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On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Things may be starting to move a bit faster in the world of GB energy policy after what you could be forgiven for thinking was a Brexit-induced slowdown. On 24 July 2017, the UK government’s Department for Business, Energy and Industrial Strategy (BEIS) and the energy regulator Ofgem published a number of documents that reveal their evolving thinking about the future of the GB electricity system. These publications followed on from some significant initiatives by Ofgem and National Grid. This is the first of series of posts assessing where all this activity may be leading.

The full holiday reading list from 24 July was as follows.

Other recent official publications that are relevant in this context and referred to below include:


The Response and the Plan cover a broad range of subjects; many of the other documents are rather more monothematic. We will follow the topic headings in the Response, referring to the other documents where they are relevant. However, it is helpful to start by framing some of the key themes underlying this area of policy by turning to the Pöyry / Imperial Report.

The CCC has recommended that in order to achieve the ultimate objective of the Climate Change Act 2008 (reducing UK greenhouse gas emissions by 80% by 2050), the carbon intensity of the power sector should fall from 350 gCO2/kWh to about 100 gCO2/kWh by 2030.  Pöyry / Imperial observe that in any future low carbon electricity system, “we should anticipate:

  • a much higher penetration of low-carbon generation with a significant increase in variable renewable sources including wind and solar and demand growth driven by electrification of segments of heat and transport sectors;
  • growth in the capacity of distribution connected flexibility resource;
  • an increased ‘flexibility’ requirement to ensure the system can efficiently maintain secure and stable operation in a lower carbon system;
  • opportunities to deploy energy storage facilities at both transmission and distribution levels; and
  • an expansion in the provision and use of demand-side response across all sectors of the economy.

System flexibility, by which we mean the ability to adjust generation or consumption in the presence of network constraints to maintain a secure system operation for reliable service to consumers, will be the key enabler of this transformation to a cost-effective low-carbon electricity system. There are several flexibility resource options available including highly flexible thermal generation, energy storage, demand side response and cross-border interconnection to other systems.”.

This explains why technologies and mechanisms that can increase system flexibility are a dominant theme in current GB electricity sector policy-making. But Pöyry / Imperial then go on to discuss the extent of the uncertainty that, based on their modelling, they consider exists about how much the main types of flexible resource may be needed on the way to achieving the CCC’s target. This is clearly shown in the table, reproduced below, setting out their assessment of “the required range of additional capacity of different flexible technologies to efficiently meet 2030 carbon intensity targets”.

With the exception of interconnectors, the table shows the amounts of each flexible technology in the low and high scenarios, at each of the three dates, varying by a factor of 5 or more. As regards interconnectors, an illustration of the potential uncertainties in the different scenarios modelled by National Grid in FES 2017 is provided by the two FES 2017 charts below.

Source: National Grid, FES 2017

Source: National Grid, FES 2017

The need for more flexible resources is clear, and Pöyry / Imperial calculate that integrating them successfully, as compared to the use of “conventional thermal generation based sources of flexibility”, could save between £3.2 billion and £4.7 billion a year in a system meeting the CCC’s 2030 target.  But it is also clear that there are many different possible pathways that could be followed to achieve this level of flexibility, and that even if we get to 100 gCO2/kWh by 2030 – which is by no means guaranteed – there will inevitably be, at least relatively speaking, “winners” and “losers” in terms of which flexible technologies, and which individual projects, end up taking a greater or lesser share of what could be loosely called the “flexibility market”.

What will determine who wins or loses out most in this competition will be the same factors as have driven changes in the generation mix in the UK and elsewhere in recent years – in particular, the interplay of regulation and technological change.  In 2016, as compared with 2010, the UK consumed 37% less power generated from fossil fuels and more than twice as much power generated from renewable sources: see the latest Digest of UK Energy Statistics. That shift is the result of subsidies for renewable generating capacity and reductions in the cost of wind and solar plants combined with other regulatory measures that have added to the costs of conventional generators. But whereas in the initial stages of decarbonising the generating mix, the relationship between regulatory cause and market impact has been relatively straightforward, making policy to encourage flexible resources is more complex: it is like a puzzle where each piece put in place changes the shapes of the others.

