What Matters Most? Population, GDP Growth or Technology.
A common theme in popular discussion of climate change, or rather of whether mitigation is feasible, is its attribution to different factors, notably population growth or economic growth, and the reliance of solutions on technology. This also affects any discussion of historic responsibility for CO2 emissions. It is a highly emotive subject, particularly in relation to population control or the limitation of growth, so it is at least worth a cursory look at what the hard statistics tell us.
The so-called IPAT equation represents a general description of human influence on the environment: IMPACT (of CO2) = [POPULATION] X [AFFLUENCE] X [TECHNOLOGY]. A popular and useful way of interpreting this for CO2 emissions for the energy sector is the so-called Kaya Decomposition. Affluence is measured as GDP per capita and technology is further decomposed as energy per unit of GDP, and CO2 emitted per unit of energy. The Kaya identity is:
Global Picture. The IPCC Fifth Assessment Report (2014) provided a useful breakdown of changes in global CO2 emissions over several decades, based on this identity:
In the three decades from 1970 to 2000, population growth and increasing incomes contributed similar amounts to the rise in emissions, but the energy intensity of GDP fell quite sharply contributing a significant saving to the level of emissions that might otherwise have been expected.
The energy intensity of GDP was a significant offsetting factor, whose importance rose in 1990-2000, possibly reflecting the longer term impact of higher energy prices and uncertainties in the 1970s and 1980s. However efforts to reduce the carbon emissions associated with energy use played only a limited role in reducing emissions. This is unfortunate since reduction of dependence on fossil fuels this is a key component of emissions reduction hopes, and this factor actually moved in the wrong direction from 2000-2010, again reflecting in part the Chinese dependence on coal.
From 2000 to 2010 the importance of rising incomes rose relative to population factors, reflecting inter alia the rapid growth of the Chinese economy. The overall outcome was particularly depressing as the decade showed a sharp increase in emissions and lessening impact of the mitigating factors.
Major regional and temporal differences
But this decomposition can change significantly over time. Global averages also conceal major differences between countries, and there are some optimistic signals. A similar but more recent chart for China (Safonov reference below) shows overall reductions (to 2016), and significantly more reductions attributable to less energy intensive GDP and less carbon intensive energy. For China, population growth has not been a significant factor over this period, but income growth continues to be so.
Similarly more optimistic trends have been observed in the USA to 2015, but with higher influence from population, less from economic growth, and significant reductions attributable to less energy intensive GDP and less carbon intensive energy consumption.
An interesting comparison of country by country decomposition for periods before and after the financial crash of 2008 is given in a fairly recent paper by Sadorsky, referenced below. It shows huge diversity in findings between countries, exemplified in the following chart for four countries:
NB. This chart has a rather more complex interpretation, as it represents the changes between two very distinct periods. The reader is referred to the Sadorsky article
Kaya factors. The future.
Given the pace of reduction required to reach net zero by 2050, the Kaya emphasis will have to shift to much greater emphasis on decarbonising energy. Population cannot be subject to substantial percentage reduction, and the drive for higher incomes is unlikely to stop. There is some scope for further weakening of the link between affluence and energy use, but the heavy lifting will depend very substantially on decarbonisation of energy, starting with the power sector and expanding the power sector into transport and heating.
IPCC Fifth Assessment Report.
George Safonov's Lab. National Research University Higher School of Economics, Moscow. Long-term, Low-emission Pathways in Australia, Brazil, Canada, China, EU, India, Indonesia, Japan, Republic of Korea, Russian Federation, and the United States. December 2018.
Sadorsky, P. Energy Related CO2 Emissions before and after the Financial Crisis. Sustainability 2020, 12, 3867. https://doi.org/10.3390/su12093867
Dr Ajay Gambhir, Neil Grant, Dr Alexandre Koberle, Dr Tamaryn Napp. The UK’s contribution to a Paris-consistent global emissions reduction pathway. Grantham Institute. Imperial College. 2 May 2019.
Public Utilities Fortnightly. First Look at 2015 CO2 Emission Trends for the U.S.
For a fuller “actuarial explanation and justification for the Kaya identity, this reference may help Kaya identity_JC Final 050219.pdf (actuaries.org.uk)
 Since the identity is multiplicative, a logarithmic transformation is usually used in the calculation of the factor contributions.
