i)  UK energy markets are beset by a number of actual and potential market failures. This submission tries to focus on those that are most relevant to institutional questions, including regulation, and issues for infrastructure investment and for wholesale and retail markets. It also concentrates on power as the sector critical to low carbon transitions, although some of the issues for power will have implications for, or a read across to, other sectors.

ii) Stemming from the objective of controlling CO2 emissions, the biggest single market failure is the absence of adequate carbon pricing. This failure can be addressed through carbon taxes or more effective and flexible emissions trading schemes, and the main obstacles are well known. But with or without resolution of carbon pricing questions, there are several less familiar sources of market failure within the sector. These stem from:

·         General features common to much if not all infrastructure investment, and the level of reassurance required by infrastructure investors for large long life projects.

·         Complex nature of the industry requiring real time command and control, as well as coordination between generation and transmission (and increasingly distribution).

·         Multiple interactions with the technical characteristics of low carbon generation, very different from those of the fossil plant for which existing structures were designed.  

·         Weaknesses already embedded in existing conventions and assumptions underpinning both wholesale and retail market arrangements.

iii)  Resolution of these questions, in the context of wholesale transformation of the energy sector, will depend on finding a “system architecture” – combining technical, markets, regulatory and institutional features to accommodate a sector undergoing major changes in its mode of operation. Particular resolutions suggested here indicate some combination of a central purchasing function, use of properly structured contracts under which the system operator would schedule and dispatch plant, and use of sophisticated metering to permit abolition of the load profiling and averaging that characterises the current retail market. 

iv)  The government has de facto become a central purchaser in the power sector. A central purchaser is almost certainly part of the answer, but the priority should be to ensure the role is performed well. A technically and commercially competent agency at arm’s length from government, with a degree of regulatory oversight, should be considered as an option. Inter alia this agency would conduct capacity auctions and define the nature of the contractual obligations for generation and storage facilities and some elements of consumer load.

v)  The technical and economic characteristics of low carbon (and storage) technologies are fundamentally different from those of fossil generation, notably in terms of zero marginal cost, inflexibility and intermittency. Current wholesale markets were conceived and designed for fossil generation (by and for fossil generators) and will increasingly cease to be fit for purpose in a low carbon power sector. These market arrangements are likely to need review in the next few years, and we should anticipate a larger role for any system operator(s).

vi)  Current market arrangements and conventions that govern the onward sale of electricity to retail consumers have had the effect of inhibiting innovation in retail supply, eg in the provision of more cost reflective tariffs and different definitions of the services provided to consumers. They will also inhibit trends towards more decentralised generation and storage. Given the technical possibilities in metering and control, these obstacles can be removed. 

vii) This submission also considers the Committee’s specific questions from this perspective.


The Committee’s first specific question defines the context for this submission. What are the key economic challenges for the energy market which the Government must address over the next decade?    

The fundamental challenge for the energy sector is that low carbon objectives require transformative change across several sub-sectors of energy production and use. The largest in scale are the power sector, transport (notably via electric vehicles or hydrogen), and the heat sector. This submission focuses on power partly because it has the most immediate challenges and partly because its transformation is also critical to the other two. Large increases in generation output and capacity are likely to be required for future transport (eg battery charging) and for heat (heat pumps or district heating).  

The role of the power sector is therefore central in the short, medium and long term. Early decarbonisation is a precondition for successful later decarbonisation of transport and heating.   But although the power sector is the main concern of this submission, we should note that there are also major challenges particular to transport and heating. 

Transport. This is still dominated by road transport. However motor manufacture is an international or global industry, so that the pace and detail of technical change will be determined on an international stage. The immediate challenge for the UK government and industry may therefore be mainly about influence on international market and regulatory developments. Most recently it is European regulation that has been of the most immediate concern to the British motor industry, whether from an export or import perspective. Maintaining UK influence is therefore a significant challenge both for the UK motor industry and in terms of low carbon objectives.

