Day: October 13, 2024

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 NO_x) 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 NO_x 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.

Summary

The title given to Sir Ian Wood’s “UKCS Maximising Recovery Review: Final Report” (published on 24 February 2014), should ensure that his name is immortalised as the abbreviation most will use, the “Wood Review”, and rightly so. This former chairman of oil field services company Wood Group has become a figure-head for reform and has set a CEO-style vision, in addition to his Government remit to make recommendations to: “enhance economic recovery of oil and gas reserves in the future”.

With this in mind, the Wood Review is not overly compromised with detail. The central proposal is for a new, independent, and much more proactive regulator to maximise economic recovery (MER).  This could be criticised as fragmenting current regulation, but Sir Ian’s pragmatic rationale is clear: “a new body…to focus solely on MER will give a clear signal. The Review believes that simply increasing the resource…within DECC is likely to be perceived as a re-badging with little material change.”

Context

The imperative for MER is production apparently falling by 38 per cent between 2010 and 2013 and a sharp decline in exploration and discovery.

Given the right “stewardship,” the UK is said to have the potential to recover an additional 3-4 billion barrels of North Sea oil over the next 20 years, with a resultant £200 billion boost to the UK’s economy.

The final Wood Review is consistent with and builds upon its Interim Report, published in November 2013.

Obstacles to overcome

The Wood Review identifies outdated “light touch” regulation as a key hindrance to the exploitation of hydrocarbons in the North Sea. A regulatory regime designed for an era of large fields and large operators has apparently not evolved to adapt to the new reality of a basin with over 300 fields, much smaller new discoveries, many marginal fields and far greater interdependence in exploration, development and production.

Specific obstacles to growth highlighted in the Review include fiscal instability, insufficient collaboration between industry players in respect of third party use of infrastructure, a lack of sharing of geophysical information, excess time spent on commercial and legal negotiations and inadequate use of technology (including Improved and Enhanced Oil Recovery (EOR)). Floating Production Storage and Offloading vessels are for example noted to have higher operating costs and poorer field recovery than using existing infrastructure where available. Over 20 instances in 3 years of “operators” failing to agree terms for access to processing and transport infrastructure, has led to more expensive / lower recovery developments.

Key recommendations of the Wood Review

The Review advocates a tri-partite strategy involving HM Treasury, industry and the proposed MER regulator. Whilst collaboration may be implicit, it is notable that the involvement of existing regulatory bodies is not emphasised. Some re-alignment of regulatory responsibility is suggested with the new MER regulator perhaps being given responsibility for carbon capture and storage, and with a potential on-shore remit. The Review also recommends new sector strategies be developed for: exploration; asset stewardship; regional development; infrastructure; technology and decommissioning.

The Review envisages that the proposed new MER regulator would be encouraged to make more robust use of existing enforcement powers and may be given new powers or access to licensees, both in the practical sense (for example by being able to attend operational and technical meetings; make recommendations; have greater data access; and to implement a “non-binding” dispute resolution function), and by way of potential new licence terms (relating to maximising economic recovery, achieving acceptable production efficiency and agreeing collaboration on cluster developments). It is further suggested that consideration of past MER performance, should be specifically taken into account for future licence applications. Formal sanctions to encourage MER compliance may include a system of issuing private and public warnings, before removal of operatorship or suspension or termination licences. Interestingly, it is said that the MER regulator should have the right to apply sanctions to the whole consortium or just those who are deemed to be failing to meet licence obligations, or indeed, MER requirements. Whilst it appears there is significant detail to be ironed out here, the collective responsibility intention is notable.

Flexibility

There is also a recognition of a need for flexibility where necessary. The four year exploration and four year development terms in Traditional Seaward Production Licences are noted as appropriate for mature areas, but the Review suggests that six year periods are more suitable for frontiers like the West of Shetland, where the drilling season is short, and in High Pressure High Temperature plays. It is said that licensees shouldn’t be compelled to drill commitment wells where new information suggests they would be unviable. The flexibility theme is also discussed in the context of the almost exclusively gas producing Southern North Sea, which is in danger of apparently premature decommissioning, given the lower market value of gas.

