New Thinking: The Capacity Market – How did we get here?

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New Thinking: The Capacity Market – How did we get here?

MtthewThe Capacity Market – How did we get here?

Matthew Lockwood, IGov Team, 15th January 2018

This winter is the first in which Britain’s electricity Capacity Market comes into play. The Capacity Market (CM) is part of a set of policy measures introduced in 2013 known as the Electricity Market Reform. The basic case made for a capacity intervention in the early 2010s was that increasing amounts of wind power would make average wholesale prices lower as well as making periods of high prices rarer and more unpredictable, with the result that no one would invest in new capacity that could be used as back up when the wind did not blow. At the time of the development of the CM, this was all an issue for the rather distant future; in 2011 wind provided less than 4% of total electricity generated. The challenges of large swings in wind output were expected to materialise only from the mid-2020s. However, the argument was that a capacity mechanism was needed well ahead of time in order to get investment in back up capacity that would be ready when wind power became really important. The idea was that such a mechanism would provide investors with an extra, stable source of revenue and induce them to invest in the plant needed. The policy eventually adopted, the Capacity Market, involves the government (via a counterparty) holding auctions for generators and providers of demand side response and storage, with successful bidders contracted to be available to generate or turn down demand over a specified period. How much resource the government contracts depends on a methodology related to reliability standard that was set as part of the CM.

The CM has been highly controversial, being criticised on a number of grounds including: poor value for money; undermining decarbonisation of the power sector by keeping old coal on the system; failure to bring forward major investment in new combined cycle gas turbine (CCGT) plants, leading instead to a surge in new small-scale high-carbon diesel generation; failure to develop much in the way of demand side response (DSR), and too strict a reliability standard, leading to over-contracting of capacity.[i]

At IGov we have recently produced some work in progress looking at the evolution of the CM over the period from the late 2000s to 2014, trying to understand the relative roles of ideas and interests amongst government and industry in shaping the policy.

Many of the features of the CM that have attracted criticism arise from its design, and in particular the fact that it takes a ‘market wide’ approach, contracting for large amounts of capacity undifferentiated by carbon intensity or flexibility, including existing power stations. Originally, the government actually preferred a different option for the CM, known as a ‘Strategic Reserve’ (SR) approach, involving the contracting of a relatively small amount of capacity and removing it from the wholesale market. This was the official position from the early days of the development of the policy from 2010 to the end of 2011, at which point the government changed course and a market-wide design was announced. This was despite the fact that the government’s own cost-benefit analysis at the time suggested that this was far more expensive than a Strategic Reserve.

So why did the shift in approach occur? One factor was that there was a very clear message from most (although not all) of the major electricity generators’ lobby in favour of a market-wide approach. The big incumbent companies would be more likely to benefit from a wider, inclusive mechanism than a SR, but of course the basis of their argument was different. This was the idea that a strategic reserve approach would suppress wholesale market prices (especially peaks), suppressing normal incentives for investors, and leading to the need for more and more capacity needing to be contracted through the reserve (the so-called ‘slippery slope’ problem).

However, while there is evidence that this argument had some effect on decision makers, what seemed to loom particularly large in the minds of politicians and civil servants (and increasingly over the course of 2011) was the prospect of what one source described as the ‘infamous five still days in January’. This phrase refers to the possibility of a sustained period of anti-cyclonic conditions, combining low wind output with cold temperatures, and hence high electricity demand. The fear was that as the role of wind power grew larger and larger in the 2020s, when its output collapsed for several days at a time, most or all of winter peak demand would have to be met by other means. A relatively small SR resource would not be sufficient. It was this ‘volume’ argument that seems to have played the key role in moving decision makers to embrace the market-wide approach.

Was this a justified fear? It is arguable that the true extent of the sustained high-demand low-wind problem was not really known in the early 2010s; it is only recently that meteorologists have started to undertake reanalysis of longer-term data, and the increased share of offshore wind has probably helped the situation. Nevertheless, while it seems that such events have been rare historically, occurring once only every few years, they still can occur.

Having decided that this was the key issue, what is striking is that the government then proceeded to seek a solution to what would have been a problem quite far ahead in the future through a means that was very much of the present. While the CM was indeed open to any form of generation or demand side response, it was clear that the government’s intended aim was in fact to induce investment in new combined cycle gas turbine (CCGT) plants, the type of investment that has been the power sector default since the early 1990s. This is what policy makers felt comfortable with, what they felt could be depended on. It is also the case that parts of industry encouraged this thinking; for example the Independent Generators Group, a number of second-tier companies, commissioned a report by Oxera in 2011 that explicitly modelled investment incentives for new CCGT under increasing wind variability.[ii]

An irony is that in fact the CM tends to favour plant with relatively low fixed costs, even if variable costs are high, because payment is principally for availability rather than generation. This means existing plant, and where new plant are involved, it means smaller peaking plant (open cycle gas turbines) or diesel generators. This is why no new full scale CCGT plant has yet successfully stayed in the auctions, despite the government’s expectations. It seems that decision makers did not fully grasp this aspect of plant economics at the time.

However, the bigger story here is that the government took an essentially backward-looking, short-term approach to managing a potential future problem, instead of seeking to prioritise the development of the kinds of solutions that might be available far more widely, and ultimately more cheaply, in the future. These include demand side response (DSR), electrical storage, interconnection and permanent demand reduction (the last of these should not be underestimated; at the time of the development of the CM, both industry and government modelling assumed a steady growth in demand through to the 2020s at around 2% a year, but in fact demand since 2010 has fallen by almost 8%).