Heating. Heating poses particular technical challenges for the power sector, given its scale and the seasonal, temperature dependent nature of heat load. But it has its own regulatory and institutional challenges. Many of the scenarios that describe how low carbon targets might be met depend on widespread introduction of district heating schemes, typically with combined heat/power generation. This is not only a major infrastructure investment in local pipe networks (to carry hot water), of which the UK has very limited experience. It also implies a degree of collective choice over heating method for a large part of the population. Institutional questions will arise for the ownership, management and regulation of municipal district heat networks – local monopolies outside the OFGEM framework. Although the decarbonisation of heat will not be achieved quickly, it has been widely assumed that the foundations will need to be laid in the next decade.

The Investment Challenge

The investment requirements for transformative change across the sector are very large, but scale per se is not the main problem. French experience of very successfully decarbonising power in the 1980s and 1990s tends to support this assertion, although clearly the challenges in achieving this through private sector investment will be different from those of a state corporation.

However it is already clear that future energy systems will be dominated by capital costs to an extent even higher than for existing energy systems. In consequence the cost of capital becomes a factor of absolutely fundamental importance in making the necessary transition affordable. One key economic challenge is therefore creating market, regulatory and institutional arrangements that provide confidence to infrastructure investors (eg pension and sovereign wealth funds), by eliminating regulatory and policy uncertainties. This should result in a relatively modest cost of capital for what are essentially “low beta” utility businesses. 

Market Failure and “System Architecture”. 

The overarching challenge is to find the right combination of regulated monopoly or public guarantee (to achieve a lower “utility” cost of capital), competitive markets and incentives (to promote efficiency and innovation), policy intervention (to meet climate or other social and political objectives), and technically competent institutions (to manage complex interdependencies). A major part of this, though not the only part, is devising means to overcome the several sources of actual or potential market failure that are present for the sector.


The Committee has identified market failure as a key theme for its investigation. This submission begins with some of the main sources of actual or potential failure for the sector. These can also interact and be mutually reinforcing. They are:

·         The nature of the CO2 externality, the “social cost of carbon”, and the problem of incentivising low carbon objectives through current market mechanisms. This is the biggest single market failure.

·         Familiar issues of infrastructure investment: of providing private investors with sufficient policy and regulatory certainty on their future revenue streams.

·         Technical features peculiar to the power sector that depend on real time command and control functions to maintain secure and stable power to consumers; the interaction of these with the newer generation technologies.

·         Weaknesses in existing electricity market structures (particularly post 2000) with inadequate incentives for capacity, even for fossil-based systems. 

·         A general problem of coordinating investment, and deciding the right mix of assets and other features, both for the power system itself and across the energy sector as a whole. This feature is reinforced by the more complex technical constraints pertaining to low carbon generation.

·         Features of current market structures and conventions that fail to translate underlying cost structures into consumer tariffs that will encourage “efficient” modes of consumption. Current arrangements have inhibited innovation in, for example, smart metering and novel approaches to supply.

The author has addressed some of these topics in more depth elsewhere, most recently in a piece recently published by the Energy Technologies Institute[1], but the main points of analysis and conclusions can be summarised as follows.

Point I.  Putting a price on carbon emissions, consistent with the policy imperative to mitigate climate change, ought to be a priority. Inter alia it can improve the “carbon efficiency” of existing assets, help incentivise research and investment, and reduce energy consumption. The difficulties are also well known, and what ought to be an important mechanism, the EU ETS, has so far failed to deliver prices adequate to incentivise the transformative changes that are required. The government, like others in Europe, has resorted to more direct interventions. However with or without satisfactory resolution of carbon pricing questions, the government will still face several other sources of market failure within the sector, which would not be removed even with a realistic carbon price

Point II. Obtaining investment in new capacity at an acceptable cost of capital, appropriate to what is in capital market terms a “low beta” utility sector with low market correlated risk, depends on providing infrastructure investors with assurance on a number of uncertainties that are outside their control, including policy, regulatory and market structure uncertainties. Historically this has normally been achieved through measures that involve strong components of vertical integration into relatively stable downstream markets, regulated monopoly, long term contracts with secure counterparties, government guarantee, public ownership or some combination of some of all these. This traditional analysis of the economics of the power sector continues to be true. It is however reinforced by the uncertainties around policies for the sector, including those that relate to carbon prices. 

