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UK “early” Capacity Market auction produces cheapest prices yet

The provisional results of the “early” Capacity Market auction held last week have now been published.

This was an auction exclusively of 1-year capacity agreements, primarily to cover Winter 2017/18, after the UK Government decided that it did not want National Grid to carry on ensuring security of supply during Winter periods by means of a Contingency Balancing Reserve (CBR).  The CBR involved auctions open to generators who would not otherwise be operating in a given Winter period and to demand side response providers.  A Government consultation in March 2016 noted that the prices National Grid were paying under the CBR were increasing and that it introduced distortions into the market.

From Winter 2018/19, of course, the Capacity Market itself will ensure security of supply.  Those with capacity agreements beginning in 2018 will be the capacity providers who bid successfully in a four year ahead auction held in 2014, supplemented by those who win capacity agreements in any subsequent one year ahead auction for delivery in 2018.  Last week’s “early” auction was a one-off bridge between the CBR (now operating for the last time to cover Winter 2016/17) and the fully-fledged Capacity Market regime.  The key difference between the CBR and the Capacity Market is that the CBR (or at least the major part of it) focuses on securing capacity that would otherwise not be in the market, to fill the potential gap between existing generation and projected peak demand, whereas the Capacity Market provides a reliability incentive to all eligible generators and demand side response providers on the market.

Commentary on previous Capacity Market auctions (such as this post from December 2016) has tended to focus on the failure of the four year ahead auctions to result in the award of 15 year agreements to meaningful amounts of large-scale new gas-fired generation projects.  With new projects competing against almost all existing thermal generation, and new reciprocating engine projects able to bear much lower Capacity Market clearing prices than a CCGT project, the auctions have produced low clearing prices, but no obvious successors to the existing big coal-fired plants that the Government wants to close by 2025.

How to evaluate the results of the “early” auction, then?  The provisional results indicate capacity agreements going to 54.43 GW of capacity, at £6.95 kW / year, suggesting total costs to bill payers of around £378 million.  This might look like spectacularly good value compared with the results of the last four year ahead auction (for delivery starting in 2020), where the clearing price was £22.50 kW / year for 52.43 GW of capacity.  But that isn’t really a fair comparison, since about a quarter of the capacity that was awarded agreements for 2020 was new build, whereas less than 4 percent of the capacity awarded agreements in the “early” auction falls into this category.  All the rest will be paid £6.95 for just continuing to operate – which presumably most of them would have done anyway. 

An alternative point of comparison might be with the costs of the CBR.  The most recent Winter for which these are available is 2015/16, when National Grid spent just over £31 million on procuring, testing and utilising less than 3 GW of CBR capacity.  Obviously a much inferior system. 


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UK “early” Capacity Market auction produces cheapest prices yet

UK renewable Contracts for Difference – now only for offshore wind?

The UK’s Contracts for Difference (CfD) regime for renewable subsidies was one of the principal pillars of the Electricity Market Reform programme put in place by the 2010-2015 Coalition Government.  In one way or another, the CfD regime aimed to provide revenue stability for most renewable technologies in projects of more than 5 MW, with consumers sharing in the upside at times when power prices exceed the guaranteed “strike price” set in a competitive allocation process.

Before the UK General Election of May 2015, it was also expected that auctions would follow a regular annual rhythm – or possibly occur more than once a year for some technologies. But things have changed a lot in the last seven months in the world of CfDs – and they continue to change.