Here are some back of the envelope calculations that demonstrate the credibility of the assertion that action to mitigate climate change, and progress to a low carbon economy, can be achieved at a containable cost. It aims to provide a simple intuitive defence of conventional estimates for the general reader, but serious students of the subject are invited to delve deeper into some of the excellent material produced under the aegis of the Committee on Climate Change.
One of the arguments mounted against taking effective action on climate is that the economic cost is unaffordable. The obvious response is that this has to be compared with the cost of not taking action, the costs of adaptation, and the possibility of existential climate threats on an unimaginable scale. However rather than engage with the occasionally hysterical accusations of alarmism from those in denial on the climate science, it is worth trying to get a sense of the scale of what may be involved in meeting a UK zero carbon target by 2050. Some sense of proportion should start to defuse the issue and calm any fears of national bankruptcy.
This can be a confusing exercise, not least because estimates (of mitigation costs) tend to get tossed around in very different contexts. For example, it’s most common for costs to be discussed in very broad terms as a percentage of GDP. The Stern Review indicated costs of up to 2.0 % of GDP per annum, and some people have argued that this would be a very damaging and unsustainable burden in macro-economic terms. The Committee on Climate Change currently makes a similar estimate (of 1-2 % of GDP). Others argue that Green investment can actually be used to boost economic growth and domestic employment. There can be at least a partial truth in this argument, even if it can be misrepresented as arguing that the low carbon economy pays for itself. It is not an argument I intend to deploy here.
Some will be more concerned with the public expenditure implications, although that issue should be seen much more in terms of more political questions of how we choose to fund transformational change. For example, much of the cost of transition to low carbon may be carried by private consumers, in their utility bills or more expensive motoring choices, or it may include publicly funded infrastructure investment and extensive grants and subsidies.
Macro-economic shocks and UK GDP numbers
2019 GDP (last year before pandemic) £ 2170 billion pa
Estimated permanent loss of
GDP due to 2008 financial crisis £
300 billion pa
The economy is 16%, or £300 billion, smaller than it would have
been had it followed the pre-crisis trend. (IFS 2018)
Typical impact of an oil price
shock in 1970s, 1980s and 1990s. £ 100 billion pa
(an order of magnitude estimate, based on spikes and falls in
the oil price of $100/ bbl, UK consumption of 100 mn tonnes pa,
and scaling up to an equivalent percentage of 2019 GDP)
I have not included the significantly larger shifts in resources associated with different government priorities on taxation and spending. Even so, the conclusion we might draw here is that the expenditure on a low carbon economy, while substantial, is far from catastrophic and unmanageable when viewed in macro-economic terms. We have coped with much larger and less predictable economic shocks than what we now face in eliminating emissions.
Public expenditure choices
Expenditure budget 2021: £ 908 bn.
Defence £ 54 bn pa
Defence in 1951 (Korean War) accounted
10% of GDP. Equivalent percentage of 2019 GDP £ 217 bn pa
Overseas aid (0.7% of GDP target) £ 15 bn pa
Overseas aid (after current cuts) £ 10.85 bn pa
Reported cost of UK Track and
Trace system £ 37 bn
(spread over two years but seems to be essentially
a 12 month figure). Minimal identified benefit.
Assumption of a 2% of 2019 GDP
devoted to GHG £
43 bn pa
reduction and low carbon transition. (as above)
But what can you buy for 2% of GDP?
It turns out you can do quite a lot for decarbonisation with around £ 40 billion a year. Here is one allocation of that money:
Decarbonising the power sector. £ 18 bn pa
Retrofitting UK housing stock.
28 million households £
20 bn pa
Grant of £ 20,000 per household for retrofitting, at one million
households a year for 28 years
Charging infrastructure for electric vehicles (EVs) £ 2.5 bn pa
Total £ 40.5 bn pa
This covers the three main sources of UK emissions, and the main areas for investment to achieve net zero by 2050. Assumptions to justify the plausibility of these numbers are as follows
Sizewell C has an estimated capital cost of around £ 18 billion for 3.2 GW of capacity. Nuclear is currently regarded as one of the more expensive options for low carbon capacity, and Sizewell is “first of a kind” but this at least gives us an order of magnitude. The equivalent of one Sizewell a year for 25 years delivers around 80 GW of capacity and more than 600 TWh pa of energy, more than enough, even after allowing for significant growth, to effectively decarbonise a power sector which already has a significant proportion of renewable low carbon energy. [Current UK annual consumption less than 350 TWh]
Alternative renewable sources are also widely seen as likely to be much cheaper than this, although there will be other major costs associated with energy storage. However we might interpret this as at least a first approximation, or an upper limit to the capital cost for low carbon generation. A great deal of new investment would of course be required in any case, so much of this will not be a truly incremental cost.