This implies a continuing important role for government in the sector, and it will almost inevitably continue to get drawn into questions of technology choice and support for major investments. There is a strong case for an arms-length agency with professional sector expertise to deliver this role. 

Point III.  There are specific features of wholesale power markets that mean they fail to deliver a set of price signals that works both to deliver efficient operation of existing assets (“sweating the assets” through the merit order) and to provide signals to incentivise investment in new capacity. Technical and economic features of the various forms of low carbon generation, including zero short run marginal cost, inflexibility constraints, multi-period storage, intermittency, and changes in scale, will all reinforce and accentuate these problems. It is likely that existing wholesale markets will increasingly cease to be “fit for purpose”, and subject to ad hoc fixes that further undermine their position as a basis for an efficient sector.

Wholesale and spot prices are likely in a low carbon system to have a much smaller role in delivering efficient and secure operation of the current stock of sector assets. The role of the system operator, in dispatching plant and making operational choices, within a set of available options that includes demand side response and the contractual commitments of the existing stock of plant, is likely to expand.

Point IV.  Capacity markets are widely seen as part of the answer to the issue of securing new investment and adequate capacity on a competitive basis. This immediately raises the question of exactly who (and with what expertise) determines the parameters for any capacity auction, and how that auction is conducted. This requires decisions on who decides how much capacity is required, when it is needed, what constitutes capacity, how it is measured and monitored, how it is remunerated (eg under long term contracts) and so on. 

Capacity markets in the UK have the government acting as a central purchaser, a role already implicit in its support for renewables and nuclear investment. This suggests formal recognition of the need for a central purchasing agency, with a strong case to make it at arms length from government, with at least some degree of insulation from political interventions and interest group lobbying.

Point V.   Engagement of the consumer in demand response programmes is widely anticipated as part of the future power sector, and along with storage, one of the necessary responses to intermittent or inflexible sources of generation. Current arrangements, which average consumption load profiles across categories of consumer, do not allow for the exploitation of advances in metering, communications and control technologies which could transform the “consumer offering”, the way in which consumers buy and use power. They will need re-design as part of a new architecture for the sector.

Point VI. Decentralisation of significant and increasing parts of generation and storage facilities for the sector also raises related issues. Inter alia this will put a much larger onus on the operators of local distribution networks to balance local loads and local generation, without necessarily reducing the importance of the national system, which will continue to be an essential back-up and a means of exploiting diversity between different sources of intermittent power. This changes in fundamental ways the business model of conventional (local) network utilities, inter alia placing a big emphasis on the structure of network charges. This represents a major change from the status quo, not least because it undermines the traditional practices of basing network tariffs mainly on simple averaging of costs over all kWh.

These points add up to the need for a comprehensive re-thinking of the “system architecture” for the power sector and most likely for the energy sector more widely. System architecture in this context means the totality of arrangements for the sector that determine where technical and operating decisions are made, which parts of the sector are primarily based on competitive markets or on coordination and policy intervention, and the details of regulatory and market structures. 

This submission remains neutral on questions of technology choice, and is consistent with “consensus” views of a balance between nuclear, CCS and renewables. It is also neutral on the issue of public vs private ownership. The key issues are apportioning and reconciling the roles of competition, coordination and command and control elements required for the sector, and necessary policy interventions required for ambitious emissions targets.


Has the market and the Government responded effectively to changes in external circumstances, such as significant shifts in technology and prices?  