In the IGov study we look in detail at the treatment of DSR in the CM. Initially, Ministers and senior officials were highly enthusiastic, saying that DSR was the ‘real prize’ and ‘absolutely crucial’. However, many observers even at the time were sceptical, seeing politicians as merely giving lip-service to DSR under pressure from groups like the Regulatory Assistance Project and E3G. Certainly, once high level attention had moved on and policy development moved into the detailed stages, a number of decisions were made that seemed designed to limit rather than expand the development of DSR. Issues of concern included: very high levels of penalty for non-delivery; making it impossible for DSR suppliers to enter a special DSR Transitional Auction (TA) in 2016 if they had entered the main auction; the short duration of the TA itself (which at 1 year was insufficient to incentivise firms to invest in the equipment needed); the unsuitability of using a one-size-fits-all de-rating methodology for DSR and storage, and pre-qualification being too cumbersome and complex.

The government also made a decision on how to pay for the CM in such a way that worked against, rather than for, the development of the DSR industry. The costs of the CM are passed through to suppliers, and the original proposal was to do this in proportion to the demand covered by each supplier at the three highest half-hourly periods of demand in the year (known as the Triad). This approach would have given a real boost to the DSR industry, as suppliers would have had an incentive to encourage big industrial and commercial customers to manage demand in those periods (also reducing the amount of capacity that had to be procured). However, under intense lobbying from suppliers (who were also electricity generators), this approach was dropped and the costs of the CM were spread over 100 days in the winter instead.

The government view, encouraged by the incumbent generators, seems to have been to treat DSR with tolerance at best and suspicion at worst. In some respects, coal-fired plant could access more favourable terms than DSR. When DSR providers complained about what they argued were excessively high bid bond amounts for unproven DSR, the government actually increased the amounts under lobbying from generators.

It may well be the case that new types of resource such as DSR, storage and interconnection would not be sufficient on their own to manage potential future problems of high demand and low wind output, especially for sustained periods. Conventional thermal generation may still be needed to an extent. But these new forms, along with permanently reduced demand and other distributed resources including solar PV, could make significant contributions, and a future-facing capacity mechanism would have sought to maximise their future contribution. Since the early 2010s the rise of these options has become much clearer; there has been a major increase in solar PV and the costs of electrical storage over the scale of hours are beginning to fall rapidly. The government and the regulator are moving slowly towards embracing the prospect of a smarter more flexible electricity system, and the major incumbents are also beginning to realise where the future lies. But instead of actively helping accelerate movement towards this vision, the CM acts as a brake.

As a policy process it seems to have been the outcome of a mix of incumbents seeking to shape policy to protect their assets, and government seeking to have system security, even at the cost of gold-plating, within the familiar centralised supply paradigm. What was lacking, despite Ministerial rhetoric, was a genuinely innovative approach.

Could the process have been different, and if so, how? Our thinking on this is still preliminary, but the IGov working paper provides some initial ideas. These include increasing the self-awareness of decision-makers (especially officials) about industry lobbying, their own political incentives, and the policy paradigms in which they work, with such issues built into the development and analysis of new policies by government.

At the same time, the policy process needs to be opened up. There are of course consultations, and processes that bring government and ‘industry’ together and the development of the CM involved plenty of both. The involvement of outsiders also happened to a limited extent, for example in the development of the methodology for setting the reliability standard in the CM; the government ultimately ignored the advice of the independent panel established on this issue, but at least they cast light on the process.

However, these kinds of processes are typically dominated by incumbents, a handful of energy consultancy firms and a relatively small number of ‘experts’ who are part of the dominant energy sector culture. New entrants and observers with unorthodox views are sometimes included, but more often than not as a fig leaf. A true opening up would involve government ensuring that actors from the new energy economy had a more equal representation, and if this means providing resources to allow this to happen because new actors are smaller and less able to commit the time required then this should also happen. It would also involve officials reaching out beyond the usual suspects in terms of independents in academia and elsewhere. Good policy making should avoid group think and embrace challenge. In a heavily male sector there is a gendered and indeed sexist aspect to this, with the views of men in senior posts familiar to officials tending to automatically receive a lot of weight and authority, while sometimes avoiding scrutiny.

Ensuring a more level playing field, and trying to decentralise the process to avoid groupthink might also extend to reports presenting evidence, analysis and modelling. These can have some influence on government thinking, but the resources to produce such reports in time to have an effect on the policy process is distributed highly unequally. Larger richer organisations (i.e. incumbent companies or their associations) are in a better position than others, and government could consider providing some analytical budgets to get other views.

Industry lobbying and dominant policy paradigms are powerful forces, unlikely to go away any time soon. The kinds of corrective measures suggested above will not completely offset them. But they might help create a better balance in policy processes, and lead to more forward thinking in energy policy. Together with other reforms described in the IGov framework, we believe that they would also help create a greater legitimacy for the transformation of the energy system, which is a complex process across many dimensions.


[i] This winter’s figures lend support to the last point; National Grid predicts that the loss of load expectation (LOLE) for this winter, i.e. the likelihood of the lights going out expressed in average expected hours without power, will be 0.01 hours per year. This is far lower than the reliability standard for the Capacity Market, set at 3 hours per year.

[ii] The Oxera paper can be found as a submission from the Independent Generators Group at

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