This is perhaps why the actions recommended by Pöyry / Imperial as having a high priority, summarised below, all sound difficult and technical, and require a large amount of collaboration.

Pöyry / Imperial recommended high priority actions for the flexibility roadmap (emphasis added)
Action Responsible Time frame
Publish a strategy for developing the longer-term roles and responsibilities of system operators (including transitional arrangements) that incentivises system operators to access all flexibility resource by making investments and operational decisions that maximise total system benefits. Ofgem in conjunction with industry 2018
Periodical review of existing system planning and operational standards for networks and generation, assessing whether they provide a level-playing field to all technologies including active network management and non-build solutions (e.g. storage and DSR), and revise these standards as appropriate. Industry codes governance and Ofgem Initial review by 2019
Review characteristics of current procurement processes (e.g. threshold capacity level to participate, contract terms / obligations) and the procurement route (e.g. open market, auctioning or competitive tendering) that enable more efficient procurement of services without unduly restricting the provision of multiple services by flexibility providers. Ofgem in conjunction with SO, TOs and DSOs By 2020
Assess the materiality of distortions to investment decisions in the current network charging methodology (e.g. lack of locational charging, double-charging for stored electricity), and reform charging methodology where appropriate. SO, DSOs and Ofgem By 2020
Assess the materiality of distortions to investment decisions in the absence of non-network system integration charging (i.e. back up capacity and ancillary services) and implement charging where appropriate SO, DSOs and Ofgem By 2020
Publish annual projections (in each year) of longer-term future procurement requirements across all flexibility services including indication of the level of uncertainty involved and where possible location specific requirements, to provide greater visibility over future demand of flexibility services SO and DSOs 2020 onwards


We looked at the current issues facing the UK energy storage sector and recent market developments in some detail in a recent post, so we will not dwell too much on the background here.

Storage – conceptually if not yet in practice – is the nearest thing there is to a “killer app” in the world of flexible resources.  It has the potential to be an important asset class on a standalone basis, but it can also be combined with other technologies (from solar to CCGT) to add value to them by enabling their output to match better the requirements of end users and the system operator.

In GB, as in a number of other jurisdictions, there is intense interest in developing distributed storage projects based on battery technology (for the moment at least, predominantly of the lithium ion variety), and a strong focus on doing so in a way that allows projects to access multiple revenue streams. There is also a general feeling that the regulatory regime needs to do more to recognise storage as a distinct activity but at the same time to do less to discriminate against it in various ways.

So, what do the Response and the Plan tell us about the vision for storage?