De facto very significant areas of decision making have moved from notional reliance on market forces to actual dependence on government decisions. Little or no major generation investment is anticipated without some form of direct government support or guarantee, either through feed-in tariffs or long term contracts. Moreover the introduction of capacity auctions, prima facie a market mechanism, is itself no more than the institution of a form of central purchasing arrangement, since a central body has to specify how much capacity is required and to define its technical requirements. A competitive market to supply capacity will still operate of course, but it will operate within parameters laid down by a central agency.

A positive perspective on this is that the government has clearly recognised the need to intervene, in order to deal with some of the market failures identified above, including weaknesses in current market structure. A more critical perspective is that it may lack the technical and institutional competences to intervene effectively and efficiently, and that this not a suitable role for a government department. In my view there is a strong case for this role to be carried out by an arms-length agency. This could take various forms, including that of a central purchasing agency or augmenting the responsibilities of a body such as the National Grid. 

Markets themselves, in the context of the power sector, are unlikely to be able to adapt to changing external circumstances of the kind we are observing, and it will rarely be in the interest of incumbent participants to change the rules. Previous changes to market structure and design, including the 1990 structure and the 2000 NETA reforms, have been the result of major policy and regulatory interventions.

Meanwhile other issues are surfacing. These include the increasing failure of conventional wholesale markets to deliver wholesale prices that can reward capacity, and concern that these prices may not even be compatible with efficient operations. There is a risk that these problems will provoke a series of ad hoc interventions, special one-off rules, and “patch-ups” that fail to address the underlying issues.

Finally there is a strong body of opinion (not just in the UK) that the future of the power sector, and the energy sector as a whole, involves a bigger role for decentralised power generation, more decentralised decision making within local and regional distribution networks, and more emphasis on consumers as active market participants. This would have a profound impact on the location of decision making and what constitute appropriate or viable structures for the future, but change is only likely to occur as the result of regulatory or other intervention, preferably based on a clear vision of the “system architecture” – the mix of technical features, competitive market content and regulation – that is most appropriate to UK energy needs.

What are the emerging technologies which could materially change the energy market over the next decade and beyond? 

Virtually all the low carbon generation technologies have characteristics that will materially change the energy market, most obviously because the technical and economic characteristics of low carbon generation undermine the assumptions on which the conventional wholesale markets are predicated.  Zero or negative marginal costs, the dominance of capital costs, and different operating constraints, are all relevant examples.

Storage is also rapidly emerging as a key factor in analysis of viable energy futures. This includes but is not confined to developments in battery technology. In a power system context, storage of power, even for relatively short periods, has obvious implications for the ways in which current wholesale markets operate. 

Looking further ahead we should also anticipate the possible effects of two particular possibilities. It may be premature to describe them even as emerging technologies, but both are of huge potential significance, both as technical solutions and in their impact on our conceptions of the energy market.

One is a solution (at acceptable cost) to the problem of seasonal storage, a role which batteries and hydro storage currently seem unlikely to fulfil. The most likely answer is chemical storage of energy, eg conversion of electrical power to hydrogen, or better still further conversion to a liquid fuel or a more amenable gas. This could in principle transform the market by resolving many of the real time balancing, seasonal and security problems, including the intermittency problem (for renewables), and make energy conform more closely to the model of conventional commodity markets.

The other is a solution for carbon sequestration. The “zero carbon” future implied by the Paris agreement almost certainly implies net extraction of CO2 from the atmosphere. The only currently viable technology for this is carbon capture and storage (CCS) although other more esoteric ideas have been put forward. The potential importance attaching to zero carbon, however, suggests that the cost of carbon sequestration technologies might ultimately attach a much more well-defined cost/value to CO2 emissions.

How should the Government promote research and development- could any shift in public funding improve the efficiency of the energy market?

