Saturday, February 20, 2021



Viewed as independent countries California and Texas would both rank among the ten largest economies in the world. One Democrat and the other Republican, the feature they now have in common is failure to prevent extensive and disruptive interruptions to power supply – California in 2001 and Texas in February 2021. In both states near-catastrophic failures raise questions as to the viability of highly market-driven power systems, which contrast with the stability of more integrated models of the East Coast of the US, and internationally. The answers matter, not just for Texas, but for developed and developing economies everywhere.

In California, the new market structures had only recently been introduced. California had copied many features of the UK 1990 model, which had worked successfully, or at least without major mishap, for ten years. With the benefit of hindsight and a lot of analysis, there seems to be a reasonable consensus that the failures resulted from a combination of factors:

·         Weaknesses in the design of the new market structures

·         State regulatory authorities’ imposition of a price cap, which prevented the market working as it should, to reduce demand and increase supply.

·         Market abuse by Enron, notoriously exploiting the rules to gain large economic rents. Enron went on to become a major corporate scandal, but California was the setting for some of its most egregious wrongdoings.

The recent failures in Texas, celebrated as an example of liberalised market reform, are harder to explain. Unusual weather conditions may be a proximate cause but are hardly an adequate excuse for one of the wealthiest advanced economies in the world, in a liberalised power sector that has appeared to operate without serious mishap since the late 1990s. The other factor cited, the intermittency of wind, can be dismissed as a credible explanation; if relevant at all, it is a known risk that should have been easily managed in a well-functioning sector. We need to look further for adequate explanations of failure to provide reserve capacity.

Creating incentives for private operators to provide the level of reliability that the public want has always been a potential weakness of market-driven systems, usually resolved by the imposition of reserve margins, and financial incentives or penalties. Peter Cramton[1]  is Vice-Chair of ERCOT, the body that has coordinated the Texas power sector over this period, and has described[2] the approach taken to this problem in Texas. It is an administered scarcity price similar to that used in the 1990 UK reforms, which operated successfully up to the introduction of further changes in 2000.

A market in reliability

The Texas model, according to Cramton, sets out the rules to determine an administered scarcity price, in periods when there may be very high or peak demand or low supply.  In theory this should incentivise sufficient capacity (Q) at all times. The administered price aims to reflect the value of lost load (VOLL), and a high VOLL should in consequence result in high reserve margins for generating capacity. Texas sets a high value for VOLL. [3] Simple economics suggests high rewards will bring forward more than adequate supply.

One possible explanation for the current failure is simply that this scheme lacks credibility. If we look at these incentives for investors in potential reserve capacity, then the return on investment – the future revenue stream – may depend on achieving ultra-high prices in periods with an ultra-low probability of occurrence. This probabilistic estimate may indicate good “expected value” returns, but the very high chance of zero revenue is not attractive as a basis for large scale investments. Paradoxically the higher the value of VOLL, the rarer the occurrence of periods of scarcity and the less credible the projected revenue becomes. 

Closely linked is the matter of regulatory credibility: if prices need to go that high, as they must do to validate the investment in reserve capacity, and particularly if the price spikes impact on consumers, will the regulatory or political authorities really stand aside and let them happen? The 2001 California experience, at least as suggested in many accounts of that event, suggests otherwise.

What do UK market models tell us?

The UK used its own version of an administered scarcity price from 1990 up to 2000. Fortunately, this was a period with a legacy of surplus capacity, so the method was not subject to severe stress tests. It worked well but was also criticised for potentially allowing larger generators to exploit their market power. It was replaced in 2000 by trading arrangements which had no formal mechanism for capacity. It rapidly became apparent, however, that these would not incentivise new capacity, and would pose an increasing risk to reliability of supply. The UK moved gradually towards the establishment of capacity markets to supplement the new arrangements.

In practice this means that investment in new capacity does not depend on investors responding to market price signals and guessing future prices in the “energy only” electricity market.  Virtually all new UK generating capacity results either from government choices, long term contracts (nuclear plant), from feed in tariffs, or from capacity auctions.

If fixing prices (P) doesn’t work, try fixing quantities (Q)? P or Q?

Economists will be familiar with markets where the choice is to use price or quantity as the appropriate instrument of policy. A good illustration is the energy policy choice between a carbon tax (P) and setting emissions quotas (Q) which can traded. It is possible for the price and quantity outcomes to be the same under either regime, but the choice is important and is usually made on an empirical or pragmatic basis, of what is likely to work best or be more politically and socially acceptable. The UK approach, de facto, for reliability, is to concentrate on fixing Q.

