CARBON WEALTH FUNDS TO SAVE THE PLANET

Adam Whitmore argues in his recent blog “How not to squander $ 130 trillion” that carbon pricing should be used to establish wealth funds from which current and future citizens can benefit.  This is very timely given the Baker and Shultz (Republicans) proposals now under discussion in the US.  He makes the classic environmental economics arguments for carbon pricing.

At the moment only a very small proportion of greenhouse gas emissions is priced adequately.  Most emissions remain unpriced, and the growing proportion that is priced is mostly sold at well below both the cost of damages, and well below the value of an increasingly scarce resource.  A valuable scarce resource is thus being given away or sold below cost, subsidising emitters.  Huge natural wealth is being squandered.  And once gone it can never be replaced.

It would be better to use revenue from carbon pricing to create a wealth fund to benefit both current and future generations …

… in the form of a fund for citizens, with proceeds from carbon pricing (the sale of allowances or taxes) at adequate levels paid into the fund.  Carbon pricing should be comprehensive, with prices at adequate levels.  The finite volume of the resource implies it is best used to establish a wealth fund, where financial capital is built as natural capital is used up.  The fund would belong to all citizens.  Granting its value to citizens would surely encourage better management of the atmosphere, and thus the climate, and higher carbon prices than generally prevail at present.

Most environmentally concerned economists will support the arguments for much higher prices to attach to greenhouse gas emissions (GHG), and it is well worth examining some of these ideas further. Adam develops the basic idea and sets out his vision for how it might work.

Dividends from the fund could be used in many ways.  One approach with a range of advantages is distributing benefits to all in the form of a “citizen’s dividend”.  There is already a feature of the Alaskan wealth fund derived from oil revenues, where distribution is in the form of a Permanent Fund Dividend to all citizens.  This is widely considered to have helped build and maintain public support for the scheme.

This approach is closely related to the idea of “tax and dividend” carbon pricing.  I have previously argued that such approaches have merit, and indeed tax and dividend has recently been advocated by senior Republicans in the USA.  However, there is an important difference between a fund and tax and dividend as often presented, in that revenues are used to establish a fund that is intended to be permanent, whereas tax and dividend proposals often assume revenues to be distributed in full.

Adam also links his idea to other political objectives especially in the context of redistributive measures, both nationally and in a global context.

There is also a relationship between the idea of a citizen’s dividend and a universal basic income, which is much discussed at the moment and subject to a few trials.  … There is a natural case for distributing dividends equally, as all have equal rights to the atmosphere.  The atmosphere is a global resource, and climate change knows no borders, so it is natural to make any fund global.  However establishing such an arrangement is likely to be too great a political challenge. …

The global challenge is clear enough. And the idea of developed countries (sometimes deemed to have a historic responsibility in this context) subscribing to development funds to assist developing countries in both low carbon initiatives and in adapting to climate change, is already part of the currency of international climate negotiations.

Establishing national funds will have many challenges.  However the prize seems large enough to be worth pursuing.  The current system of simply allowing emissions to be dumped into the atmosphere, often free of charge and almost always too cheaply, is a waste of a unique and irreplaceable asset.  Irreplaceable natural wealth such as the atmosphere should be managed carefully, not squandered recklessly.

This amounts to a series of challenging propositions. It is intuitively appealing, and the connection of ideas in providing for the future, taxing emissions to correct a market failure, and providing for a “fair” allocation of proceeds is attractive.

However it will be necessary to explore the idea in the context of potential macro-economic and other implications, and we can expect quite a lot of exposure for these ideas in the near future, not least reflecting their surprising emergence from US Republicans. A few of the questions deserving consideration, and to which we may return in future blogs, are:

1  There are some clear differences from the sovereign wealth funds put in place to preserve the long term position of countries that are depleting a scarce natural resource eg Norway and oil. One feature of the latter is that they can prevent a potentially dangerous exchange rate appreciation which destroys part of the country’s economy. UK failure to establish a wealth fund for North Sea oil was one of the factors that undermined UK manufacturing in the 1980s. But this feature does not translate to a global context, nor, would it necessarily make sense for an individual country to set up such a fund in isolation.