Competitive disadvantages of the UKCS versus the Netherlands are another interesting theme and is, in part, attributed to the Dutch Government’s active ownership of infrastructure. Differences in commercial models are also noted whereby, for example, NOGAT BV (whose business model is solely to operate pipelines and processing facilities) actively seeks to attract new transport business, versus the apparent reluctance of UKCS operators to facilitate third party infrastructure use business as an adjunct to their core production business.

Fiscal incentives

Such issues are intended to be bolstered by HM Treasury’s better use of: “fiscal levers to incentivise MER”, perhaps including: extension of field allowances to incentivise EOR; or incentives for seismic and the drilling of exploration or less prospective wells by operators who currently lack production. In addition, a need for commitment to a simpler and more stable fiscal regime is acknowledged (although tax is beyond the specific remit of the Wood Review).

What is next?

Government and industry appear to publically welcome the initiative, which is to be industry-funded. Indeed, Ed Davey (Secretary of State for Energy) has announced that legislation to implement the new body, will be introduced in the fourth parliamentary session (ie. autumn 2014) but it would be expected to become law in 2015, and may be dragged out by a need for secondary legislation. Ed Davey has hinted at an informal “shadow” arrangement in the meantime. Such break-neck speed perhaps seeks to capitalise on the Review’s current good will, and will hope to minimise potentially significant industry delay in making new investments, pending uncertainty as to the new regulations.  It may also reflect the UK Government’s desire to show oil and gas policy leadership before September’s referendum on Scottish independence, and the spring 2014 publication of detailed Scottish oil and gas proposals for maximising economic recovery, which also intends to consider the Wood Review. Time will tell whether all remain so keen, once detailed provisions take effect, particularly given the Review’s criticism of some current areas of apparent self interest which are to be targeted.  As currently proposed, reforms may touch all areas of the UK oil industry from operators down, both on and off-shore.

The Silk Commission, set up to consider possible changes to the powers of the devolved government in Wales, have recommended a new division of responsibilities between UK and Welsh Ministers as regards the consenting of energy projects (click here for their report).  The Commission propose that “responsibility for all energy planning development consents for projects up to 350 MW onshore and in Welsh territorial waters should be devolved to the Welsh Government”.  This would bring Welsh Ministers closer to parity with their Scottish counterparts in energy consenting: they have long complained that there is no good reason why proposed generating stations with a capacity of more than 50 MW should be determined by UK Ministers if they are Wales, but by Scottish Ministers if they are in Scotland.  Although the proposal is not tied to particular technology types, sub-350 MW schemes are always likely to be renewables projects.

As in many parts of the UK, new renewable developments are not always popular in Wales.  In Wales there have been particular problems as a result of the relevant Welsh Government planning policy document, TAN 8, which encouraged developers to focus their proposals for wind farms on a number of designated areas.  So, in Powys, for example, a conjoined public inquiry is currently being held (on behalf of the Secretary of State for Energy and Climate Change) into five proposed wind farms with a combined capacity of several hundred MW.  As well as being unpopular with local residents, this kind of concentration of development in a given area presents major logistical problems for developers: the capacity of the road networks to cope with the large numbers of outsize loads that would need to be transported on them to build the wind farms is severely constrained in the largely rural areas involved.

Under the Commission’s proposals, Welsh Ministers would have to deal with the consequences of TAN 8 as decision-makers on individual applications.  But UK Ministers have so far been very reluctant to give up their decision-making powers over larger Welsh wind projects, even though the objections to them are not confined to Wales itself: the proposed line of pylons that would carry power from mid-Wales wind farms to the Grid in England would pass through Shropshire and has excited plenty of opposition on the English side of the border.   Whilst the Commission’s overall plan is for new primary legislation on Welsh devolution by 2017, they point out that the competence of the Welsh Assembly could be expanded by secondary legislation on a shorter timescale.  However, it seems unlikely that any action will be taken that would result in Welsh Ministers, rather than the Secretary of State, determining the five Powys applications.

