Friday, December 16, 2016


It was reported this week (FT, 12th December) that Andrew Wright, a senior partner at OFGEM, had argued that Britain could be moving towards a two-tier power market in which some households pay for reliability while their neighbours “sit in the dark”. Ignoring for the moment the selective reporting of a complex discussion, and a mildly hysterical media reaction to this proposition, we need to recognise that the world is changing. Different tiers of reliability, in which customers can choose their own combinations of price and quality/availability, are now both technically feasible and advantageous to consumers. There are deficiencies in current retail markets, so new formats for the “consumer offering” are both necessary and desirable. They will give us better control over our power systems and can even help with thorny problems such as those of fuel poverty.

Possible supply failures in which households “sit in the dark” are a source of nightmares for government ministers and are seen, often correctly, as a sign of political failure. The last national “black-outs” in the UK occurred in the 1970s with the miners’ strike and the 3-day week, resulting in political turmoil and the fall of a government. But, historically and internationally the more common cause has been either inability to plan for, or inability to finance, sufficient generation capacity. The UK safety margin in generation is currently at a historic low, so risk of failure is increasingly seen as real. Responsibility for maintaining adequate supplies, within the current institutional architecture, is largely left to the “market”, with a degree of oversight from OFGEM.  Some of these issues, and instances of market failure, are spelled out in the page[1] dealing with low carbon power.

But Andrew Wright has raised different questions that deserve some very serious consideration, and go well beyond the simple question of whether we currently have enough capacity in our power system. They go to the heart of the ways in which consumers in future will and should be able to purchase electricity. Reliability is an expensive commodity and the idea of consumer choice over the standard of reliability required is one that can only benefit consumers and the overall efficiency of power systems. In most sectors of the economy the ability to choose combinations of quality and price that suit a consumer’s needs is well established, and indeed a normal characteristic of a vibrant market economy. An incidental benefit in the power sector is provision of an additional instrument to improve overall system reliability and, along with storage and interconnection, to assist in managing future low carbon power systems with operational features that include intermittency or inflexibility.

The changes that are coming stem from technological developments in control and metering systems that were considered futuristic in the 1970s, and were to a large extent inhibited by deficiencies in the structures of the UK retail market, including the adoption of load profiling. With load profiling, all consumers of a particular type are assumed to have the same time profile in their consumption pattern, implying a homogenous mix of peak/ non-peak, day/night and winter/summer loads. The supply business is then essentially commoditised.  All suppliers provide the same product, with differentiation only on price. This undermines, or rather excludes from the market, any competitive benefit from offering consumers a truly differentiated service. Profiling inhibited UK development of sophisticated metering and control systems and tariffs, arguably for a generation[2].

The conventional utility model has consumers able to treat electrical energy supply as “on tap”, with limited or no differentiation between applications (e.g. as between lighting, heating or mechanical power). Tariffs and prices for the most part approximate to an averaging of the costs of supplying electricity, with very limited ability to differentiate on grounds of differing incremental costs. 

Technology change is now forcing re-examination of this model and offers an opportunity to transform the market.  Just as new low carbon generation and storage technologies, with very different operating characteristics and cost structures, will force us to re-examine system operation and wholesale markets, so should developments in metering, telecoms and control technologies lead to re-examination of the way consumers use electricity and control their own usage, changing the whole nature of the supply business. These developments have created an explosion of possibilities in metering and service provision, including sophisticated metering or even real time pricing, and sophisticated remote control of individual appliances. Given the interactive nature of these possibilities, utilities need to consider how end use should be incorporated into processes for the secure and efficient operation of the system. Consumer behaviour, and consumer choice, will be incorporated as a much more active element in the system. 

What is needed is to redefine the “consumer offering”, defining electricity as a set of services, rather than a homogeneous commodity. This requires starting with a clean sheet in defining the nature of the services that consumers will want, and the basis on which they pay.  So, for example, a consumer wanting to charge electric vehicle (EV) batteries might request 75 kWh to be delivered in a specified period, over (say) 60 minutes for “instant” service, over several hours, overnight or over several days, and the consumer will pay for his 75 kWh requirement to be met within the agreed time but with the supplier choosing exactly when the charging takes place.  Corresponding arrangements could apply to the purchase of power for heat, for refrigeration, and some other uses, designed in each case to reflect the nature of the load.  Such services might even be packaged with the provision of appropriate equipment (eg storage heaters). Commitments to individual consumers would be made by energy service companies who would be able to aggregate consumer requests and in turn contract with network operators, for whom the flexibility would be an additional instrument in maintaining a reliable and efficient system.

Implicit in all this is the option to take electricity supply at varying levels of “reliability”.  Most consumers will want 100% reliability for lighting or the ability to watch “Strictly” live, and to continue to pay a higher kWh price to get it. But many will be relatively indifferent to the exact mode of operation of their storage heaters (as they are now), water heaters, or EV battery charging. But in each case they will have a choice between a higher price premium service with guaranteed instantaneous delivery, and a lower price with delivery still guaranteed but with timing subject to some external influence.