[Economists will also note that oil is a “private” good, whereas the GHG absorbing capacity of the planet is very much part of the “global commons”.]

2  Would the creation of such a fund immediately remove purchasing power from the economy and, in the absence of offsetting measures, provoke recession? One can imagine, for example, some very negative effects from the immediate adoption of such a measure in the German and eurozone economy for example.

3  Is it not simpler to view the proposal simply in the context of additional sources of tax revenue, Green taxes, which would increasingly substitute for other and unpopular forms of taxation? Or should the revenues be hypothecated to other clearly needed climate policies, for example on research and development?

4  Energy taxes are often seen as quite regressive. How could this be remedied?

My own view is that this is a welcome and timely proposal and it, perhaps in a modified form, could be used as a welcome rallying point for more effective action on climate; but we will need to think hard about its practical and political aspects. As ever the devil will be in the detail. But it will also be in the packaging and the presentation.

EU EMISSIONS TRADING SCHEME AND EUROPE’S CLIMATE POLICY. A FLAGSHIP FLOUNDERING

Speaking at last Wednesday’s BIEE Climate Policy Seminar Boris Lagadinov of Sandbag, the Brussels and London based think-tank that addresses climate issues, gave an excellent summary description of the development of the EU Emissions Trading Scheme (ETS), its successes and shortcomings, and the prospects for remedying its defects in the 2020s, notably the status of Phase 4 (2021-2028) reforms and the overlap with other policies. The presentation is available online (at least to BIEE members), but the fuller version of his analysis is also readily available on the Sandbag website. It is an excellent exposition and I will not try to repeat its detail, but rather aim to concentrate on some of the lessons and implications discussed at the seminar and that we might draw from the ETS experience.

The broad picture is well known. The EU ETS has achieved compliance with its targets, largely as the result of initially very undemanding targets (a result of  extensive industry lobbying) combined with recession induced falls in demand, but it has in the view of most commentators wholly failed to produce carbon prices that are likely to have any significant effect in reducing emissions, let alone incentivise the kind of transformative change that is required across the energy sector or more broadly in the economy or in lifestyle choices. In other words it provides no incentives for economy wide decarbonisation.

Boris outlined the structural reform measures associated with so-called “backloading” and the creation of a Market Stability Reserve (MSR), but the scale of the surplus in the ETS stands at about 3 billion tonnes in 2016 and Sandbag expect this to rise to about 4 billion tonnes by 2020. In broad terms this is about a full year’s EU emissions, but about two years for emissions falling within the scope of the scheme. The reform proposals may be structurally sensible but the Sandbag analysis indicates there is no real prospect that they will lead to a significant increase in carbon prices any time soon.

In terms of fundamentals, the EU ETS is a highly oversupplied system. Emissions have fallen much faster than the “cap”, but it is quite clear that this has been entirely due to other factors including the impact of so-called “overlapping policies” such as national policies for the power sector, and for energy efficiency. It is very hard to argue therefore that EU achievements in reducing emissions owe very much, if anything, to its flagship policy, the ETS. 

For economists, for whom adequate pricing of the emissions externality is usually assumed to be one of the simplest and most efficient and effective policies, this is a difficult pill to swallow. In global terms the EU ETS was one of the earliest and is the world’s largest attempt at using price and market mechanisms to control emissions. But the outcome is that, in one of the largest players in the world economy, the carbon price is having little impact and playing little or no part in policy. And it now appears condemned to irrelevance for at least the next decade.

There is therefore a clear contrast between the lofty ambitions of Paris, which the EU (including the UK) have endorsed, and the reality of this core EU policy. And there are some clear practical and philosophical lessons to learn, both in the EU and for other regional schemes.