  • The Conservative Party, victorious in May 2015, had campaigned on a manifesto promise of “no new subsidies for onshore wind”, which they have been quick to implement, and which appears to include the exclusion of onshore wind (except perhaps on Scottish islands) from future CfD auctions.
  • On 11 February 2016, the Secretary of State for Energy and Climate Change, Amber Rudd, told Parliament: “We don’t have plans at the moment for a large-scale solar contract [for difference]“.
  • The day before, her Department announced “an independent review into the feasibility and practicality of tidal lagoon energy in the UK” – appearing to cast more than a little doubt over the prospects of the Swansea Bay Tidal Lagoon project, with which the Department had previously been said to be negotiating CfD support (tidal lagoon projects, like nuclear ones, fall outside the scope of the competitive CfD allocation framework).
  • The news that the European Commission has doubts about the compatibility with EU state aid rules of the proposed CfD for the conversion of a third unit at the Drax coal-fired power station to burning biomass perhaps makes it unlikely that there will be many, or any, more CfDs awarded for this technology.
  • Almost a year after the results of the first (delayed) CfD auction were announced, there is no sign as yet of Government gearing up for a second auction any time soon – merely a promise that there will be funding for three more auctions before mid-2020.

To be fair, so far, nothing has been said to suggest that Energy from Waste with CHP, Hydro (up to 50 MW), Landfill Gas, Sewage Gas, Wave, Tidal Stream, Advanced Conversion Technologies, Anaerobic Digestion, Biomass with CHP or Geothermal will not be eligible if and when the second auction finally takes place, but the fact remains that for the foreseeable future, offshore wind appears likely to dwarf all the other CfD-eligible technologies.

In clearing the original CfD rules for state aid purposes, the European Commission noted, as apparently relevant facts, that “All generators producing electricity from renewable energy sources will be able to bid for a CfD on non-discriminatory basis (albeit that some less established technologies will initially benefit from allocated budgets in order to promote their further development).“, and that “in the absence of aid renewable energy technologies will not be deployed at the required scale and pace, as without the aid such projects would not be financially viable.”  This was in keeping with the emphasis in the relevant State Aid Guidelines that an “auctioning or competitive bidding process open to all generators producing electricity from renewable energy sources…should normally ensure that subsidies are reduced to a minimum“, but admitting that “given the different stage of technological development of renewable energy technologies“, technology specific tenders may be allowed “on the basis of the longer-term potential of a given new and innovative technology, the need to achieve diversification; network constraints and grid stability and system (integration) costs“.

The statutory framework for CfD auctions allows the Secretary of State enormous flexibility to determine, at very short notice and in documents which are not subject either to Parliamentary approval or any statutory consultation requirement (the “budget notices” and “allocation frameworks”), which technologies will be eligible for support in a given auction.  However, it must be arguable that a decision effectively to exclude technologies as significant (and competitive) as onshore wind and solar from the allocation process could amount to a change in the CfD rules which should itself be notified to the Commission for state aid approval.  And it is not entirely clear that such exclusions could be – or at any rate have been – justified on the grounds specified in the Guidelines as a basis for technology specific tenders.

A cynic or conspiracy theorist might suspect that the lack of urgency in proceeding to a second CfD auction may not be unrelated to the UK Government’s reluctance to put itself – in advance of a referendum on the UK’s continued membership of the EU – in the position of appearing to have to ask the Commission’s permission (in the form of a state aid clearance for alterations to the CfD rules) not to offer CfDs to technologies that Ministers do not want to subsidise.  But cynics and conspiracy theorists are often wrong.  The Government is perhaps more likely to be just taking its time to consider the future of CfDs more broadly.  For example, in the 11 February 2016 Parliamentary exchanges referred to above, Ministers confirmed that they are looking “very closely” at the seductively labelled and highly fashionable concept of “subsidy-free CfDs” (which means different things to different people, but for one interesting suggestion, see this blog post by Professor Michael Grubb of UCL).

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UK renewable Contracts for Difference – now only for offshore wind?

Christmas to come late(r) for those seeking UK renewables CfDs

Two more milestones in the implementation of UK Electricity Market Reform (EMR) have been passed in the last 24 hours (15/16 December 2014): the first EMR Capacity Market auction began, and it became clear that the first auction of EMR Contracts for Difference (CfDs) has been postponed until February 2015.