  • The Response points to National Grid’s SNaPS work, “which specifically considers improving transparency and reducing the complexity of ancillary services”.
  • It also points to work that has been done and/or is ongoing to clarify how storage can be co-located with subsidised renewable electricity generating projects and to provide guidance on the process of connecting storage to the grid. BEIS / Ofgem note that they see no reason why a network operator should not “promote storage…in a connection queue if it has the objective of helping others…to connect more quickly or cheaply”, and point out that Ofgem can penalise DNOs who fail to provide evidence that they are engaging with and responding to the needs of connection stakeholders.
  • BEIS / Ofgem highlight the proposals in the TCR Consultation on reducing the burden faced by storage in terms of network charges, notably the removal of demand residual charges at transmission and distribution level, and reducing BSUoS charges, for storage. A response to that consultation is to be published “in the summer”.
  • In relation to behind the meter storage, BEIS / Ofgem observe that at present: “technology costs and the limited availability of Time of Use (ToU)/smart tariffs are greater barriers…than policy or regulatory issues”. This may invite the response from some readers that it is precisely a matter for policy and regulation to promote time of use / smart tariffs: the CEPA Report makes interesting reading in this context.
  • BEIS / Ofgem “agree with the view expressed by many respondents” that network operators should be prevented from directly owning and operating storage” whilst slightly fudging the extent to which this may already be the case as a result of existing EU-based rules on the unbundling of generation from network operation, but “noting” the current EU proposals in the November 2016 Clean Energy Package to prohibit ownership of storage by network operators except in very limited circumstances and with a derogation from the Member State.
  • Flexible connections “should be made available at both transmission and distribution level”.
  • BEIS / Ofgem agree that the lack of a legal definition or regulatory categorisation of storage is a barrier to its deployment. Legislation will be introduced to “define storage as a distinct subset of generation”. This will enable Ofgem to introduce a new licence for storage before the changes to primary legislation are made. The “subset of generation” approach will also “avoid unnecessary duplication of regulation while still allowing specific regulations to be determined for storage assets” – such as whether the threshold for requiring national rather than local planning consent should be the same for storage as for other forms of generation.
  • The prospect of storage facilities benefiting, as generation, from relief from the climate change levy is also noted – although since the principal such relief (for electricity generated from renewable sources) no longer applies, this may be of limited use to most projects.

What the Response says about storage is typical of its approach to most of the issues raised in the CFE. If one wanted to be critical, it could be said that although, on the whole, BEIS / Ofgem engage with all the points raised by stakeholders, there is rarely an immediate and decisive answer to them: there is always another workstream somewhere else that has not yet concluded that holds out the prospect of something better than they can offer at present. On the other hand, perhaps that just highlights the points implicit in the Pöyry / Imperial Report’s recommendations: no one body can by itself create all the conditions for flexibility to be delivered cost-effectively, and it will be difficult fully to judge the success of the agenda that BEIS and Ofgem are pursuing for another two or three years.

But wait a minute.  On the same day as it issued the Response and the Plan, BEIS also published the CM Consultation. The sections of the Response on storage say nothing about this document, but it is potentially the most significant regulatory development in relation to storage for some time.