The Commission also recommend giving Welsh Ministers the power to approve “associated development” such as roads and substations as part of a development consent order for a “nationally significant” generating station under the Planning Act 2008.  At present, absurdly, this can currently be done for English, but not for Welsh projects, meaning that the supposed “one-stop shop” provided by the 2008 Act for consenting complex projects is nothing of the kind in Wales.

In a politically charged area where there are probably no perfect solution, the Commission’s proposals deserve serious consideration.

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? 

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.

In July and November last year, DECC consulted on the transition period between the introduction of the Contracts for Difference (CfD) regime under Electricity Market Reform (EMR) later this year and the closure of the Renewables Obligation (RO) to new generating capacity at the end of March 2017.  The response to these consultations was published earlier this week, just as Spring came to London.  Some of the policy decisions it sets out will already have been apparent to careful students of the draft Renewables Obligation (Amendment) Order 2014 that was published and laid before Parliament last month with an accompanying  written ministerial statement, but the response provides an opportunity to see DECC’s approach to RO / CfD transition issues in the round, with a fuller set of explanations.

Botticelli’s “Spring”: spot the connections between the picture and this post!

The transition period

The transition period begins once the CfD regime is live.  No firm date is given for this, but the response refers to 31 October 2014 as the date when CfD applications are expected to open.  It also says Government does not expect applications for CfDs to be open in advance of State Aid clearance. 

Choice of scheme

During the transition period, developers will be able to apply for accreditation under the RO or for a CfD or Investment Contract (if they meet the relevant eligibility criteria).  When they make their applications, they will be required to make various declarations: for example, if they are applying for a CfD, to declare that they are not supported under the RO.  A developer who is unsuccessful in relation to an application under one scheme will be able to apply under the other. 

A developer whose Investment Contract is terminated for certain reasons relating to State Aid, or to possible amendments to the Investment Contract in the light of the standard terms for CfDs will be able to apply for RO accreditation.  But a developer who withdraws an RO or CfD application or refuses a CfD or RO accreditation will not be able to apply under the other scheme: so, you cannot, for example, bid for a CfD, decide that you don’t like the strike price (e.g. in a “pay as clear” regime), and decide to retreat to the perceived safety of the RO instead. 

The level of the RO (i.e. the extent of the obligation on electricity suppliers to purchase ROCs) will continue to be set by 1 October, rather than being pushed back to being decided by 1 February.  Whilst effectively acknowledging that the likely launch of the CfD regime in the later part of this year will complicate the task of setting the RO level at the same time, Government has been persuaded that moving to a February deadline would mean that suppliers had to rely on their own internal RO forecasts when pricing supply contracts, resulting in the addition of a risk premium which would increase consumer bills.  The status quo was therefore preferred.

Dual Scheme Facilities

Additional capacity added to an RO accredited project will be eligible for registration under the RO if no application for a CfD has been made in respect of the project.  However, additional capacity of 5MW or less added to RO accredited stations after 31 March 2017 will not be eligible for RO or FiT support.  On the basis of the representations made to it, DECC does not seem to believe that there is a significant class of potential ≤5MW extensions to existing RO-accredited projects which would not be able to go ahead without an extension of the RO deadline (or FiT support) beyond March 2017. Although, between 2006 and 2012, 131MW of the 190MW of additional capacity accredited in respect of existing projects was ≤5MW, 103MW was for landfill and sewage gas sites: analysis of this sector suggests that existing sites have added most of the extra capacity they can, and DECC do not expect many new sites to be developed under the RO.  Finally, increases in capacity resulting from station refurbishment or unit replacement after the closure date will not be eligible for support under the RO.