For all households, but perhaps particularly those struggling to meet their energy bills, this choice can have a real value if, for major parts of their kWh consumption, they are no longer forced to pay the full price for a “gold plated” concept of reliability that they neither need nor want.
The development of such schemes still requires a great deal of research and product design work and public consultation, but Andrew Wright is to be congratulated on bringing to our attention an idea which will be of increasing importance for 21st century power systems.


A fuller development of the above ideas can be found in the author's paper published by the Energy Technologies Institute: MARKETS, POLICY AND REGULATION IN A LOW CARBON FUTURE

[1] (See panel of page headings above).
[2] The CALMU credit and load management unit was pioneered by Fielden and Peddie (then an Area Board Chairman) in the 1980s, and has enjoyed worldwide success. It died in the UK with privatisation and the adoption of profiling.

Monday, December 12, 2016


Battery technology is becoming a hot topic for larger commercial consumers, and may soon become a viable option for domestic consumers too. And National Grid is contracting for battery storage as a back-up resource. But how batteries are best deployed in today’s power networks is a complicated question. Today’s wholesale markets and tariff structures are very imperfect and may be quite dysfunctional in the world of fast moving technical change that includes communications and control in power networks. Consumers investing in batteries to make or save money are therefore advised to look carefully at the options, and the small print in tariffs and contracts. There are opportunities, particularly in exploiting anomalies, but wholesale markets and utility tariffs can change very quickly, and maintaining flexible options is likely to be the wisest strategy for business consumers.

What led to this comment was a request to talk on the subject of commercial opportunities at a recent energy management exhibition (EMEX) held in partnership with the Energy Managers Association. There is strong current interest among commercial consumers, such as supermarket chains, in the installation of banks of batteries. These can help to enhance security of supply, but this is not a primary motive for a significant investment outlay.

Batteries are now proving to be a valuable option for power systems, with several potentially useful functions. These can include spreading national or aggregate system loads over the day, providing emergency back-up and other ancillary services, and managing thermal and voltage constraints in local distribution networks. A two year trial of the largest grid-scale battery in Britain has proved it can potentially transform the energy grid and play a major role in the transition towards a low-carbon economy. The latest auction round for back-up capacity is reported to involve procurement of 500 megawatts of new storage projects.

The fact that batteries also have significant value at the lower voltage levels of local distribution networks, as well as in contributing to the management of aggregate demand and supply, is very relevant since it means that the battery owner may want or need to have a commercial relationship with both the National Grid and the local network operator. It also suggests that, in relation to local networks, there may be a premium on mobile batteries since load constraints on the network may occur in different locations at different times.

Some new loads, such as electric vehicles, are likely to further increase the need for batteries within the control of the system operators, again both at national or system wide levels and at key nodes within local networks. A good example is described in the Norwegian experience described in an earlier comment.

Will commercial scale batteries operate in front of or behind the meter?

From a commercial consumer perspective, the investment case for battery purchase and installation rests on three possible sources of revenue or cost saving, arbitrage in the wholesale market where there is regular opportunity to “buy cheap and sell dear”, responding to use of network tariffs that are strongly differentiated by time of day, and contracting directly with the network system operators.

Arbitraging wholesale markets.  The risk in relying on trading in wholesale markets is the volatility in prices from year to year. Wholesale prices are expected to be high this winter, in early 2017, but this expectation is critically dependent on capacity margins. Additional capacity or less than expected demand growth can dramatically reduce prices and the opportunities for arbitrage. In the medium term, it is increasingly likely that conventional wholesale market structures and assumptions will be overturned in progress to a low carbon economy, possibly reducing the importance of wholesale “spot” prices. Basing an investment on the ability to exploit arbitrage opportunities needs to take account not just of immediate market risk but also future structural change.

Exploiting distribution use of system (DUoS) tariffs. Some published network tariffs are highly differentiated by time of day, enabling consumers on these tariffs to make very large savings if they are able to move their usage away from peak loading on the local network, for example by using their own battery storage. In the case of supermarkets this may also be possible by using a store of “cold” to reduce their refrigeration load.

But the key factor here is that these structures are often extremely imperfect economic signals and are very crude devices to influence the shape of consumer loads. Exploiting anomalies in the tariff structure is ultimately a zero sum game. Ultimately the network operator is a utility that will be allowed to earn a regulated rate of return. Its costs are composed mainly of the fixed costs of the network, so the network utility will be forced either to recover more revenue from other customers, (highly unpopular and subject to regulatory intervention), or to rebalance the tariff to remove what may actually be a distorting incentive. Again this is a commercial risk if this is the prime motive for investment in batteries.