In this context, capacity markets can fix Q if a central authority – government, regulator or utility – decides on the reserve margin and the reliability standard, and invites tenders to provide that capacity. This has the advantage of much more certainty that the reserve will be provided, but it places the onus on the central authority, not just to decide how much capacity but also, in practice, to determine the right technology mix, and to monitor delivery. It represents the abandonment of most of the tenets of a market fundamentalist approach to the power sector.

Regulation and Governance for the Power Sector

It is always tempting to read too much into a single event, when there will inevitably be multiple interpretations of what has happened, and rarely one simple explanation. Another focus will no doubt be on the general governance and regulatory arrangements in Texas, and the role of ERCOT (see below). However, the “standard model” of unbundled utilities, wholesale and retail competition, independent regulation and excessive reliance on markets, however flawed, must come under more scrutiny. Pioneered in the UK, promoted by the World Bank, the European Commission and others, it looks increasingly incapable of responding to today’s policy challenges, of which the climate emergency is just one.

[1] Cramton is an academic economist, who has described and indeed promoted market-driven models for the power sector. He described the role of ERCOT and the power sector in Texas in a paper - Electricity Market Design - in the Oxford Review of Economic Policy.

[2] Oxford Review of Economic Policy, Volume 33, Issue 4, Winter 2017, Pages 589–612

[3] In Texas VOLL was set administratively at $9,000/MWh—367 times higher than the average energy price of $24.62/MWh in 2016.


Additional Notes.

A regulatory issue. There is another feature of the power sector in Texas which is at odds with the “standard model” of liberalised markets and independent regulation. The Electric Reliability Council of Texas (ERCOT) effectively controls the functioning, in operational terms, of the Texas power system. It is an umbrella organisation, whose membership includes the utilities, generators and other stakeholders in the sector. It implicitly assumes responsibility for reliability and by its nature provides scope for formal or informal coordination within the sector. This might be interpreted as a quasi-regulatory role, violating one of the conventional principles of sound regulation, namely that the regulator should be independent of ownership and management.  There is an additional oversight from a Texas Public Utilities Commission, but it is unlikely this will have had the knowledge or expertise to probe ERCOT too closely, especially on technical issues

It is possible to argue that ERCOT also provides a vehicle for informal planning or informal guarantees for future investment, and that coordination and more rigorous planning disciplines, plus technical monitoring of capacity, should have been applied.  I would argue in this instance that it was reliance on a “market” mechanism that is the more likely prime cause of the failure.


California. See for example Weare, Christopher (2003) The California Electricity Crisis: Causes and Policy Options  ISBN 1-58213-064-7;


There is another important alternative to administered scarcity prices. It is to allow scarcity prices to be set in a market by consumer choices and consumer valuation of reliability, but that is generally seen as currently impractical, because consumers lack the technical capability to respond quickly to price or crisis signals. However increasing digitalisation, and concepts like differential reliability and supplier managed loads- see my tariffs paper - will take us in that direction in the future. 


Thursday, February 4, 2021


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A recent FT article argued the importance of electric vehicles in Africa, as an essential component of a global strategy to limit emissions and combat climate change. A predictable response from readers was that this was wholly impractical on the grounds of both affordability and the current inadequacy of African power systems. Healthy scepticism is fine but it should not obscure the fact that it is in an African and global interest to leapfrog to an electricity based transport technology. Electric vehicles can be part of the solution for Africa’s power systems, not just another problem.

Vome Aghoghovbia-Gafaar writes[1] on “Why Sub-Saharan Africa’s teeming cities need electric vehicles.” The response from FT readers was sceptical, making the seemingly obvious points that Africans will not be able to afford expensive Teslas, that even developed countries are struggling with the infrastructure electric vehicles (EVs) require, that Africa largely lacks adequate power supplies, and that better mass transit systems are perhaps a more immediate transport priority for Africa’s mega-cities like Lagos or Dar-es-Salaam.

Healthy scepticism is fine, but there is a wider case for EVs in Africa, and it builds on the almost universal imperative to move rapidly towards low carbon sources of electricity as a substitute for fossil fuel use. The big issues for this target in Africa are first the absence of affordable electricity, and second the unsustainability of clean economic development without it.

The global imperative is that unless we can achieve a transformation of the power sector in Africa, which enables both economic development and a switch to low carbon fuel sources, then the chances of meeting global emissions and climate targets are very low indeed. That reality should condition our judgements on the realism of prospects for overcoming the undoubted obstacles

From my experience the biggest single barrier to resolve the first issue – affordability – is likely to be the very high component of fixed cost, which especially in poor communities has to be spread over a small number of kWh. The only way to get the unit cost down is by much higher volumes, but these are often hard to achieve.

Africa has some of the highest unit costs and prices for power in the world, as well as many of the poorest people. This combination makes it particularly difficult to build the volumes, and the economies of scale, which are ultimately the only ways of bringing these costs down.

