricity Market Reform (EMR).  This in turn may be an important point for the European Commission in granting state aid approval for EMR (see EU renewable generators: time to wean them off “overcompensating” subsidies?).  But while last year’s EU Regulation on cross-border infrastructure should make it easier to get interconnectors built and funded, the new DECC paper, and the Redpoint analysis that accompanies it, show very clearly why interconnection is such a difficult area for the UK.

europeansupergridmap

An Interconnected Europe?  Commission’s interactive map of Projects of Common Interest (electricity schemes are in blue)

Geography plays a part: it is inevitably more expensive to interconnect the UK with other EU markets than it is to interconnect many markets in Continental Europe.  But that is only the start.  Which markets should we connect to, and when?  How big should the connections be?  Who should build, own and pay them, where and when?  The answers to these questions depend on a lot of other, interdependent factors that are themselves not easy to pin down: notably the future generating mix in the UK and other markets concerned, and future fossil fuel and carbon prices.  DECC’s summary of Redpoint’s work notes that the possible impact on GB consumers ranges, rather neatly, from potential net benefits of around £9 billion to potential net costs of around £9.5 billion.

Perhaps the toughest questions are who should decide between the competing merits of rival interconnection schemes, and when that decision should be taken.  Historically, neither the planning regime nor the regulatory network development process have had to pick winners and losers in this way.  But DECC’s acknowledgement that the issue should be looked at strategically and some kind of plan formed is encouraging.  They identify Ofgem’s Integrated Transmission Planning and Regulation (ITPR) project, and its ongoing consideration of Project Nemo and other proposed interconnection schemes as the proper vehicle for next steps on UK interconnection policy: watch this space.

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Plugging in to a European Supergrid?

EU renewable generators: time to wean them off “overcompensating” subsidies?

The European Commission has published draft state aid guidelines on environmental and energy aid for 2014-2020 for consultation.  According to the accompanying press release, these would “facilitate the decarbonisation of energy supply and the integration of the EU internal energy market”.  A less charitable reader might detect in the draft guidelines some tensions between the EU’s competing goals of promoting free competition and completing the EU internal energy market on the one hand and the need to reduce greenhouse gas emissions and ensure security of energy supply on the other.

The draft guidelines follow the policy outlined in the Commission Communication on delivering the internal electricity market and making the most of public intervention, published with accompanying  staff working papers in November: the suspicion that, notwithstanding “the challenges of the climate change agenda”, some national subsidy regimes for renewables are “overcompensating” what are now “mature” technologies; that new schemes designed to ensure security of supply may end up supporting plants that are unnecessary or inefficient; and that Member States too readily opt for subsidies rather than pursuing demand reduction options or the potential for EU market integration.

There is considerable emphasis on the use of competitive bidding processes.  The draft thresholds for determining whether a technology is “deployed” and subsidies to it therefore require to be subject to more rigorous criteria may be set quite low (between 1 and 3 per cent of production at EU level).  For each technology / kind of aid, the draft guidelines list specific anti-competitive pitfalls to be avoided and/or ways to monitor for, and correct, possible overcompensation.  And it is envisaged that the guidelines will apply not just to new schemes, but also to existing ones which are amended after the guidelines come into force – unless the only amendment is the publication of a new tariff, or the beneficiary has received confirmation that it will benefit for a predetermined period.

In some ways, none of this should be surprising.  By definition, even aid that has been cleared by the Commission remains susceptible to further examination in the light of changing market conditions – which may lead to something that was originally found compatible with the internal market subsequently being found to be incompatible.  It remains to be seen whether the draft Guidelines will lead to this happening more often, or whether they will change much as a result of this new consultation (the third on this subject).  One thing that is certain is that there is no shortage of high-profile cases to which the Commission can apply its current thinking.  On the same day as the draft guidelines were published the Commission announced an in-depth investigation into a German scheme reducing renewables surcharges to energy-intensive users and into the UK’s proposed aid to EDF’s Hinkley Point C nuclear power station.

All of which comes as a reminder that the low carbon investment support and security of supply elements of the UK Government’s flagship programme of Electricity Market Reform (EMR) require – and have yet to be granted – state aid clearance from the Commission.  The same is true of the proposed exemption for energy intensive industrial users from the increases in supply charges that will fund EMR.  It is not surprising that recent DECC announcements have stressed the possibility of e.g. moving to competitive bidding for EMR contracts for difference (rather than setting the “strike price” administratively) sooner rather than later.  Fortunately, the EMR regime has been designed in such a way as to accommodate a lot of adjustments both before and after it goes live later this year.

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EU renewable generators: time to wean them off “overcompensating” subsidies?