Contracting directly with the network operator. This is a novel development for network operators but, as shown in the recent auctions, it is a trend that is now under way. It raises the more general question of whether it is more effective to have the system operator managing batteries as facilities contracted from the battery owner, or to try to manage the system through complex tariff structures which try to second guess consumer behaviour. In the first case we might describe the battery as “in front of the meter”, and in the second case “behind the meter”.

A wise decision for the commercial consumer considering battery purchase, which of course can also provide a small amount of extra security, would be to make this investment as flexible as possible, to allow for direct contracting as well as managing its own demand. In dealing with local networks, there might also be a case for making the batteries trailer mounted, to allow further geographic mobility and to meet changing local network needs.  

Thursday, December 8, 2016


The institutional framework against which investment decisions have to be made is critical to capital intensive sectors such as power, and in consequence to promoting low carbon economies, which in relative terms will often tend to be even more capital-intensive than conventional thermal generation. Sound regulatory and market frameworks are therefore a central concern for energy and GHG reduction policies. In the UK, for example, one of the biggest single issues is getting infrastructure investment against a background of policy uncertainty, one of the themes I have explored previously in discussing low carbon power[1].

But worldwide there are also some prior and even more pressing set of problems that can impact on the viability and sustainability of the power sector. These relate to fundamentals of law and good governance, and go to the heart of national political structures. The corrosive nature of corruption and clientelism (sometimes defined in terms of widespread patronage and the exchange of favours for votes) is a major challenge for all political systems, but is perhaps particularly important when there are serious resource constraints, and in the context of successful economic development. This is therefore a big issue for many less developed economies, which are of equal or greater importance to the achievement of a global low carbon future.

Vinayak Chatterjee describes the problem in an Indian context. How to revive India's corrupt and debt-ridden power sector. (October 26, 2015)

India's electricity distribution sector is a national embarrassment, brought about by decades of turning a blind eye to the misdemeanours of this sector. The unholy trinity of the conniving State Electricity Board (SEB) employee, the unethical and self-enriching domestic and industrial consumer and the politician patronising theft, corruption, sloth and freebies has brought the power sector to its knees.

Students of past performance of many SEBs, with honourable exceptions, will be familiar with this harsh judgement, with many of these criticisms confirmed in numerous World Bank studies. High levels of illegal abstraction from distribution networks, tariffs inadequate to allow SEBs to finance new capacity, and political patronage that can view SEB management as a vehicle for distributing favours and jobs, are all rife and in many instances both well documented and publicised. Unsurprisingly many SEBs are in dire financial straits and are ill-equipped to support the high levels of investment required to improve and increase access and supply, let alone make the transformation to a low carbon economy.

The Indian power sector is an important illustration, partly because a low carbon future for India is so important to the world, partly because the power sector is intrinsically crucial to this objective, and partly because the problems of India’s state electricity boards (SEBs) have been widely acknowledged and openly discussed. India is by no means unique in its lack of effective governance. Indeed the open nature of Indian democracy means that the problems are at least recognised, a first step to a possible resolution.

A recent article by Jacquelyn Pless and Harrison Fell, “Bribes, bureaucracies, and blackouts: Towards understanding how corruption at the firm level impacts electricity reliability” offers an interesting empirical example and theoretical perspective for this discussion, pointing out that these shortcomings in governance can also lead us to comparison with some familiar problems of a common pooled resource such as fisheries.[2] The study addressed a particular form of corruption, using data from many countries, and found empirically that firms with a propensity to bribe for electricity connections experienced 14 more power outages per month and incur 22% greater losses as a percentage of annual sales due to power outages.

Propensity to bribe is closely linked both to a perceived necessity for bribery (in order to get any power at all), ie a resource constrained system, and to weak governance where bribery is an effective, low risk and penalty-free option. Inevitably these include many systems in developing countries with limited power generation resources combined with weak governance and regulation. A simple example of the process by which the reliability of the network is degraded is given below.

Imagine you are an investor in a manufacturing plant invited to wait six months to connect a factory to the electricity grid. The temptation is to bribe an employee of the local power supplier to connect you next week. The bribe is a rational act and will benefit your company, but we can assume that many other people will be doing the same thing. Typically there is an actual or potential shortage of capacity in the system, due to a lack of investment, itself a result of failure to collect revenues that cover costs and of poor governance. This has frequently been true of State Electricity Boards (SEBs) in India, power being a competence of individual states rather than the federal government. Restricting new connections is one of the means that the SEB is obliged to use to try to restrict demand to a level that can be met with a reasonable degree of reliability. Unauthorised connections will overburden the electrical grid, leading to a more vulnerable system and less reliable power supplies for everyone.