For rural electrification, involving some of the poorest communities, the World Bank has estimated kWh costs could be brought down to about 22c per kWh with the achievement of reasonable load volumes and a 40% load factor. Neither of these conditions is easily met, however. Moreover much of Africa is well endowed with solar power, but the management, even of small systems with intermittent energy, is problematic in the absence of storage or back-up. And similar issues can be expected in urban systems.

Electric vehicles help with both problems. It is intrinsically a large load, and with a high percentage of EV batteries connected to the grid when the vehicle is not in use, eg in the evening, this creates significant opportunities to improve load factor, substantially reducing the unit costs to other productive uses of electricity, and to cooking. The latter in particular offers a big environmental benefit. Electricity can substitute for firewood or charcoal, whose continued use has disastrous consequences for deforestation as well as a large carbon footprint. The scale of emissions from these unsustainable sources is comparable to that of diesel used as a transport fuel.

As an idealised solution, therefore, promotion of electric vehicles in Africa can provide a classic synergy in terms of reducing emissions, providing clean energy and assisting economic development. In itself it reduces harmful emissions, a global CO2 benefit, as well as localised city pollution. The key to the economics is that if the vehicles and their batteries are already there, some of the essential but very expensive storage requirement of renewable power systems is already in place.

The additional load permits more effective management of renewable systems and much higher load factors. Both these gains would have a big impact in reducing unit costs, and this in itself could create a virtuous circle of more affordable power, more productive use of that power, higher incomes and improved affordability, feeding back into further economies of scale, cheaper power, and less polluted cities.

Measuring the benefits

In an earlier post[2], I discussed the benefits of eliminating traditional and unsustainable use of firewood or charcoal for domestic cooking. The potential reduction in CO2 emissions is huge. Charcoal use is widespread in the developing world and its elimination for a billion people (a conservative estimate of potential) could reduce global emissions by as much as 700 million tonnes or about 3 % of the total. The nature of the emissions externality is that the benefit accrues to the global community as a whole, not just to Africa. But the scale, with any reasonable valuation of carbon, is huge

The contribution from eliminating oil dependent road transport in Africa could be of a similar order of magnitude, with a similar global benefit.

How realistic is all this?

As electric vehicles take an increasing market share, some of the barriers are likely to fade away. Scale economies will bring down manufacturing costs and prices to consumers, along with a new generation of vehicles made in China or India, probably with more basic specifications but significantly lower costs. Electric vehicles combined with electric cooking could, as suggested above, mitigate the technical and economic problems in developing the power sector

The biggest barrier remains the quantum leap required of African power sectors, partly in terms of governance but even more in terms of the sheer amount of capital required. Help from development aid budgets will be a necessity. But, as I have suggested above, failure in this task should not be considered an option. The global economic cost of climate catastrophe, or the cost of expensive carbon extraction from the atmosphere (which we shall almost certainly be forced to adopt) could make African electrification a bargain form of carbon reduction for wealthier nations.



Is sub-Saharan Africa ready for the electric vehicle revolution? | World Economic Forum (


Energy and Transport in Africa and South Asia. Katherine A. Collett, Maximus Byamukama, Constance Crozier, Malcolm McCulloch February 2020

[1] FT.  1 February 2021

[2] Reference and link at bottom of post.

Monday, February 1, 2021


In recent years we have witnessed the central role, everywhere, of governments dealing with massive market failures, or potential failures, in critical parts of the economy and society. The most obvious crises and interventions have been in the financial sector, and in public health. But attention is also now turning to the biggest crisis of all, the looming threat of climate change. As with the pandemic and with finance, this makes the risk of systemic failure in the energy sector something that governments, of whatever ideological complexion, can no longer ignore. This may be the end for the road for market fundamentalism in the energy sector.

National Grid faces being stripped of its role … after the energy regulator concluded an independent body would better oversee the changes required to meet the UK’s 2050 net zero emissions target. It would also avoid potential conflicts of interest and allow for the “greater strategic planning and management” of the electricity system. (FT, January 2021)

The wheel turns full circle. We are now a million miles from the “liberalised” structure of markets and governance, with all investment choice driven by market signals, and celebrated as such an achievement after the complex and innovative restructuring of the UK power sector in 1990.  The government has already resumed its role as the prime decision maker on new generation investment, and nothing substantial is built without a long-term contractual commitment on off-take that only government or a regulated monopoly can provide. Government has become the de facto "central buyer". The new proposal simply follows the logic of a return to a more planned and coordinated power sector by explicitly extending this role to transmission. Since transmission investment is frequently an alternative to additional generation capacity (most obviously with international interconnection), this seems entirely logical.