Prima facie the efficiency of the energy market per se depends not on funding but on regulation, structure and governance, ie system architecture.  However if one were to look for areas where technical advance could have the biggest impact on market efficiency per se then it is the consumer related area – metering, automated control of consumer loads, etc – that is likely to be the most significant.

How long might it take for new technologies to displace the established capital stock? 

French experience demonstrates there can sometimes be very few barriers to a comparatively rapid transformation of the capital stock, even in power generation. France moved from high dependence on oil-fired and fossil generation to a near-zero carbon power sector over a period of less than two decades (1977-1995). And the UK’s movement from coal to gas has also been quite rapid.

What should the future balance between the roles of the public and the private sector be? 

Overall the future will almost certainly require higher levels of government involvement in setting policy objectives for the energy sector, in defining new institutional architectures for the operation of markets, and to some degree in underwriting key infrastructure developments. 

However the balance between public and private, at least in terms of ownership and management, is not the most important question. The key question for system architecture is the balance between traditional “command and control” functions for the sector (many still retained by the system operator), regulated monopoly, and segments of the sector open to various forms of competition. 

Another major factor is the growth in decentralised generation and storage. This has been widely perceived as a significant threat to the business model, regulated monopoly with guaranteed cost recovery from a secure customer base, of local distribution networks.

The preferred direction of travel should probably be towards more explicit policy intervention in relation to generation investment, system operation based on a combination of command and control and contractual commitments made by  generators (who may have competed for their long term contracts in the first instance), and much more effective competition in retail supply where existing market arrangements have largely stifled the incentives for innovation in more sophisticated metering and “consumer offerings”.

Similar issues arise for the heat sector in the context of this and the next question. The nature of district heating suggests that actual ownership and control should be at local or municipal level, but the scale of development needed and the low level of current UK expertise in this field suggests that there is a case for a national body, again at arms length from government, to provide a kick-start for district heating programmes.

Is further expertise needed within Government to understand the issues and to negotiate with external investors and suppliers?  

Yes. The government has taken on a de facto role as the main planner of the power system and as the main decision maker on choice of generation technology. But, while it may be well equipped in strategic terms, it is not clear that it has been able to develop the necessary technical competence that would allow it to perform the purchasing role effectively and to deliver the best outcomes. This is in any case not a role well suited to a government department and should ideally be assumed by an arms-length agency, which might for example act as the main purchaser for new capacity.

National Grid is the entity that currently comes closest to having the responsibilities and expertise appropriate to this task, given its position as system and transmission operator, but there are other options.

Are returns for private investment in the sector adequate or excessive? How should the Government attract sufficient investment?  

The market failure arguments above suggest that current returns will tend to be quite poor for new investment in generation (other than under long term contracts secured at the outset). This reflects the tendency of the wholesale market price to be dominated by short run marginal costs, providing inadequate incentives for capacity. At the same time margins and returns appear rather large in the retail supply businesses[2], which requires little or no capital investment. Unsurprisingly this can be viewed both as a prime motivation for the vertical integration, or re-integration, of the industry that has occurred since privatisation in 1990, and as an explanation of it.

There is also a significant part of the sector that remains as regulated monopoly, notably the network businesses of pipes and wires. Getting the balance right is the responsibility of the regulatory body OFGEM, and there is no reason to suppose that the balance between adequate incentives for investment and a fair deal for consumers is not, in broad terms, being achieved, at least as measured by returns on capital.

In aggregate, observed rates of return on existing assets may therefore be reasonable (although I hesitate to pass judgment on this), but the more substantial issue is financing new investment. Investors require confidence in the anticipated revenue stream. New generation investment no longer happens except in response to schemes that provide some form of long term contractual protection. This takes us back to a traditional view of dependence on some combination of regulated monopoly, government guarantee, vertical integration and long term contracts.

What is the relationship between high energy costs and the loss of industrial capacity in the UK? What measures should be taken to address this?  