On the other hand, projects which are developed in phases may find themselves with part of their capacity accredited under the RO and part being the subject of a CfD.  In such cases there will need to be separate metering and fuel data collection for the two parts of the project, so as to make sure that plants do not claim ROCs / CfD payments in respect of capacity which is not entitled to them.  As DECC puts it, “preventing arbitrage opportunities between the two schemes and ensuring accuracy, is crucial to minimise the impact on consumer bills”.  DECC also take the view that the dual scheme arrangements should not be available to RO-accredited projects which wish to add less than 5MW of extra capacity funded by a CfD, as it would give rise to an “unjustified” and “disproportionate administrative impact in relation to the amount of additional generation produced”.

Grandfathering

The July consultation included some proposals about grandfathering, with particular reference to biomass co-firing.  The response reports “widespread misunderstanding” of these proposals, which DECC concludes “were too confusing and administratively complicated to take forward” and “would have had little genuine impact in terms of budgetary stability”.  Further proposals in this area may be consulted on “later in the spring or summer”.

Grace periods

The grace periods are a set of four exceptions to the rule that the RO closes to new capacity on 31 March 2017: projects which reach the stage at which RO accreditation could have been given within a certain period after that date will be allowed to be accredited in certain circumstances.  A project that is in a position to benefit from two or more of these exceptions will only be permitted to benefit from one, but (subject to the eligibility rules) has a free choice in deciding which one it will benefit from.

• New or additional capacity which is delayed by a failure to resolve issues with radar or to establish a grid connection will have a 12 month grace period.  In the case of grid delays, there must be evidence of a grid connection offer made and accepted and a network operator having set a date before April 2017 for connecting the project.
• There will be a 12 month grace period for any project that is awarded a FID Enabling Investment Contract if that contract is terminated either for reasons relating to state aid or because the developer exercises a right to terminate when changes are made or proposed to it in the light of the CfD standard terms.   
• A 12 month grace period will be available to a class of ACT or offshore wind projects which are scheduled to commission close to 31 March 2017 and have been identified as at risk of investment hiatus.  These projects are expending funds but are unwilling to commit to the CfD regime because elements of it are still uncertain.  The deadline for applications for this grace period will be 31 October 2014 – i.e. about the time when applications for CfDs are expected to open.  DECC rejected suggestions of a later deadline “as it could give projects which could have applied for a CfD shortly after applications open an incentive to enter the RO instead”.  Of course, it may be that by requiring developers to apply for the grace period before the outcome of the first CfD allocation round is apparent, DECC will simply guarantee that they opt for the RO, but DECC’s thinking seems to be partly that it is targeting projects that ought to be commissioned before 31 March 2017 and making sure that this happens by giving them the confidence to proceed, in the knowledge that the grace period provides them with a safety net.  By way of evidence that they are sufficiently advanced to be eligible for this grace period, developers will have to produce a grid connection offer, a letter from the network operator indicating that connection will take place before April 2017, planning consent (the conditions of which need not have been discharged) and land use rights or an option to acquire them.  They will also have to produce a director’s certificate confirming that the developer will have sufficient resources to commit to the project and that it is expected to commission before April 2017.  Various forms of more detailed evidence of “substantial financial commitment” towards the project were considered and rejected as “too restrictive, too unclear or too sensitive”. 
• DECC begins discussion of the final grace period by observing that “dedicated biomass projects have in some cases been delayed while detailed Government policy arrangements in relation to the 400MW cap were put into place”.  Dedicated biomass projects allocated an unconditional place within the cap will therefore be offered an 18 month grace period, regardless of whether they are CHP or not.  However, this grace period will not be available for additional capacity.

Further measures for biomass

Generating stations which co-fire biomass and are RO-accredited but have never claimed ROCs under the biomass conversion support band will be permitted to apply for a CfD or Investment Contract as biomass conversions, and leave the RO if they are successful.  If the operator gets cold feet about its CfD before reaching the CfD “Start Date”, it will be able to revert to the RO.  However, DECC has not yet decided whether an operator which finds itself in this position with respect to only some of the units in a generating station would still be entitled to claim ROCs at the conversion band for units in respect of which it has not previously fired or claimed this level of support.

Biomass co-firing stations which are supported by the RO will be permitted to bid into the EMR Capacity Market, leaving the RO if they are successful in their bid.