While it is still not clear what changes will result from the OFGEM proposal, one obvious deduction is that we are moving towards the creation of a new body with a strategic responsibility for planning and coordinating all significant future investment in the power sector. It would be hard to avoid linking this with the existing functions of government in securing new capacity, through auctions or other means. In its fundamentals this represents the re-establishment of the planning functions of the old Central Electricity Generating Board (CEGB), but without the CEGB’s functions of ownership and operation of generation and transmission. If this interpretation is correct, and the proposals are implemented, then this represents an essential development for which I have been arguing on this site[1] and in other media for many years.

To understand how and why, even with successive governments as the most enthusiastic promoters of theoretical “free market” philosophies, we have got to this position, we need to look at some of the basics of power sector and infrastructure economics, and also at the climate policy imperatives.

The Infrastructure Investment Problem

Investors in high capital cost and immobile assets typically require long term contractual or similar assurance. Their assets are almost always specific to one purpose, and depend on a secure long term revenue stream. Reliance on a spot market or short term contracts, the core components of electricity market structures and both dominated by short term factors, are just not good enough to satisfy private investors. This is particularly so for key investors like pension or sovereign wealth funds who are seeking secure but modest returns. And the low cost of capital these investors can provide is exactly what is necessary to keep electricity prices affordable.

Along with construction risks, the biggest risk to infrastructure investors is that, having sunk the costs of their capital investment, future revenues are exposed to opportunistic actions by other parties. These include government, regulators and customer utilities, all with political or economic incentives to attack their future revenue stream. The owner cannot transfer the asset to an alternative use or jurisdiction, and faces expropriation of expected revenues in the interest of lower prices to consumers.

The two main options are inclusion in a regulated utility framework (traditionally vertically integrated monopoly) in which reasonably incurred costs are passed to consumers, or long term contracts with or commitment from a reliable counterparty, usually the only plausible party being the government.   In the UK, network investments have in recent decades typically depended on the former, and generation on the latter (via CfDs, feed in tariffs etc).

Either remedy can work but both draw a monopoly utility, or government, into strategic investment choices. Both are a long way from the paradigm of the fully liberalised market.

The Coordination Problem

Recent complaints have focused on failure to coordinate offshore wind development with the transmission investment necessary to bring it ashore. But there are plenty of other examples of the need for coordination with low carbon systems, mostly reflecting the fact that these sources are less controllable than conventional thermal fossil plant.  Factors include the advantages of planning for diversity in the siting of wind facilities, the need to get the right seasonal balance of solar and wind, issues around storage and whether to treat it as supply or demand. It looks improbable that any of these issues can be resolved either through short term price signals from power markets, or by “technology neutral” invitations to bid new capacity.

The remedies are either informal coordination within the sector, which risks running foul of competition law or anti-cartel legislation, or a central direction of what types of generation are required.

I have previously argued that the National Grid already plays such a central role that one solution might have been an extension to include a more formal planning or even a central buyer role. But this may well not have been acceptable to a private sector management, and the OFGEM proposals may lead us to an equally satisfactory outcome.

The Carbon Emissions Externality

Climate change is the “biggest economic externality of all time”[2], to date addressed only to a very limited degree by carbon taxes or emissions pricing.  Low carbon prices, only partial in coverage, may be due to insufficient ambition or vested interest capture, but are grossly inadequate to match any serious estimate of the cost of the externality.

So failure to price emissions adequately means that market solutions cannot work on their own. Moreover the “Theory of the Second Best” implies that once we have one major failure in the market, like the failure to price carbon, we cannot assume that other policies, eg competition policy or a merit order[3], normally thought of as good, will actually improve welfare rather than reduce it. In our context even the best designed markets will produce the wrong seriously sub-optimal outcomes, for both operations and investment, if the damages of unconstrained emissions are not included in economic calculations.

Recent examples include the huge coal for gas substitution in 2013/14, driven by a temporary change in fuel price relativities, Dutch competition authorities prohibition of collusion between utilities to reduce coal use, and the UK exclusion of domestic gas, but not the power sector, from emissions trading.

But difficulty in allowing the market to “price” emissions is another prime reason why governments cannot and will not “leave it to the market” to meet its climate objectives. Societies can no more afford systemic failure in relation to energy and climate issues than in health or the financial sector.


Suggested reading.

ETI publishes industry perspectives on how to deliver efficient networks for a low carbon future energy system.  19 September 2016

Markets, Policy and Regulation in a Low Carbon Future. John Rhys. January 2016


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[1] Use the button LOW CARBON POWER at the top of this page for a more wide ranging discussion.

[2] Stern

[3] The merit order, in any power system, is simply a ranking of generating facilities in ascending order of cost, so that the cheapest are always used first to minimise total cost. If key elements of cost, in this case the damage from CO2 emissions, are not included, then there will be poor outcomes.