It would be wrong to dismiss the importance of energy costs for particular industries but it is also difficult to argue that there is a strong relationship between high energy costs and the loss of industrial capacity in the UK. The following points tend to support this sceptical perspective.

The Committee on Climate Change analysis[3] suggests that the proportion of industry and GDP for which energy costs are a significant influence on a firm’s price competitiveness is quite small. [c 2.6% of GDP].  If analysis is confined to goods in extra-EU trade the proportion will be smaller. 

Exchange rate movements are substantially more significant in their impact on cost competitiveness. The recent depreciation of sterling will have substantially improved the UK position in an international energy price comparison (except to the extent that domestic prices embody international fuel prices). But the same exchange rate depreciation will also have a much bigger and generally more important competitive impact on firms through making their comparative labour costs, and other domestically incurred costs, more favourable (since these are a bigger proportion of total costs even for most energy intensive industry),. 

The loss of UK industrial capacity in the 1980s and 1990s has been strongly associated with the advent of North Sea oil, sometimes known as the “Dutch disease”, and strongly associated with the exchange rate impacts of North Sea oil as well as of economic policy during that period. It had little to do with energy prices per se.

In general the association of energy prices with measures of competitiveness looks weak.  Many of our Asian competitors have faced higher energy costs than the UK or EU. Germany, widely regarded as the most “competitive” of the EU economies, also has among the higher levels of energy costs, in spite of what is sometimes seen as an artificially competitive exchange rate position[4] within the euro.

There are likely to be some “carbon leakage”[5] issues for particular energy intensive and internationally traded products and industries.  This should not in principle be a problem in relation to EU competition, assuming the UK were to continue to participate in a reformed EU ETS[6], but may be a problem in relation to other countries, eg Chinese steel.

However the appropriate response may be to consider remedies for each of the small number of affected sectors on its merits, rather than to distort the general pattern of UK energy policy.   The political and economic issues are very much akin to those of general trade policy, antidumping etc. Anticipation of a changing post-EU trade environment obviously adds to the potential complexity of this particular issue.

What preparations could be made to cope with the risk of a shortfall in energy supply? 

The most critical area is again the power sector.  A lot depends on the nature and extent of the type of shortfall that is anticipated as a risk. Historically shortfalls have been perceived as events of relatively short duration (a few hours at a time), linked to cold weather conditions and reflecting insufficient capacity to meet the strongly seasonal and temperature related nature of aggregate load. This is a failure to meet “needle peaks”. 

Planning to reduce the incidence or impact of this kind of failure ought to be relatively straightforward, at least in principle, and the most obvious strategies to adopt, apart from trying to avoid crisis in the first place, would be some combination of measures already available to the Grid:

·         Using the capacity market or other means to increase the amount of low cost incremental capacity available to meet peak loads; this might include enhancement to existing interconnector capacity, measures to encourage more use of existing sources of emergency back-up, and so on.

·         Developing load management/ consumer response techniques to allow for switching off loads that have lower priority in real time, eg water heating for domestic consumers.

·         To cover worst case scenarios, prioritisation of particular loads on the system.

·         The above all being additional to any legally permissible measures of power system control, such as voltage reduction within statutory limits.

It is possible (but not likely in the near term) that future systems could face different kinds of supply shortfall crises. For example a system heavily dependent on renewables with a large weather related output (eg wind) could face longer periods (of a week or more) of sustained shortage, less amenable to the solutions available for “needle peaks”. Possible remedies and mitigations in this case might include:

·         Much more emphasis on international interconnections, since this improves diversity of supply for weather related generation.

·         Reinforcement of the economic case to find large scale storage solutions.

·         Possibility of much stronger short term price signals to encourage some temporary reduction in the activity of energy intensive industry.

·         Administrative measures to reduce “low priority” use of power (office lighting at night).

·         Redefinition of what constitutes an acceptable standard of security. In part this merely reflects the increasing number of technical options to differentiate between different categories of load. Intermittent sources also tend to accentuate the trade-off between cost and reliability, so may provoke some re-evaluation of the right balance.