Heating of buildings
Retro-fitting of buildings, especially residential property, for energy efficiency and low carbon heat pumps or heat network solutions, is one of the biggest problems for achieving zero carbon. The cost of air or ground source heat pump installations are currently advertised at around £ 6000-8000 and up to £ 16000 respectively, while heat networks are collective typically municipal investments which can also be quite costly. But even adding on a substantial allowance for insulation improvement, £ 20000 per household would look like an extremely generous grant to a householder, especially as there would be a continuing benefit in lower running costs.
“The UK by 2040 needs 1-2.5 million new charging points. An average public charging point costs 25-30,000 euros so it would need to invest 33-87bn euros from now until 2040,” said Wood Mackenzie’s Wetzel. Interpreting this as two million over twenty years and assuming a cost per installation of £ 25000, this implies an annual investment of £ 2.5 billion.
The price of EVs is likely to fall dramatically with increasing scale, so we should not need to worry unduly about the capital costs of fleet replacement, which will be borne by motorists as they retire their existing vehicles.
Current estimates of expenditure required for a zero-carbon economy are plausible. In no sense can they be considered unattainable or damaging in macro-economic terms, as the sums are smaller and more predictable than the much bigger economic shocks we have endured in recent decades from other sources. Viewed as public expenditure choices the sums are commensurate with other choices we make and have made, such as the unfortunate “test and trace” scheme. An it is quite easy to hypothesise major elements in the composition of that expenditure.
Caveat. Sharp-eyed readers will have noticed that I have omitted some of the notoriously difficult, but smaller, sectors, such as aviation and shipping. But I believe the biggest additional issue will be the funds that high income countries will need to find in order to support low carbon strategies in the developing world. That is a different story, and one that I have addressed in earlier posts this year.
 This post concentrates on UK statistics but the same arguments, and similar orders of magnitude, will apply to most developed economies.
 Retrofitting the UK housing stock, and many other infrastructure investments, will be labour intensive.
 10 years on - have we recovered from the financial crisis? - Institute For Fiscal Studies - IFS. Paul Johnson and Jonathan Cribb. 2018
 The UK became a net oil exporter during this period, so the macro-economic consequences for the UK relate both to price shocks and significant changes in production.
 “Chancellor Rishi Sunak’s Budget last week included an additional £15bn for test and trace, taking the total bill to more than £37bn over two years.” [Independent. 10 March 2021]
This is the substance of a recent talk I was asked to give at a recent COP26 roundtable in Turkmenistan. It is an attempt to summarise, for policy makers, some of the general principles we have learned in the course of the Oxford Martin School Integrate project.
First, the context. A low carbon power sector has a central role in reducing CO2 emissions and making progress towards zero carbon. This is not just because fossil-based power has high emissions and we already have numerous technologies for low carbon generation. A low or zero carbon power sector means we can progressively use electricity solutions to reduce CO2 emissions in other major categories, notably transport and heat.
The task then is developing and integrating renewable and other low carbon energy resources into power systems that deliver what we need and expect. The main factors that have to be respected and reconciled are the following:
· Power systems require flexible responses to balance real time supply and demand.
· Low carbon sources (mostly) lack the flexibility of traditional thermal generation plant using coal oil or gas.
· Renewables output can be intermittent and unpredictable
Today I am going to summarise some of the general principles we have learned in the Oxford Martin School. The principles apply not just to the UK but in virtually all power systems. However, lesson one is that every country and every network is different, in terms of its available resources, its climate, weather and seasonal effects, and the needs of its consumers. So the best choices for the future will also be different.
Framing the Policy Choices
We have used this diagram to represent the task, and the large number of questions that need to be addressed. The potential resources and activities that we can manage, the options available to the power sector, are shown in the top row - generation, storage, networks and consumption. Costs are generally coming down.
The policy instruments that we have to manage these options can be categorised, in the left-hand column, in terms of technology and innovation, the wise use of markets and price signals, social engagement in the process of change, and finally the whole framework of law, organisation, policy, regulation and governance on which the sector depends.
There are 16 cells in this 4x4 matrix, and there will be important questions in almost all of them.
Starting with the resources, choices involve selection from a long menu, much of which I am showing on this slide. Virtually all the items here feature in the UK as part of our likely solutions, and they are all potentially important. I will just comment on a few highlights.