  • The Capacity Market is meant to be “technology neutral”. Above a 2 MW threshold, any provider of capacity (on the generation or demand side) that is not in receipt of renewable or CCC subsidies can bid for a capacity agreement in a Capacity Auction that is held one year or four years ahead of when (if successful) they may be called on to provide capacity when National Grid declares a System Stress Event.
  • A key part of the calculations of any prospective bidder in the Capacity Market, particularly one considering a new build project, who is hoping that payments under a capacity agreement will partly fund its development expenses, is the de-rating factor that National Grid applies – the amount by which each MW of each bidding unit’s nameplate capacity is discounted when comparing the amount of capacity left in the auction at the end of each round against the total amount of capacity to be procured, represented by the demand curve. Some of the de-rating factors applied in the 2016 T-4 Auction are set out below.
Technology class Description De-rating Factor
Storage Conversion of imported electricity into a form of energy which can be stored, the storing of the energy which has been so converted and the re-conversion of the stored energy into electrical energy. Includes pumped storage hydro stations. 96.29%
OCGT / recip Gas turbines running in open cycle fired mode.
Reciprocating engines not used for autogeneration.
CCGT Combined Cycle Gas Turbine plants 90.00%
DSR Demand side response 86.88%
Hydro Generating Units driven by water, other than such units: (a) driven by tidal flows, waves, ocean currents or geothermal sources; or (b) which form part of a Storage Facility. 86.16%
Nuclear Nuclear plants generating electricity 84.36%
Interconnectors IFA, Eleclink, BritNED, NEMO, Moyle, EWIC, IFA2, NSL (project specific de-rating factors for each interconnector) 26.00% to 78.00%
  • In the table above, storage has, for example, a de-rating factor approximately 10 percentage points higher than DSR and hydro and, if successful at auction, would receive correspondingly higher remuneration per MW of nameplate capacity than those technologies.
  • The typical potential storage project competitor in the Capacity Market is now more likely to be a shed full of batteries than a pumped hydro station. This has prompted industry participants to question whether such a high de-rating factor is appropriate to all storage. Ofgem, in considering changes to the Capacity Market Rules proposed by stakeholders, declined to take a view on this, deferring to BEIS.
  • BEIS, in the CM Consultation, finds merit in the arguments that (i) System Stress Events may last longer than the period for which a battery is capable of discharging power without re-charging; (ii) batteries degrade over time, so that their performance is not constant; (iii) a battery that is seeking to maximise its revenues from other sources may not be fully charged at the start of a System Stress Event. It proposes to take these points into account when setting de-rating factors for the next Capacity Auction (scheduled to take place in January 2017, and for which pre-qualification is ongoing), and splitting storage into a series of different categories based on the length of time for which they can discharge without re-charging (bands measured in half-hourly increments from 30 minutes to 4 hours). Bidders will be invited in due course to “self-select” which duration-based band they fall into.
  • Of course, deterioration in performance over time is not unique to batteries – other technologies may also perform less well by the end of the 15 year period of a new build capacity agreement than they did at the start. And, as with other technologies, such effects can be mitigated: batteries can be replaced, and who knows by what cheaper and better products by the late 2020s. However, a fundamental difficulty with the CM Consultation is that it contains an outline description of a methodology, based around the concept of Equivalent Firm Capacity, but no indicative values for the new de-rating factors.
  • It may be that BEIS’s concerns about battery performance have been heightened by the fact that the parameters for the next Capacity Market auctions show that it is seeking to procure an additional 6 GW of capacity in the T-1 auction (i.e. for delivery in 2018). There is reason to suppose that battery projects could make a strong showing in this auction, given their relatively quick construction period and the number of projects in the market, some of which may already have other “stacked” revenues (see our earlier post). Clearly it would be undesirable if a significant tranche of the T-1 auction capacity agreements was awarded to battery storage projects which then failed to perform as required in a System Stress Event.
  • It is arguable that the three potential drawbacks of battery projects are not necessarily all best dealt with by de-rating. For example, the risk that a battery is not adequately charged at the start of a System Stress Event is ultimately one for the project’s operator to manage, given that it will face penalties for non-delivery. Nor is it only battery storage projects that access multiple revenue streams and may find themselves without sufficient charge to fulfil their Capacity Market obligations on occasion: pumped hydro projects do not operate only in the Capacity Market, and even though they may be able to generate power for well over four hours, they too cannot operate indefinitely without “recharging”.  Moreover, National Grid is meant to give 4 hours’ notice of a System Stress Event, which may provide battery projects with some opportunity to prepare themselves.
  • However, the real objection to the de-rating proposal is not that it is not addressing a potentially real problem, but that it is only doing so now – given that the issue was raised by stakeholders proposing Capacity Market Rules changes at least as long ago as November 2016 – and with no published numbers for consultees to comment on.
  • The de-rating proposal illustrates a fundamental feature of the flexible resources policy space: one technology’s problems provide an up-side for competing technologies. Self-evidently, what may be bad news for batteries is good news for other storage technologies to the extent that they are not perceived to have the same drawbacks.
  • Seen in this light, the CM Consultation appears to be the main (perhaps only) example of a policy measure that supports the “larger, grid-scale” storage projects (using e.g. pumped hydro or compressed air technology) about which the Response has relatively little to say. However, a few percentage points more or less on de-rating may not make up for the lack of e.g. the “cap and floor” regulated revenue stream advocated by some for such projects.

In Part 2 of this series we will focus on the role of aggregators (featuring the analysis in the CRA Report on independent aggregators) and the demand-side more generally.

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On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

They say a picture is worth a thousand words, so rather than writing a lengthy post on the provisional results of the four-year ahead GB Capacity Market Auction, published on 9 December 2016 by National Grid, we are focusing on two pictures and inviting you to spot the difference between them.