The Capacity Market aims to secure the availability of 48.6GW of reliably despatchable generating plant from the autumn of 2018.  This is being procured by means of a series of bidding rounds in a “descending clock” auction which must be completed by 19 December 2014.  The auction pits existing coal, nuclear, CCGT and peaking plant against each other and against new build gas and diesel generators, but only new build plant and existing plant spending £125/kW or more on refurbishment can act as “price makers” in the bidding process (see further National Grid’s Auction User Guide).

According to the previously advertised timetable, the first CfD auction should already have taken place in early December, with results being notified to applicants between Christmas and the New Year.  Instead, the revised version of the Low Carbon Contracts Company’s GB Implementation Plan for CfDs, published on 15 December 2014, states that those seeking CfDs will be invited to submit their bids on 17 February 2015 (if, at that point, demand for CfDs exceeds supply under the allocation round budget).

The delay has been driven by appeals against decisions on the eligibility of applications.  The Implementation Plan notes that a longer delay is possible if “Tier 2” appeals are not completed by 6 February 2015.  It is interesting that DECC has chosen to delay the CfD auction rather than make use of the mechanism (provided for in Part 8 of the Allocation Regulations and Rule 21 of the Allocation Framework) that allows an auction to go ahead with disputed applications still “pending”.

While we await the eventual outcome of these two first-of-a-kind auctions, we can start to compare and contrast the CfD and Capacity Market processes.

One striking difference is in terms of transparency.  The Capacity Market prequalification process results in publication and regular updating on the EMR Portal of a full list of applicants (both successful and unsuccessful) and their plants.  By contrast, there is no published list of applications for CfDs or the decisions that have been made as to their eligibility to be allocated a CfD.  In some ways this mirrors the bidding processes themselves: the successive rounds of the Capacity Market auction are rather more interactive and offer bidders some (albeit limited) visibility of each other’s behaviour; in the CfD auction, applicants must effectively put everything into their initial sealed bid.

A second major difference is in the scrutiny to which applicants’ claims to have fulfilled the criteria that make them eligible to bid are subjected.  For example, under the CfD legislation, applicants’ claims to have the necessary planning permission for their generating stations have to be substantiated by submitting copies of the relevant documents, which will then be checked by National Grid (albeit possibly in a fairly mechanical way).  By contrast, compliance with the parallel obligations to have any requisite planning permission before bidding in the Capacity Market auction is simply self-certified.

No doubt there will be further debate about these and other design features during 2015.  Already, Ofgem is consulting on possible changes to the Capacity Market Rules.  It has identified as priority areas for consideration the possible streamlining of the prequalification process, price maker memoranda, and rules about demand side response.  Meanwhile, alleged discrimination against the demand side has prompted Tempus Energy to challenge the European Commission’s decision that the Capacity Market is compatible with EU state aid rules.

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Christmas to come late(r) for those seeking UK renewables CfDs

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


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

Table 6

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

Early closure of RO to >5MW solar PV projects confirmed

Following a consultation that ran from 13 May to 7 July 2014, the UK Government has confirmed its intention that, as a general rule, funding under the Renewables Obligation will not be available to larger scale (>5MW solar) PV projects after 31 March 2015.

There will be a “grace period” of a year for projects which were, in effect, in a position to begin development before 13 May 2014.  Perhaps more usefully for projects which may struggle to meet the requirements for RO accreditation before 31 March 2015, further consultation is taking place on a proposal to protect the position of those projects which only fail to meet the 31 March 2015 cut-off date for commissioning because their electricity network operator has not met a pre-31 March 2015 estimated connection date.


For most technologies, the Renewables Obligation will close on 31 March 2017.  After that date, smaller projects will have to rely on the Feed-in Tariffs regime and larger projects must compete for Contracts for Difference (CfDs) under Electricity Market Reform.  In March 2014, the Government set out its overall approach to the two and a half year  transition period when both the RO and CfD regimes are open to new projects: developers are able to choose between the two schemes (subject to certain qualifications). But subsequently DECC has become increasingly concerned that the rapid growth of the UK solar industry, supported by the “demand-led” RO, will breach the Levy Control Framework (LCF) limits on the overall amount of money that the Treasury will permit to be spent on renewable energy subsidies.  In its May 2014 consultation, DECC estimated that large-scale solar PV deployment under the RO could reach “more than 5GW by 2017”; in the response to that consultation, DECC’s “updated assessment” found that “in the absence of intervention”, up to 10GW of solar PV could deploy within this period, costing some £400m more than was allowed for in the EMR Delivery Plan and exceeding the LCF cap.