In terms of impact, bribery to get a connection is akin to theft, equivalent in its effect to the smaller scale illegal “hook-ups” that are also commonplace. The company may subsequently pay for actual kWh consumed (by no means certain) but this does not reduce its immediate adverse impact. The fact that the SEB management is unable to control connections, obtained by bribery or other illegal methods, means that it loses control of system reliability. In other words a system that is open to corrupt practices, or indeed to simple theft, will inevitably suffer either financially or in terms of its ability to provide a reliable supply, or most likely both. It has become a common pool resource for which no-one is prepared to pay to maintain reliability.

There is an interesting and broader question of how to get to more socially efficient outcomes. Administrative rationing, giving preference to incumbent consumers, is often the starting point for electricity providers, given that they start from a position where potential demand is greatly in excess of available supply, but may also be economically inefficient. It also breaks down when subject to bribery and corrupt practices. It has sometimes been argued that corruption is a form of market pressure and can under some conditions improve social efficiency, by allocating scarce supplies (of import licences or network connections for example) to those who value them most highly.

Quite apart from any moral or ethical objections to condoning rent seeking by corrupt officials, however, bribery and corruption are by their very nature clandestine and non-transparent, and are unlikely to be organised in a technically efficient manner, eg with transparent markets or openly conducted competitive auctions. Our examples, and general experience, suggest that corruption quickly gets out of control.  World Bank economists have therefore preferred to recommend solutions that focus on improving governance and enhancing the financial capability of the sector, eg through cost reflective tariffs that permit investment in increased supply.

The so-called Washington consensus on economic reforms recognised the underlying problems but assumed that the answer was markets and privatisation. In practice this approach has not lived up to expectations, in no small measure because successful privatisation is only possible when the basic elements of reform, including adequate tariff levels and structures, and the depoliticisation of power sector management, have already been achieved. Private sector management is in any case not immune from corrupt practices in environments of weak governance.

I believe these will be continuing and increasingly important issues within a global perspective on both economic development and low carbon futures. Transparency, oversight, and enforcement of high standards of sector governance will continue to be important objectives everywhere, and they are closely tied to wider questions of political economy.[3]


[1] Recent papers published by the Energy Technologies Institute addressed these themes, and also related and additional elements of market failure, for the UK, and form a foundation for looking at future energy systems architecture.
[2] A recent Oxford Martin School blog by Jacquelyn Pless and Johanna Schiele  also aims to develop and extend this analysis to other aspects of electricity networks.
 [3] Francis Fukuyama provides a thought provoking discussion of the general issue of clientelism in Political Order and Political Decay: From the Industrial Revolution to the Globalisation of Democracy,  Farrar, Straus and Giroux. He also makes useful distinctions between the closely related concepts of corruption, patronage and clientelism. The book is also particularly interesting in its criticisms of the USA, and reminds us that political systems are capable of decay as well as improvement, with the ever present risk of reversion to clientelism in both democratic and authoritarian societies

Thursday, December 1, 2016


UK grid loses half the power from link to France.

National Grid powers up for a renewables future.

National Grid to be spared from break-up.

(all from FT, November 2016)

 The UK currently faces a tight supply situation through this winter, which may be exacerbated by downtime on French nuclear plant and partial loss of capacity on the submarine interconnector. National Grid as the system operator plays a key role in keeping the lights on, by finding ways to manage these and other unforeseen events, and balancing supply and demand in real time. It will also face new challenges in managing generation supply that contains an increasing proportion of renewable energy, with significant intermittency of supply. These challenges increasingly emphasise the difficulties in separating the roles of a transmission operator, managing and maintaining the high voltage network, and a system operator, directing many aspects of the day to day business of power generation. As I observed in an earlier comment, Low carbon network infrastructure. Not sufficient arguments for breaking up National Grid. the House of Commons Select Committee was ill advised to recommend the break-up of National Grid on the grounds of an interpretation of regulatory theory that addresses yesterday’s problems. Keeping these functions together implies that the government has to address the problems of a difficult low carbon future, not the outdated paradigms of the 1990s.

Three stories for the UK power sector came together in this week’s FT, all focused on National Grid, who maintain the UK’s high voltage long distance transmission network and also act as the system operator, essentially controlling the operation of the UK’s generating plant in order to maintain supply/demand balance and stability of power flows within the system. The first story, National Grid Powers up for a Renewables Future, describes how National Grid is refocusing its business to cope with the challenges of renewables.

Some analysts believe we are on the verge of a fragmentation of the power sector that will eventually lead to much more emphasis on local power generation and battery storage, making the high voltage grid redundant. I believe this extreme position is highly improbable, for two main reasons. First, a very high proportion, at least of new low carbon sources of power currently anticipated in most projections, is in sources of generation that are intrinsically either large scale or remote from population centres. This includes nuclear (excluding for the moment small modular reactors), carbon capture (CCS) and large scale renewables such as offshore wind. These and probably other options such as tidal lagoons, depend on access to long distance transmission to make them viable.