1    The first is the importance of being clear about objectives. The required level of long term global emissions reduction may be a clear target, but “region EU” contributions, defined over relatively short time periods were always at best a partial reflection of the real objective, which is to set in motion the massive changes required in moving to a low carbon economy. It was and remains the case that the long term objective requires very substantial transformative change, and that the incentive of a significant carbon price should be playing a major role in this. Failure of the EU ETS to deliver meaningful prices should therefore have been interpreted as an early signal that the short and medium term targets were far too slack and were certainly not consistent with EU ambitions to be a global leader on climate.

2    Cap and trade mechanisms are badly suited to the cumbersome and inflexible nature of much of EU decision taking, demonstrated by the slow and inadequate progress of MSR and related reforms. Cap and trade is intrinsically inflexible, given the need to provide participants with some degree of confidence in the rules and duration of the market. What is needed is policy instruments with the ability to adjust to events, such as the recession, over reasonably short timescales. Adaptive mechanisms permit a learning process. In this context using price directly as a policy instrument (through a carbon tax) could have been a much more effective policy instrument.

Unsurprisingly member states with high levels of ambition have developed their own policies. These include “floor prices” for carbon in order to support low carbon investments, but also other direct interventions. It has been claimed that, paradoxically, these so-called “overlapping policies” will in some instances give rise to implicit “costs of carbon reduction” an order of magnitude higher than the actual carbon price that would emerge even from a reformed ETS.  Whatever the truth of this, the weakness of the ETS means that we are likely to see more rather than fewer “overlapping policies”.

These unilateral initiatives have also led on to further disputes over policy. It can be argued that they have undermined the carbon price and the ETS, and this finds its expression in one conventional view that additional measures do not decrease cumulative emissions, since they merely substitute for reductions that would otherwise have occurred within the EU ETS “carbon bubble”. Sandbag analysis of this argument, often described as the waterbed effect, and the growing scale of ETS surpluses, suggest that the waterbed myth is entirely fallacious, but that has not stopped the myth giving rise to some damaging public policy consequences.

One example was the objection on competition policy grounds to proposed closure of five coal power plants in the Netherlands, as part of a national agreement to move towards cleaner energy. Since this was to be done on the basis of an agreement between producers, it hit problems of competition law. The companies pleaded a “public interest” defence, namely reduction in CO2 emissions. However the Dutch competition authority concluded that the agreement was in violation of the cartel prohibition, arguing that the proposal would not reduce CO2 emissions, as claimed by the producers, since the redundant emission rights would be sold on the open market and would therefore only be relocated. In other words the “waterbed myth”  was used to obstruct an “overlapping” policy that would have resulted in a real and immediate emissions reduction.

Inter alia this shows that the impact of policy failures can go beyond simple failure to achieve expectations, and can act as a barrier to other effective initiatives. Regular readers of this blog will be aware of my opposition to the UK’s exit from the EU, but the EU ETS has not proved to be a good example of successful EU policy. It may still be sensible for the UK to participate post Brexit, in the hope of its ultimate reform, but the UK will clearly need to continue its own policy initiatives, as it has to date.

There are numerous other issues for energy and decarbonisation policy that will spring from Brexit, and that is the subject of the next Climate Policy Seminar, on 5^th April when Anthony Froggatt of Chatham House and Owen Bellamy of the Committee on Climate Change are addressing the topic of “Brexit and Decarbonisation”

MORE THOUGHTS ON NETWORK CHARGING

MikeDG, commenting on my last blog on this subject, focuses on other competition analogies in telephony, and poses the question of how much difference there is likely to be between transmission and distribution networks. So I will try to partially answer this question while at the same time reflecting on the conflicting objectives to which network charging in the power sector might be subjected. I cannot pretend to have a clear and unambiguous answer, and it is probable that no solution will satisfy all the objectives, but it is at least worth rehearsing the questions.

One set of basic challenges stems from the fact that there is a strong case for using network pricing to convey economic messages for energy production and consumption, given the network structure that is already in place, but also to influence future investment in production and consumption and in the network infrastructure itself. The problem is that these worthwhile objectives can themselves produce conflicting answers, for the simple reason that there is a huge gulf between short run marginal costs, which matter for operational purposes, and long run marginal costs, which include the much larger capital costs associated with constructing or reinforcing transmission and distribution networks.