Offshore wind

Offshore wind projects accredited under the RO when it closes will be permitted to commission their remaining phases under (i) the RO, (ii) the CfD or (iii) both regimes, provided that they “inform Ofgem by 31 March 2017 “whether they intend to take up the RO option” in relation to any of those phases.  Option (iii) is expected to be a minority interest.  RO and CfD phases “will need to be on entirely separate strings of turbines”, with no connection that enables electricity generated by one string to be exported on another.  

Replacement of ROCs with Fixed Price Certificates

The July consultation opened up the possibility that the transition from the current ROC regime to a system of fixed price certificates (FPCs) might be brought forward to coincide with the closure of the RO to new capacity in 2017 rather than taking place in 2027 as originally proposed.  However, DECC intends to stick to the original plan, because consultees did not persuade it that ROC values are likely to fall below the buyout price or that a significant oversupply of ROCs is likely to occur.  

What next?

The implementation of most of these policies will be spread across the RO (Amendment) Order mentioned above (intended to come into fore on 1 April 2014) and the RO Closure Order (due to be laid before Parliament in May and come into fore in July 2014).  “Some remaining transition policy issues, such as those relating to interaction between the RO and the Capacity Market” will be dealt with in an RO Consolidated Order to be made “later in 2014/15”.

Comments

In a world where there is no perfect answer and the most important thing is for developers to know where they stand, DECC’s consultation response is to be welcomed.  It bears the hallmarks of  evidence-based policy making and shows a proper degree of engagement with what consultees had to say as well as a willingness to interrogate critically the representations that they made.  

Overall, the response appears to take a slightly tougher line than is sometimes found on what DECC evidently sees as unjustified special pleading in some areas.  This, and a recurrent emphasis in the response on controlling costs, make sense both in domestic political terms and from the point of view of clearing these policies with the European Commission under the state aid rules.  

The response is perhaps a little more favourable on balance to biomass developers than some of DECC’s publications on biomass of last year, whilst emphasising its transitional status.

DECC has tried to keep things simple at a number of points.  However, the detail of what must be done in order to be eligible to make particular choices is inevitably quite intricate.  Developers will need to think carefully about how to integrate transition and grace period decision-points and criteria, as well as the various steps in RO and CfD procedures, into their own project plans.

As ever with EMR, some big questions remain.  Perhaps the biggest in this case is whether the flexibility to move between the RO and CfD regimes will encourage those who are able to choose either regime to opt for a CfD in preference to the RO.  If it does not, there must be a risk that the RO’s share of Levy Control Framework funding (see the table below, based on DECC figures) will continue to dominate UK renewables subsidies to a greater extent and for a longer period than to be comforably consistent with either the ultimate goals of EMR or the European Commission’s policies on state aid for renewables schemes.

In December 2013 DECC published, and submitted for consultation, a Strategic Environmental Assessment (SEA) for further onshore oil and gas licensing. The SEA environmental report is required to identify the likely significant effects of proposed licensing on the environment, and identify the reasonable alternatives to DECC’s proposal. The consultation period closes on 28 March.  DECC will consider responses to the consultation before issuing a post-adoption statement that will summarise government policy on further onshore licensing.

Just as the consultation period was drawing to a close, six countryside and wildlife organisations, including the National Trust and RSPB, released a report entitled “Are we fit to frack?”.  Referring to analysis in the SEA environmental report prepared by AMEC, the Are we fit to frack? report sets out concerns about the potential impact of unconventional onshore oil and gas developments on protected species and habitats in the UK.

Analysis in the report indicates that a significant proportion of land currently “under licence” comprises designated protected areas of one kind or another (e.g. 5.1% being sites of special scientific interest; 5% being national parks; and 9.8% being Areas of National Outstanding Beauty).  The analysis also indicates that a greater proportion of the land being considered in the 14th licensing round is similarly protected.  Despite this, the National Trust, RSPB, Wildlife Trust and Wildfowl and Wetlands Trust between them own only a very small proportion of these areas.  Perhaps as a result, the first of 10 recommendations made by the report is the creation of “shale gas extraction exclusion zones” to avoid sensitive areas for wildlife and water resources.