Second, smaller local systems face much bigger balancing problems, primarily because they lack diversity. Interconnection is therefore a necessity. There may be some specific issues of network charging, if local facilities believe local generation and lower “imports” allow them to escape paying for the back-up services the local system needs, but it is not clear why these issues should undermine the fundamentals of the National Grid business model.

It is true that the essentially intermittent nature of many sources of renewable power will make the Grid’s job, as system operator, more challenging. Viewed from this perspective even a system as large as the UK can benefit from additional diversity and from the back-up potentially provided by interconnection with other networks. This takes us to the second FT story, on 29 November, UK Grid loses half the power from link to France.

Damage to the cable, possibly from a marine anchor, has temporarily reduced the capacity of the link. Coinciding with some unanticipated downtime on French nuclear plants, this increases the risk of a tight supply situation this winter and a spike in short term market prices (one independent supplier has already gone to the wall). The impact of this loss of capacity, on France as well as the UK, emphasises the importance of interconnection for security of supply, and also the role of the Grid.

This leads us to the third story, National Grid to be spared from break-up, also on 27 November. The government has sensibly rejected the recommendations of the Select Committee chaired by the SNP’s Angus McNeil. As I argued in an earlier comment, the drive to a low carbon economy is going to bring profound changes to the power sector. These start with questions of technology and scale but they have huge ramifications, and conventional assumptions about markets, regulation and governance are coming under increasing pressure. Given that governments lack any technical competence in the power sector, the role of organisations like the National Grid is becoming more and more important. Now is not the time to take the risks of disruptive organisational change for its own sake.

To embark on a re-organisation of National Grid, in the absence of a clearer vision of where we need to get to, and focusing on issues which in a sense are problems of the old paradigm, may be a mistake. To do so without a clear direction of travel will simply add to the policy uncertainties already identified as a major problem for new investment.

For a fuller discussion of the National Grid break-up question, refer to the earlier article: Low carbon network infrastructure. Not sufficient arguments for breaking up national grid.  Some of these challenges sit at the heart of the Oxford Martin Programme on Integrating Renewable Energy.

Monday, November 28, 2016



Record global temperatures and unusually high Arctic temperatures, in particular, are starting to suggest some scary scenarios for the world’s climate, including the notorious “tipping points” which can accelerate the rate of change. This is a time when we need the best possible understanding of what is happening to the planet, not least because it can help preparations for a dangerous future. But US climate science, hitherto one of the most important sources of understanding, is threatened with budget cuts. This was predictable in the context of anti-science climate denial rhetoric but there have been signs that Trump, at least on this issue, is rowing back from his extreme positions and threats to scrap the Paris agreement. So now is not the time to cut back on the research that helps to anticipate the real global and regional threats that we shall be facing. This would be the equivalent of a pilot switching off the navigation system when he discovers he does not have enough fuel.

We have become accustomed to a string of global temperature records in the last two years, with 2016 likely to exceed 2015 for the global annual average; and we have also passed a psychological landmark with estimates that the world has now warmed by over 1o C since pre-industrial times. Recent weather in the Arctic has provided further surprises, including periods of several weeks where the temperature has exceeded seasonal norms by as much as 20o C. This difference is significantly higher than the average temperature gap between summer and winter in the UK and other temperate climates. 

Climate science has for a long time indicated the likelihood of greater warming at the poles, and this dramatic anomaly is no doubt partly attributable to the aftermath of an el Nino event. However the scale of this increase has taken scientists by surprise and increased fears that climate change could move much more rapidly than has been generally forecast. There are several reasons why the Arctic matters so much, and these include the risk of some very serious feedback effects which have been characterised as “tipping points”. One is the potential reduction in “albedo”, which means that loss of snow and ice cover reduces the reflection of heat and leads to more warming. Another is the potential release of another powerful greenhouse gas, methane, from warming land surfaces and thaws in the permafrost. Big changes in Arctic conditions are also likely to have major impacts on weather across the globe.

These threats underline the importance of action on greenhouse gases. But they also start to put a more immediate focus on issues of adaptation.  Given that more and more attention is now being given to the challenges of adapting to climate change, understanding the numerous climate processes that will affect individual regions and countries becomes even more important. Without that understanding there will be real dangers that adaptation is planned, and investments made, that fail to address the right issues. A simple example is whether to plan for heavy increases in rainfall (possibly the UK), or for prolonged droughts (possibly California).

This makes the suggestions of US cutback on climate research (affecting NASA, NOOA and others) a particularly foolish, shortsighted, and damaging proposition.

Friday, November 25, 2016


Modified policies on climate issues might have some surprising benefits for a declining US coal industry, and for the future of carbon capture.

President-elect Trump is having second thoughts about climate change, previously dismissed as a Chinese-inspired hoax. There are many reasons that might make this a perfectly rational response to the impending responsibilities of office.