The first, immediately below, shows the progress of bidding in the 2016 auction.  In simple terms:

  • the process starts with all prequalified potential providers of capacity “in” at the cap price of £75/kw/year and the price then goes down by £5 with each round;
  • the auction clears when the purple line, whose progress from right to left shows how many bidders are left in after each round, converges with the red line “demand curve” drawn on the graph by the Government as part of the auction parameters;
  • all bidders still in at that point get a capacity agreement at the clearing price.

The big right to left moves occurred when the price moved between £35 and £30 and below £25.  In particular, each of these moves saw 6GW of capacity drop out.

2016 progress of bidding chart

Now look at the equivalent presentation of results from last year’s auction.  The purple line slopes more gradually, and the biggest right to left moves happen much earlier on in the bidding, between £60 and £50.  (The picture from 2014 is very similar to the 2015 one.)

2015 progress of bidding chart

It’s only an educated guess, of course, but it seems likely that much of the big leftward shifts in both auctions represented the exiting of bidders with plans to build large-scale proposed combined cycle gas turbine (CCGT) plants.  As a group, they are almost certain to have higher per MW development costs than other categories of new build projects competing for capacity agreements (small gas or diesel projects based on reciprocating engines, open-cycle gas projects, or battery based storage).  And the amount of capacity involved corresponds roughly with the big CCGT projects in the auction.

If the above is correct, why where proposed new big CCGT plants apparently prepared to tolerate prices almost 50% lower this year?  Perhaps they were hoping that a price between £30 and £35 would be where the auction cleared this time, on the basis that:

  • the clearing price is effectively set by the bidding behaviour of a sub-set of the smaller-scale, distribution-connected, fossil fuel generators;
  • on top of their power sales revenue, these smaller-scale generators have two main projected sources of income: capacity agreements and so-called residual demand TNUoS benefits;
  • Ofgem has issued what amounted to a warning that residual demand TNUoS benefits could be very sharply reduced by the time plants bidding in this year’s auction are commissioned;
  • the anticipated loss in residual demand TNUoS benefit revenue would be enough to push the smaller-scale generators to want a significantly higher capacity market price than the clearing prices seen in 2014 and 2015, both of which were below £20;
  • lower gas prices and slightly higher projected wholesale power prices may make a low capacity market price more bearable for CCGT plant, and there may other ways to mitigate merchant risk through innovative trading arrangements.

Maybe Ofgem’s warning wasn’t strong enough.  Maybe the smaller-scale generators reckon that Ofgem’s bark will turn out to have been worse than its bite on this.  In any event, the outcome has shown that for now, simply expanding the amount of capacity to be procured under an auction, as the Government appeared to be hoping when it adopted a limited change of approach to the 2016 auction, isn’t enough to ensure that some new GB CCGT plant is financeable and gets built.  Instead, a somewhat higher price will be paid to all successful bidders, including existing plant, for a larger amount of capacity than the Government thought we really needed.

As usual on these occasions, the Government has professed itself happy with the result of the auction, and it is fair to note that of the two new gas-fired plants with a capacity of around 300 MW that have been successful in the auction, one is described in the Capacity Market register as being CCGT.  But if a new generation of big CCGT plants is an important part of our new lower carbon power mix, there is some way to go.  A possibly more promising approach to using a capacity market to stimulate new CCGT build is suggested by the European Commission’s recent Winter Package of Energy Union proposals: set a date beyond which existing coal-fired plant will be ineligible for capacity market payments.  This is not among the options canvassed in the Government’s recent consultation on achieving the closure of coal-fired plant by 2025.  There would of course be an element of risk in adopting such an approach (coal plant might stay open because it can still make money without a subsidy, resulting in overcapacity, or alternatively coal plant might close immediately, before the new CCGT plant is built, leaving a generation gap), but it might be worth considering.

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Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

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?