The other set of challenges stem from the history of the electricity sector, and the high voltage transmission and lower voltage distribution networks within it, as regulated monopolies. On the one hand this means that private investors have to be guaranteed a “reasonable” rate of return on their investment. But it also means that they are subject to a number of constraints that reflect social objectives, such as requirements to provide something approaching a universal service, and to set prices that are deemed to be fair and equitable, even if this conflicts with economic efficiency.

It is also in this context that competition issues are most likely to arise. Electricity networks are usually assumed to be natural monopolies, and this assumption is now generally much stronger than it is for mobile telephony. The competition issues are not about competing networks but relate to regulatory and licence requirements for network operators to provide broadly similar non-discriminatory terms to all parties in those competitive markets, such as power generation and retail supply of electricity, which depend on the network for transport to their customers. 

Given these potentially conflicting objectives and constraints for network pricing, the transformation to a low carbon power sector is going to pose some new problems, not least because of the additional electrical loads associated with electric vehicles. Here are a few.

1.       Network operators want to encourage consumers to avoid overloading networks at peak times, and can impose time of day charges for network usage that are highly differentiated and reflect operational objectives, short term costs and capacity constraints. But with conventional approaches to time of day tariffs, attempts to smooth peaks can be highly unstable, requiring regular tariff adjustments which undermine the incentive properties as far as consumers are concerned. Large commercial consumers can shift their load significantly through battery technology and other demand management measures, but if the utility is relying on highly differentiated prices to recover its allowed revenue requirement it will be forced back to higher reliance on fixed charges, negating any investment the consumers have put.

2.       The basic structure of network costs is that they are dominated by the fixed costs associated with the network, essentially the costs associated with installing wires and transformers. The future of the power sector is one which is increasingly dominated by fixed rather than variable (fuel) costs in generation and storage as well as in the networks, and this will put an increasing pressure on utilities to reflect this in charging structures. If they do not, then they may be vulnerable to cherry picking and adverse selection problems from customers going “off-grid” and paying too little for the back-up services they receive.

3.       Traditional regulatory pressures will militate in the opposite direction, continuing to seek an equitable approach to pricing that essentially equates to an averaging of costs over all units consumed.

4.       There is evidence that some new loads, including electric vehicles and heat pumps, will pose particular issues in rural networks, which have relatively tight thermal and voltage constraints. Dealing with this may require much more differentiated pricing signals, but this will run against traditional practices and also raise discrimination questions.

We should expect these factors to generate an increasing number of analytic and policy issues as we move towards an increasing electrification of the energy economy.

NETWORK CHARGING IN THE POWER SECTOR. CONTRAST WITH MOBILE TELEPHONY AND A MAJOR ISSUE FOR THE FUTURE.

A combination of a New Year break and attempting to digest the barrage of dramatic political news with the inauguration of the new US President has limited my writing time in the last few weeks. I am going to restart 2017 with a few further reflections on the problems of network charging, picking up on the first comment received below. [2 February 2017.]

Trends in renewable energy and decentralised generation are a huge threat to the conventional business model for power utilities. There is no read across from mobile telephony and some major challenges for public policy.

Network charging promises to be a subject that, with a growing proportion of renewable energies, and especially with the growth in decentralised and off-grid systems, is simultaneously important, intellectually challenging and controversial. It may be worth starting with a few comparisons with charging structures for mobile telephone networks. Prima facie some people assume that the questions should be very similar, and that there is therefore an easy read-across between these two types of network.

After all both can be considered, as a first approximation, as dominated by high fixed cost elements and near zero marginal cost. But there are also some profound differences.

1. The capital costs sunk in the fixed asset part of mobile network are smaller – a few masts as compared to a complex structure of overhead and buried lines, wayleaves, transformers and substations, plus physical connections to each property/ consumer. This is one explanation that mobile telephones, unlike landline networks, and unlike gas and electricity distribution networks have never been regarded as a natural monopoly. The social and other constraints placed on the operation of a natural monopoly that is also an essential service are a major factor in explaining why charging structures have developed differently.