The SEA environmental report concludes that the existing regulatory framework will identify, assess and mitigate to an acceptable level any environmental effects. It states that construction and operational best practices can minimise effects to a level that is acceptable to both regulators and communities. By contrast, Are we fit to frack? describes the current regime as not fit for purpose. The report considers the current safeguards are too reliant on self-inspection and the HSE ,which “does not have the necessary specialist knowledge”.

The UK Onshore Operator’s Group (UKOOG), promptly published a response to the report on its website.  Chief Executive  Keith Cronin commented, “We have studied this report and the fact is that many of the recommendations are already in place in the UK or are in the process of being put in place. We hope that the publication of this report, despite a number of critical inaccuracies, will kickstart a process of open dialogue which we have already proposed to conservation agencies.”

Are we fit to frack certainly has the potential to kickstart a constructive dialogue.  However, it also has the potential to polarise the debate, with important stakeholders on each side.  Indeed the debate already looks adversarial, with the current UK Government adopting an entrepreneurial “pro-shale” stance, but the EU Commission, conservation groups, and local residential groups all urging caution.

This emerging fault line could pave the way for legal challenges against decisions taken by DECC in the 14th licensing round.  Demonstrating the absence of harmful effects on protected species (for the purposes of the Habitats Directive) could prove costly for developers, whether this is tackled at the licensing / consenting stage, or subsequently in court.

The prospect of legal challenges can lead to considerable uncertainty for developers and investors.  More generally, the impact of the Are we fit to frack? report on public perception should not be overlooked.  Unlike other published environmental assessments, the report was widely covered in the media, thereby contributing to the groundswell of public concern about fracking.  This recently released video from the European Commission summarises the divergence of public opinion on fracking.  Both the video and the Are we fit to frack? report emphasise that navigating the route to achieving a “social licence” is inextricably linked to the route to obtaining regulatory consents.

It has been widely reported that Ofgem has referred the “Big 6” UK energy companies for investigation by the Competition and Markets Authority (CMA).  That is of course not strictly true, for three reasons.

• First, and most trivially, the CMA, which will take over the functions of the former Office of Fair Trading (OFT) and Competition Commission, currently only exists in “shadow” form, and does not assume its statutory functions until next month.
• Second, although the prospect of a market investigation reference has been canvassed for some time, Ofgem have not yet made a reference.  They are consulting on a proposal to do so.  The consultation ends on 23 May 2014.  As any administrative lawyer will tell you, a decision-maker must not consult with a closed mind, so we are probably still at least 3 months away from the start of a CMA investigation.  It would be possible for Ofgem to agree “undertakings in lieu of a reference” from players in the market if it felt that would adequately address the problems it is concerned about without the need for a market investigation – although at present that seems an unlikely outcome.
• Third, as is normal with a market investigation, the proposed terms of reference do not refer to individual companies.  What Ofgem proposes that the CMA should investigate is no more and no less than the supply and acquisition of energy (i.e. electricity and gas) in Great Britain.

Market investigations are the oldest and in some ways the most powerful tool in UK competition law.  In their modern form they are governed by the Enterprise Act 2002, a piece of legislation enthusiastically promoted by the then Chancellor, Gordon Brown, as destined to make the UK economy more competitive by the more vigorous application of competition law.  They exist to deal with markets which appear to be insufficiently competitive, but whose problems do not appear to come from cartels or other anti-competitive agreements between firms, or the abuse of a dominant position – all of which obviously anti-competitive kinds of behaviour are prohibited under UK and EU law in any event.  A market investigation aims to find other features of a market which prevent, restrict or distort competition and then to devise a means or remedying, preventing or mitigating those effects, taking account of any incidental benefits which those features may bring to customers.  In a regulated market such as gas or electricity, the CMA may also need to have regard to the statutory functions of the sectoral regulator concerned.   The powers which the CMA can deploy in devising remedies for any problems it finds are extremely wide, and – unless Ministers legislate under the Act to give themselves a role – are formulated and imposed without any political sanction.  They can include everything from price regulation to divestment of a business – such as the forced sale of Stansted Airport that took place following a market investigation into airports.