First he is almost certainly now getting briefings from scientific and other experts both on the reality of climate science, and on the potential impacts of climate change.

Second the USA is now suffering major drought conditions in the South West. There are indications of a possible link with climate change and strong indications of possibly much worse “megadroughts” in the future. Most people in the US now accept the reality of climate risks, and for some people the potential costs are becoming apparent.

Third, and of more immediate political significance, it seems unlikely that a US withdrawal from the Paris agreement would be followed by any significant US allies or trading partners. Even more significantly, and as I have observed in earlier blog comments, climate policy will become increasingly tied in with trade. China’s Vice Foreign Minister Liu Zhenmin, for example, has made it clear that China will take other countries’ positions on climate change and the low-carbon economy into account when negotiating trade deals.

This is hardly surprising. No-one is going to put up with trading partners who free-ride on cheap but destructive energy sources with unabated emissions, undercutting competitors who adopt environmentally responsible policies. [The UK incidentally will have to recognise the same realities as it navigates a path to those sunlit uplands of new trade agreements. This will be a bitter medicine for ardent climate sceptics and Leave campaigners such as Lawson, Redwood and Rees-Mogg.]

But acceptance of the compelling arguments for action on greenhouse gas emissions could, in principle at least, also provide a lifeline for US coal communities, in the “rustbelt” that provided an important contribution to Trump’s election victory. The connection is carbon capture and storage (CCS) applied to coal. This is not currently a frontrunner as a least cost solution for US energy policy, and a substantial unknown is the extent to which Trump will be willing or able to fulfil his campaign promises to these neglected communities.

Coal has almost certainly suffered more from fracking and the resulting cheap gas than it has from federal environmental policies, so the connection may seem an improbable one. Proposed policies to spend on infrastructure, similar to those advanced by Obama but blocked by a Republican Congress, may provide a “Keynesian” stimulus to the economy. But directing them to benefit deprived areas may be much more difficult, particularly as the allocation of infrastructure spend is far from being in the gift of the President. 

There are in consequence some potential merits in CCS that at least make this an avenue worth exploring. A programme to develop carbon capture and storage has several potential advantages, and these include benefits to economically depressed regions with high dependency on coal.  It requires a very substantial infrastructure spend which is likely to be close to those regions. It may provide a more promising future for coal. And in terms of wider benefits, CCS is still seen by many policy analysts as an important or even essential ingredient of real progress to a low carbon economy, and could reduce the large number of coal fired stations that otherwise threaten to become stranded assets.

These are complex questions, and continued coal fired generation with CCS could still face many barriers, not least on cost. But the idea does provide at least a small element of hope for a fading industry.

Saturday, November 12, 2016


A major element of Trump proposals for US energy policy targets complaints that energy costs, driven by supposedly excessive concerns over climate issues, are disadvantaging US industry, notably in competition with China. As usual there is a complex story to be told, probably too complex for a short comment, but the following observations ought to provoke some thought.

“It’s a lament that rarely holds up under examination of the facts. All too often, these complaints are part of a lobbying campaign that is essentially political. And when that’s not the case, we usually find there’s a lot of money at stake in industries that are reluctant to invest in adjusting to future challenges. And even when corporate leaders know that these investments are necessary, a majority of them still believe the cost should be paid by the taxpayer. That leads them to threaten using their deadliest weapon, the threat of job cuts and the relocation abroad of their factories and production operations.”

Does this sound familiar in a US context? Could it have been written by a US commentator? I suspect it does and could. But, surprising as this may seem, it was written by a former German environment minister in 2014. The context was not the supposedly high costs of US industry, but concerns about the competitiveness of European and especially German industry in relation to a low energy cost USA. He continues the attack.

The complaints by European industry lobbyists, that energy costs are putting them at a “destructive” competitive disadvantage, simply doesn’t stand up to scrutiny. Industry lobbyists will say either that the costs of labour are too high, or that their big problem is the price of energy. America’s historically low gas prices are at present the cause of yet more European moaning.

The facts show how wrong they are. Energy costs account on average for less than 3% of gross production costs in Germany, whereas staffing costs account for about 20%. Even if you look at shares of gross value creation, the energy costs don’t exceed the 10% mark. Yet, industrial lobbies and trade associations continue to prophesy the end of the Western world.

I made similar points in recent evidence to the House of Lords in respect of their questions about loss of industrial capacity in the UK and energy costs as a possible cause.

It is 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.

1. The Committee on Climate Change analysis[1] 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.

2. 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),.

3. 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.

4. 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 within the euro[2].

5. There are likely to be some “carbon leakage”[3] issues for particular energy intensive and internationally traded products and industries, especially if competitors are subject to less stringent emissions targets. 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[4], but may be a problem in relation to other countries, eg Chinese steel.