2. When you buy a mobile phone service, one of the main choice you are making, and a major part of the service you are buying, apart from the phone itself, is the network coverage. So paying a fixed charge, which may differ between providers according to the quality of their overall geographical coverage, makes intuitive sense. You are paying for connectedness when you yourself may be in a wide variety of locations. You are not paying for a dedicated local connection.

3. Most of the time mobile phone networks are operating well within capacity. The same is often true of electricity networks although there are increasing pressures to manage peak loadings through time of day tariff incentives. But perhaps the key difference here is that mobile telephony consumers are accustomed to a much higher degree of unreliability than is acceptable for utility services like power and water. It is also difficult for consumers to differentiate between signal, handset and capacity limitations.  So there is inevitably less consumer pressure and less economic or commercial incentive for providers to use price to manage consumption.

Whatever the differences in these economic structures, there seem to be some big consequential differences in the approach to pricing. Mobile telephony places a much higher level of emphasis on fixed or “standing” charges, while the tendency in gas and electricity networks is to average the fixed costs over the units (kWh) of consumption. There are at least two plausible explanations.

Historically and politically the impact of regulated monopoly is important.

A fixed charge for connection and distribution has always been seen as regressive, since it appears to penalise small consumers. “Cost averaged” kWh charges look more equitable. There has always been a strong "political" resistance to even quite small standing charges. Per unit charges would also have been built into the charging structures of the early (monopoly) local utilities as a good marketing tool to get more people connected in the first place, ie downplaying the fixed charge component. And of course regulation of the sector monopolies has had a major impact in imposing universal service obligations or their equivalent, and also very high levels of system reliability.

This model is now under threat, partly because the potential impact of consumer self-generation and “off grid” activity threatens the monopoly model. It is usually only monopolies, de facto or otherwise, that are able to cross-subsidise one group of consumers at the expense of another.

The real key may be the threat of adverse selection in the competitive markets that constitute mobile telephony?

Mobile telephony is a competitive market, so that any provider getting the structure of charges wrong will suffer adverse selection.  This might tend to favour a fixed charges approach as follows.  Many or most consumers place a high value on having access to a network even if they are relatively low or infrequent users, but the marginal value to them, ie price they would be prepared to pay for an additional minute of conversation time is very small. So any charging pattern based solely on usage would attract the low usage customers, lose the high usage customers to other providers, and consequently fail to cover fixed costs.

In other words the risk of adverse selection forces competing companies to adopt pricing strategies that are closer to their real cost structure. There are some quite complex tariff structures that do relate to volume but these tend to reflect at least in part an attempt to price discriminate by extracting a higher cost recovery from high users who are in fact less price sensitive and prepared to pay a little more. And they often take the form of a higher upfront charge with a higher free usage entitlement, usually without a marginal charge attaching to a particular call.

Problems for future electricity distribution networks? 

What is now happening therefore is that more people are going partially “ off grid” and in consequence undermining the traditional network pricing model. This is analogous if not identical to the adverse selection issue.  The “off grid” consumers still want connection to a network qua network, and the back-up provision of power that that network provides. But the per kWh pricing structure allows them to escape having to pay the real cost. So the loss of monopoly is undermining the regulated utility business model. The situation is potentially unsustainable and poses some major public policy and regulatory issues, especially if network utilities are forced to revert to a much higher reliance on a fixed charge component of their tariffs.

DOUBLE STANDARDS FOR RELIABILITY IN POWER SUPPLIES. NOT SUCH A BAD IDEA.

It was reported this week (FT, 12^th 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 21^st century power systems.

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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

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[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.

GRID SCALE BATTERY TECHNOLOGY IS COMING. INTERESTING QUESTIONS FOR COMMERCIAL ADOPTERS AND SYSTEM OPERATORS.

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.  

BRIBERY, CORRUPTION AND BLACKOUTS

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]

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[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

FUTURE FOR THE NATIONAL GRID. THREE HEADLINES SAY IT ALL.

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.

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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.