· When we look ahead to planning the power sector, we have to look not only at the current use and applications of electricity but also at its substitution for other fuels in new applications, especially transport and the provision of heat. This implies coordination across sectors.
· Electric vehicles especially have the potential to play a huge part in the operations of the power sector.
· Interconnection. The recent power crisis in Texas has highlighted the importance of interconnection and the risk of isolation.
· Solving the storage problem is one of the most challenging parts of the exercise, at least from a technical and economic perspective.
· Consumers are also a vital part of the system, technically, economically, and politically. They merit a separate conference on their own.
Technical and technology choices
The choices have to be complementary rather than exclusive. This will involve substantial computer modelling of alternative combinations to find out what works best.
So the balance, getting the right mixture, of solar, wind, biomass and other sources is essential. For the UK, for example, meeting seasonal variations is very important, implying a higher ratio of wind to solar.
Storage is going to be important everywhere. Battery technology and pumped hydro, possibly some interconnection, combined with the ability to make use of more time-flexibility in consumer demands, will mostly be more than adequate for smoothing daily variations. But inter-seasonal storage is potentially a much bigger problem, unless the capital cost per unit of energy stored can be greatly reduced. The most promising answer appears to be conversion of renewables output into high energy forms which can be stored more cheaply. Hydrogen may be the preferred long term storage option at the present time, but there are other contenders.
In the UK, a bigger issue than seasonal storage may turn out to be risk of prolonged periods of low wind. Some modelling has simulated the effects using weather data over the last 40 years, and this has proved a useful exercise.
Markets and prices
These issues have related to technical planning, and available innovations, but there are also major implications for markets, governance, and the management and control of the sector. Turkmenistan and the UK have very different starting positions. Turkmenistan starts from a position of government ownership and control of the power sector, and supply to many consumers has been free. The UK has private ownership and some market structures but also has increasing government involvement in underwriting new low carbon investments, and in ensuring coordination within the sector. Despite these differences, I believe that there are some important common principles.
One is how to choose the most efficient plant to operate. In the UK we call this the merit order. As we progress towards low carbon economies, this will normally imply the plant with lowest CO2 emissions per kWh. In the UK and Europe this means that a price has to be attached to emissions and that must impact on the economic choices made for the sector. But it is also true that the task of managing power systems effectively with high renewables presents new challenges. In the UK we are also having to re-examine the methods that we use to get the most efficient operation of the system. The optimisation methods designed for a world of coal and gas generation are not necessarily the right ones for a low carbon system.
Consumer tariffs are very important. They are central to the ecology of the power sector as the primary means of communication between production and consumption. The priority attaching to reduced emissions is such that this should be reflected in cost reflective pricing. Tariffs are even more important if we need to promote more flexible demand. We expect to see some profound changes in the nature of the services provided by electric power in meeting consumer needs.
Finance and Governance
My last big economic issue is financing. It is widely held that collectively the world has a glut of savings waiting to be invested in useful projects. Also, the cost of capital is at historically low levels. But to access that capital, for any country or industry dependent on external or private finance, it will be essential to demonstrate that the investment is going to be well managed. The institutional structure is important for that and also for successful implementation.
This means ensuring a good and stable legal and institutional framework within which low carbon investments can be delivered, and one that banks, the World Bank and others, or other investors, can rely on. That of course depends on the commitment of governments, in the UK as much as anywhere, to low carbon objectives.
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 is Vice-Chair of ERCOT, the body that has coordinated the Texas power sector over this period, and has described 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.  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.
 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.
 Oxford Review of Economic Policy, Volume 33, Issue 4, Winter 2017, Pages 589–612
 In Texas VOLL was set administratively at $9,000/MWh—367 times higher than the average energy price of $24.62/MWh in 2016.
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.
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 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, 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.
John Rhys on Energy, Climate and Carbon: FINANCIAL SUPPORT FOR ENVIRONMENTALLY SOUND POLICIES IN POORER COUNTRIES MAKES SENSE FOR EVERYONE. THE CASE OF FIREWOOD, CHARCOAL AND DEFORESTATION. (co2economics.blogspot.com)
Energy and Transport in Africa and South Asia. Katherine A. Collett, Maximus Byamukama, Constance Crozier, Malcolm McCulloch February 2020
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 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”, 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, 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.
 Use the button LOW CARBON POWER at the top of this page for a more wide ranging discussion.
 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.