6. 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, anti-dumping etc. Anticipation of a changing post-EU trade environment obviously adds to the potential complexity of this particular issue.

From all this we might deduce the probability of a strong read across to the US, ironically with US gas being a main focus of comparison for European “moaning”. The reality for the US is, I suspect, closer to the following.

US coal, and coal communities, will have been hit hard by the fall in US gas prices. Climate policies are a convenient scapegoat in a political environment that includes a strong ideological commitment to rejection of climate science.

There is also a very strong perception that American jobs have been destroyed by competition from “cheap” Chinese labour. Migration of some industry to poorer countries with lower labour costs is an almost inevitable consequence of globalisation. We can and do argue at length in every developed economy about how best to deal with that. It is a serious issue of adjustment to globalisation and free trade. But that is a debate for another day.

The real point though is that energy prices per se seem unlikely to have much connection with concerns over “unfair” Chinese competition, for the reasons given above.  What dominate are first real labour costs, and second exchange rates. Exchange rates are part of the process of adjustment that allows trade to balance in response to differing comparative advantage between countries[5]. Inevitably someone will have a comparative advantage in labour costs and someone else in energy or agricultural production.

Given its resource endowment, the US has always been in a strong position on energy compared to Europe, and it is worth noting that China is pressing ahead hard with an emissions reduction agenda. So using competitiveness concerns as an excuse to avoid ambitious climate targets looks like a particularly specious argument.

There have been other concerns in Europe, mainly on the emissions impact of the unloading of surplus US coal, but that is another and more familiar story.

What is challenging and depressing is the apparent universality of almost entirely phoney claims for the profound significance of energy costs in industrial competitiveness. A good time to ask if the emperor actually has any clothes, or to shout “Cui Bono?”. Who benefits?

[1]Reducing the UK’s carbon footprint and managing competitiveness risks, Committee on Climate Change April 2013.
[2] 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 cross-subsidising parts of its heavy industrial sector.
[3] 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.
[4] This point, and that the bulk of this trade is intra-EU, is made in the 2013 Committee on Climate Change report.
[5] In fact the whole concept of industry competitiveness becomes quite questionable in this context. But that again is another question for another day.

Thursday, November 10, 2016


Conventional wisdoms on the superiority of unfettered energy markets, and their ability to incentivise investment and deliver reliable electricity supplies, are coming under challenge as never before. The failure to deal adequately with the social costs and externalities of CO2 emissions is one massive market failure, but even the resolution of that through carbon pricing does not address the structural flaw in many wholesale electricity markets. The policy imperatives for a low carbon economy are reinforcing many of these structural failures, but the seeds of trouble have been there for some time. The UK, in many respects the pioneer of market liberalisation, the EU which has since adopted these ideas with enthusiasm, and New Zealand, whose natural resource endowment (hydro) has allowed it to move a long way towards a low carbon power sector, present different issues, but all are forced to confront the same basic paradoxes in electricity economics. Failure to resolve these will ultimately threaten security of supplies, and the credibility of national regulatory frameworks.

Tariffs, pricing and markets underpin both efficient resource allocation and the basis for power sector investment, and have always deserved theoretical and practical analysis.  But there are two separate objectives. One is a set of market prices that incentivises investment. The other is market signals that ensure the efficient use of an existing stock of generation capacity. The fundamental dichotomy is the distinction between the short term and long term. The cost signals essential for production efficiency from existing assets relate only to short run marginal costs (SRMC), but adequate returns to investment, and to a significant degree retail tariffs, require prices that cover total costs[1] including capital costs. This is often described as long run marginal cost (LRMC).  Both objectives matter.  But it is the more limited SRMC, often equated to the short term variable costs of fuel, that has become the key to most wholesale markets, and in many ways the cornerstone on which liberalised market structures rest.

Wholesale prices based on SRMC are an outcome of the requirements for operational efficiency.  But it is intrinsic to SRMC pricing that it is not sufficient to reward investment; nor will it signal to consumers the full real costs of consumption which must include investment.  Allocative efficiency matters in the consumption of electricity as well as in production; and in the wider economy more cost reflective pricing for power will in principle reduce costs and improve economic efficiency.  For both these reasons, the conceptual basis for electricity tariffs has often been defined as LRMC, giving substantially higher prices that can cover investment and other fixed costs. The structure of consumer tariffs can however incorporate both SRMC and LRMC elements.

The UK 1990 model. When the institutional norms for the power sector changed towards liberalised market structures, the LRMC/SRMC issue was brought into sharp focus.  “Energy only” markets necessarily tend towards SRMC based outcomes, especially in periods of surplus capacity. This does not cover investment costs or incentivise new capacity investment[2].  In consequence some market designs have attempted, explicitly or implicitly, to build in features which will, at least in principle and over the long term, be capable of rewarding investment through a spot price alone. A prime example was the England and Wales pool introduced in 1990, using an administrative mechanism to define value of lost load (VOLL), and loss of load probability (LOLP), to provide prices which spiked dramatically. In principle at least this provided incentives for investment on the basis of long term price expectations.