Back in 2002, it was expected that there would be between two and four market investigation references a year.  In fact there have been slightly fewer: 17 completed investigations.  Back in 2002, some questioned whether economic sectoral regulators such as Ofgem would ever use the power that was being given to them to make a market reference in respect of their own sectors (otherwise, the power to refer a market rests with the OFT, or, in an extreme case, Ministers): would referring the market that it was their function to regulate not look like an admission of defeat?  Ofgem’s proposed reference, if made, will be the first to be made by an economic regulator into the very heart of the markets which it is responsible for regulating.

Ofgem have published a consultation on the proposal to make a reference and, separately, a state of the market assessment containing the fruits of its own investigation, with the OFT and CMA, into the current state of competition in energy markets.  Both are well worth reading (as is the Secretary of State’s statement to Parliament on the Ofgem announcement).  Don’t be put off by the apparent length of the state of the market assessment, as a large amount of its more than 100 pages is taken up with rather striking graphs and charts.  I particularly liked Figure 14, which shows that the proportion of consumers who said they have not switched supplier because they are “happy with their current supplier” fell from 78% in 2012 to 55% in 2013; the proportion who claimed to have checked prices and found that they were on the best deal rose from 9% to 12%; and the proportion of those honest enough simply to say that switching was too much of a hassle rose from 20% to 27%.

The points that Ofgem have highlighted as reasons for proposing a market investigation are mostly what economists would regard as potential symptoms of competition problems rather than the actual features of the market that are giving rise to those problems.  They are, however, symptoms traditionally associated with uncompetitive oligopolies, which is what market investigations are meant to be good at tackling: high levels of apparent customer dissatisfaction, but low levels of customer switching; static market shares of incumbent firms; possible “tacit collusion” (e.g. co-ordinating in the timing and size of price changes); possibly high profits; and potential barriers to entry.  The last of these is the most significant, but the assessment document is notably circumspect in its conclusions: “In the time available…we have not been able to examine in depth the claimed benefits and reasons for vertical integration for the suppliers and the implications for barriers to entry, and assess the net impact on consumers of vertical integration overall.”.

The big question of the effect of the Big 6’s high shares of both the supply and generation markets is therefore left for the CMA to consider in the greater depth that its procedures and wider powers to compel the provision of information allow.  Another big question in any regulated market is of course the effect that regulation itself has on competition.  Here, the CMA will really have its work cut out, because the regulatory landscape in the energy sector is in a more than usually fluid state just now, with various significant Ofgem reforms about to take effect and DECC in the process of finalising the radical upheaval that is Electricity Market Reform (EMR).  The CMA will have a ring-side seat as the first allocations of EMR Contracts for Difference take place and the EMR Capacity Market is launched, expected to be later this year.

That in turn raises the question of timing.  Some have been calling for an energy market investigation for some time.  Others suggest that with so much change, such an investigation can only add to uncertainty and further inhibit decision-making on new infrastructure that is sorely needed to keep the lights on.  What is certain is that market investigations can, and frequently do, take up to two years (not counting any further time taken up in legal challenges to the outcome).  There are often good reasons for that, but even apparently uncompetitive markets can change over time.  What appear to be problems at the start of an investigation may not still be there at the end.  How relevant will the CMA’s findings be in 2016, a year after an election that may be won by a Labour Party which has announced its intention of making a series of further regulatory changes, including the abolition of Ofgem and the separation of generation and supply businesses?  In any event, if the CMA do find that there are features of the regulation of energy markets that are part of the competition problem, that is one area in which it may not be able to impose remedies, and may instead have to limit itself to making recommendations to the sector regulator or the Government of the day.  So those welcoming Ofgem’s announcement as an end to “the politics” around the issues and the start of a dispassionate, technocratic process may have spoken too soon.