Proposals and policy decisions

The table below summarises the Government’s main proposals on RO closure for solar PV in the May consultation and the policy decisions announced in the response to consultation.


DECC has not been persuaded to change the cut-off date or open up the grace period to a wider group of projects.  Responding to “the main criticism…that any projects that can meet the grace period…requirements are unlikely to need the grace period because they will already be sufficiently advanced to secure connection by 31 March 2015”, DECC states that “the grace period will have fulfilled its purpose if it protects eligible projects that subsequently encounter unexpected events which delay their completion beyond the end of March 2015.  However, DECC very clearly has taken on board the industry’s practical objections around the evidence to be provided by those that are eligible for the grace period and has accommodated its evidential requirements to the realities of the industry.

Further consultation

In response to comments from consultees that early closure of the RO to large-scale solar would create a “cliff-edge” effect for some projects, DECC has put out a further consultation (closing on 24 October 2014) on the proposal that there should be a separate 3 month grace period (until 30 June 2015) for projects which are prevented from meeting the 31 March 2015 deadline only because they are not connected to the grid by that date.

The proposal is that such projects would have to include in their RO application:

  • a grid connection offer and acceptance and a letter from the network operator estimating or setting a date for connection of no later to 31 March 2015 (the estimated connection date);
  • a declaration by the developer that to the best of its knowledge, the project would have been commissioned by 31 March 2015 if the connection had been made by the estimated connection date; and
  • a letter from the network operator confirming that in its opinion, the failure to make the grid connection before the estimated connection date was not due to any failure on the part of the developer.

The first of these proposed requirements is open to the same sorts of objections that were made by the industry against the proposed requirement for a letter from the network operator that formed part of the May 2014 proposals.  However, DECC insists that past experience on banding review grace periods suggests that the difficulties associated with it are “not insurmountable”, and the response to consultation is careful to note that the requirement has been removed from the final policy decision on the May proposals because a letter from the network operator was considered unnecessary in that context, rather than that it would be too difficult to obtain.

What next?

DECC intends to implement the policy decisions described above in relation to RO closure through an amendment to the Renewables Obligation Closure Order 2014, to take effect on 1 April 2015.

DECC is evidently determined to do whatever it has to in order to mitigate the risk that the growth in large-scale solar PV will lead to a breach in the Levy Control Framework limits. It wants the sector to switch to the CfD regime, where the auction-based allocation process will drive down the costs of subsidy, acknowledging that the greater complexity of the CfD regime will favour the larger players in the industry.

The deadline for applications for the first CfD round is now 30 October 2014, and in recent publications both DECC and National Grid (as EMR Delivery Body) have been doing their best to make the regime user-friendly.  The table below suggests which groups of developers may need to consider making a CfD application.  If onshore wind developers (with whom solar projects must compete) are likely to avoid bidding for CfDs in the first auction since they  have until 31 March 2017 to achieve RO accreditation, it may be that solar projects stand a reasonable chance of success of being allocated CfDs later this year.


At present, for those who miss out on both the RO and a CfD from the first allocation round, the next opportunity would be a CfD allocation round in Autumn 2015.  DECC has given some indications that it is sympathetic to the proposition that the rapid development cycle of solar projects means that there ought to be solar CfD allocations every 6 months rather than every year, as for other technologies, but it also points out that more frequent auctions would not mean any increase in the overall budget.  And since 2015 is a General Election year, no promises of a further allocation round for solar can be made at present.



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Early closure of RO to >5MW solar PV projects confirmed

Market investigation: just what UK energy markets need?

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.

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Market investigation: just what UK energy markets need?