The approach was essentially a clever attempt to reconcile SRMC and LRMC through a device which purports to act as a surrogate for the “market” in assigning a scarcity value to form part of a single “spot price”, albeit done by administrative means. However this approach proved hard to maintain in a regulatory context, partly because it implies and requires the possibility of very substantial price spikes, some of which must be expected to persist over long periods if they are to provide adequate returns on capital.  However even this model, with a single “spot” price, depended on an administrative intervention, external to the market, to set VOLL and measure LOLP. This in turn reflects a political or administrative view of the level of security or generation adequacy to which the system should operate.

Post liberalisation experience.  This central intervention was one of the features that made the 1990 model unpopular and led, in the UK, to the NETA/BETTA reforms. Implicit in the latter was the assumption that the market itself would somehow define an appropriate level of security. The outcome was neatly summarised by John Kay in the FT.

 But privatisation failed to provide a stable framework for planning new electricity generation. The initial regime reflected careful thought about appropriate incentives for capacity installation, but this regime was swept away in 2001 in favour of a simpler one modelled on other commodity markets and known as NETA (New Electricity Trading Arrangements), subsequently to be Betta (British Electricity Trading and Transmission Arrangements). As so often in commodity markets, this structure worked rather better in the short run than over the long term.”[3]

A return to central purchasing. Predictably the UK is now widely seen as facing very tight capacity margins and the possibility of a supply crisis. In response it has reverted to what is essentially a central purchasing regime through the introduction of a capacity market. This is an entirely rational response but it represents a major step away from the unfettered market philosophy that underpinned the original power sector reforms, and the first step to a centrally directed system. The challenge will be to ensure that this new function for government is conducted efficiently and effectively.

EU ambitions for energy only markets. The EU has generally opposed the idea of capacity markets, perhaps partly on ideological grounds, but more convincingly because national capacity markets are potentially a major barrier to a “single market” in electricity. The power sector has always been a national not an EU responsibility, so national capacity markets are a further barrier to integration. Importantly a single market that includes capacity can only make sense if there is a single security standard across the system. This would need to be set centrally and applied in all EU countries participating in the single electricity market. It seems unlikely that the German government, for example, would be happy to see such a fundamental choice made in Brussels.   

Will regulators allow price spikes? New Zealand experience.  A necessary (but not sufficient) condition for a market to be effective in inducing investment is that the political and regulatory framework can allow for major price spikes in which the only constraint on prices is the willingness of someone to pay. General experience is that this does not happen. New Zealand was brought to my attention this week, and is interesting because of the high proportion of zero marginal cost generation. As such it presents a foretaste of how this market question might play out in other jurisdictions, as the advent of low carbon technologies accentuates the gap between SRMC and LRMC, with SRMC falling to a very low [4] or zero level, while LRMC, ie the full cost of supplying power, rises. The story, for market enthusiasts, is not encouraging.

Price spikes do occur and are subject to regular complaints of an “undesirable trading situation”, allowing the regulatory authority to intervene and remedy the problem. So the natural “market” development of supply shortages, inducing higher prices to bring forward additional supply or curtail demand, is heavily constrained.

Prima facie this should make life difficult for the generation utilities. However most are vertically integrated into retail supply, and there have also been complaints about the margins prevailing in retail supply. If correct this suggests that any damage to the financial viability of generation is offset at least in part by the ability to sustain excessive margins in another part of the business, a situation that would be strongly redolent of complaints made about UK energy utilities.

Ideology. In both New Zealand and the UK, there is substantial tension between “energy only” free market enthusiasts and the development of centrally directed capacity markets. Central purchasing has entered the UK by stealth under Conservative or Conservative led coalition governments. In New Zealand the left of centre Labour and Greens proposed a central buyer model, only to be accused of Soviet-style economic vandalism.

We can expect these controversies to continue and to accelerate as the world moves further towards a low carbon, zero marginal cost world. But it is more and more evident that conventional assumptions about electricity wholesale markets are no longer “fit for purpose” and we shall in due course see further rounds of major reform.

The Oxford Martin School Programme on the Integration of Renewable Energy will be returning to these and other questions, not just for the UK but in a wider international context.

[1] To be wholly accurate, we should distinguish actual total costs from the concept of long run marginal cost, but for the purposes of this particular exposition the distinction need not concern us very much.
[2] This is most easy to demonstrate for peaking plant, which can only earn enough to cover its fuel cost even in the very few hours when it runs. But a similar revenue shortfall will apply to almost all plant to some degree.
[3] John Kay.  FT.  July 2013.
[4] CCS, if it is ever built, might provide an exception to this.