What would be the cost to the economy of the breakdown of the existing system?

It is difficult to answer this question without a more explicit picture of what form a breakdown might take. Historical experience of short term supply crises in the UK has been largely confined to the immediate postwar period, including some exceptionally cold winters, and supply disruptions associated with industrial action in the coal industry (the 3-day week). These were associated with rota disconnections of whole towns or districts, causing great inconvenience and significant lost output.

It should be possible to mitigate the worst effects of a supply crisis of the “needle peak” variety with improved load management and demand response, in which case the economic impact would be relatively much smaller than in the past.

However the effect of sustained (“no wind”) supply shortages could be much harder to manage, and the costs correspondingly higher. This would obviously be of the greatest concern to sectors that place the highest value on supply reliability, including all sectors that depend heavily on reliable IT and communications. The impact would clearly depend in large measure on the way the previous question was addressed.

What alternative ways of pricing energy should be considered to reduce the burden of high energy bills, in particular on less well-off consumers?

There are some well-rehearsed arguments around domestic tariff structures that aim to alleviate fuel prices for poorer households. The most familiar is the concept of lifeline tariffs, in which the first “block” of energy is provided either free or at a heavily discounted rate, but with a premium rate attaching to higher levels of consumption.

Although this is superficially attractive there are some practical problems. One is that poorer consumers are not necessarily low volume consumers, depending on family size, fuel choice, nature of property, etc.  As an illustration of the imperfections of such a scheme, a lifeline tariff will typically also benefit second home owners. 

Moreover the capital intensive nature of low carbon generation may also predispose to a higher element of fixed charge in fuel tariffs, ie counter to the notion of an initial free allowance. This would tend to increase the role of the state in determining “social” tariffs, ie in determining who should pay what fixed charges.

However there are two developments that may suggest new approaches. One is the medium term prospect of more district heating schemes. It seems quite possible that these will tend to incorporate a higher proportion of high density social or affordable housing, and this may provide new opportunities to provide relatively low cost heating, depending on how the initial infrastructure cost is funded. We should also look at this in the context of a simultaneous rolling out future schemes for energy efficiency, which may have an at least equal potential to reduce costs to poorer consumers.

Second, new technologies at the interface with consumer metering and load control may also be helpful. For example it is quite feasible that the new “consumer offering” will differentiate between different types of load, eg between lighting, battery charging (for EVs), and other domestic circuits. It also makes it possible in principle for consumers to choose between different standards of reliability, at different prices, rather than having a single reliability standard across the board.

But there is no simple answer to this problem. At root it is a problem of poverty rather than a problem of energy per se, and we have to accept the fact that the costs of energy (ignoring for the moment health and climate “costs”) are likely to rise above current levels (which in some senses may still be at an unsustainable historic low). The direct consequences can be alleviated to a degree by efficiency programmes (insulation), an approach sometimes evident in policy discussions, or by other dimensions of social policy.

23 September 2016  

[1] Markets, Policy and Regulation in a Low Carbon Future. Policy and Regulatory Frameworks to Enable Network Infrastructure Investment for a Low Carbon Future.  John Rhys. January 2016.

[2] Energy Market Investigation. Final Report June 2016. Competition and Markets Authority.
[3] Reducing the UK’s carbon footprint and managing competitiveness risks, Committee on Climate Change April 2013. 
[4] In the sense that reversion to the DM would make Germany much less competitive. But it should be noted that Germany has also been accused of crosssubsidising parts of its heavy industrial sector.

[5] Carbon leakage occurs if a country exports its own industry emissions to another country solely as a result of having a more stringent policy on CO2 reduction, possibly resulting in the unintended consequence of higher global CO2 emissions, especially if competitors are subject to less stringent emissions targets.
[6] This point, and that the bulk of this trade is intra-EU, is made in the 2013 Committee on Climate Change report. 

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