Wednesday, October 15, 2008


John Rhys. October 2008

Being forced to consider the possibility of new coal-fired generation looks prima facie like a failure, either of policy or of the market to anticipate and deliver requirements for sustainable low carbon electricity. This might be because the price signals on the cost of CO2 emissions (largely through the EU ETS) have so far been wholly inadequate, or because of other market failures. Or it might be that the policy simply lacks credibility with markets because market participants do not have confidence that the reward to low carbon generation will grow and persist. Or it might be that government itself has given mixed messages over its willingness to support nuclear or renewable alternatives. Not surprisingly Kingsnorth has become a “line in the sand” for many people concerned about UK policy in relation to emissions and climate change. This note does not dismiss out-of-hand the possibility of a case for Kingsnorth. But it does attempt to ask the questions that should be relevant to rational discussion of the issue, and which government and promoters of Kingsnorth should be prepared to address, and answer, before proceeding further.

It is sometimes difficult within a power sector of powerful industrial interests to get unbiased sources of analysis. Some of the relevant data sets and analyses, once collected automatically and subject to some public scrutiny while the industry was in public ownership, are either not collected at all or are protected as commercially confidential. However the need for public information about the policy justification for Kingsnorth is every bit as great now as it would have been if the proposal were being promoted by a publicly owned and publicly accountable Central Electricity Generating Board (CEGB). This note attempts to set down at least some of the questions that would have been put by the Treasury to the old CEGB, and need to be answered in any economic or policy justification of Kingsnorth. If the defence of Kingsnorth is that it represents a "market" solution, then we need to know how UK emissions targets are factored into the market calculations.

1. How reliable are the demand forecasts, particularly of winter peak demand, which supposedly establish the “need” for Kingsnorth?

- What are the forecasts and where do they originate within the sector? Are they taken from aggregation of supplier estimates, which would be obviously unreliable in a competitive market, or are they based on high level “top down” Departmental or other economic forecasts linking demand to GDP growth and relative prices.

- If the latter then there is an obvious criticism to be made: it is that since privatisation there has been no comprehensive programme of market and load research to assist in the production of soundly based forecasts? Long term projections based solely on econometric models often differ little from naïve trend projections, with a constant GDP/kWh elasticity, tend to fail in spotting new developments and have a poor track record.

- Even within a modelling approach do the forecasts reflect the most recent economic developments? We are probably going to lose the equivalent of at least one year’s growth in a recession, and quite possibly significantly more. Kingsnorth forecasts will presumably have been constructed on the assumption of steady trend GDP growth.

- Similarly do the forecasts reflect the likely downturn in house construction and new household formation, one of the drivers of residential electricity consumption in particular?

- Do the forecasts reflect the effect of higher fuel prices ? Much of the growth in domestic sector demand in the 1990s is likely to attributable to substantial falls in real prices which re-established electricity as a significant element in space and water heating (although this is not detected in official estimates, perhaps because we no longer had the basic load and market research that would have allowed actual measurement of aggregate consumption between usages). One might expect higher prices to reverse at least some of that growth over the period to 2020.

- Finally, do the forecasts take into account energy conservation savings anticipated from White Paper measures? If so, how?

2. Are there no other sources of incremental capacity?

One of the arguments for market forces is that a higher price, and reward for availability, will induce suppliers/generators to “find” additional capacity, not least by sweating existing assets a little bit harder. We should expect that with the right incentives, a surprising amount of additional capacity could and would be found. Options that would need to be explored include:

- any residual mothballed plant
- increasing the rated capacity or potential output of existing fossil plant

- life extensions to existing nuclear plant, including the cost of continuing to comply with nuclear safety requirements

- emergency generation facilities that would only be used at peak, or lower capital cost specialist peaking plant

- the possibility of emergency derogations for standby capacity under the EC Large Combustion Plant Directive (LCPD)

The last of these options is a particularly persuasive alternative. It would be somewhat contrary to achieve compliance with the LCPD only by engaging in an environmentally far more damaging investment in new coal plant.

3. If Kingsnorth were not permitted and no alternative capacity were available, for whatever reason, what other options would be open?

Most obviously we would take much stronger demand side measures to reduce the risk of actual disconnections and hence limit the economic and social damage. Bearing in mind that peak load is typically the main issue in the UK and that the capacity concern may centre on a relatively short period of winter and very few individual hours in any given year, there are a variety of strategies:

- more load management for large industrial consumers, with appropriate incentives and tariffs

- pricing and tariff strategies targeted to reduce peak loads

- initiation of smart metering techniques and tariffs which would extend the concepts of time of day pricing, and identifying more disconnectable load

- contingency planning within the National Grid, for example for voltage reductions[1], within current legal limits, to minimise actual forced disconnections

- broader contingency planning to mitigate the consequences of outages if they occur

4. Even assuming the worst case, where there are blackouts and rota disconnections, how do the estimated social costs compare to the estimated social costs of emissions?
Obviously a lot of assumptions go into this, such as the life of Kingsnorth as a baseload station, whether and at what point it would be fitted with carbon capture, how severe the shortages might be, and so on. But just to give a feel for orders of magnitude:
Social cost of emissions. A 2 GW baseload power station operating at 85% load factor might on average consume about 6 million tonnes of coal a year. This equates to about 15 million tonnes of CO2, or 300 million tonnes over a 20 year life operating at baseload without CCS. Valuing the cost of the latter at a comparatively modest (ie only a little above Stern Review) figure of £ 80 per tonne, this would imply an annual cost of £ 1.2 billion, £ 6 billion over 5 years (say), the presumed period when Kingsnorth fills a gap, and a lifetime cost of £ 24 billion.

Social cost of supply disruption. If we start with an England and Wales consumption of perhaps 275 TWh, this might give a typical peak period hourly consumption of about 1.8 times average hourly consumption, amounting to about 55 million kWh. Assume the absence of Kingsnorth meant that 3% of total load in England and Wales could not be met for 3 hours a day over a period of 30 days (ie a fairly prolonged period of severe disruption that is arguably worse than more likely, expected value, outcomes). Adopting a conventional valuation of lost load, £ 5 per kWh, that supposedly underpinned the old public sector standard of generation security, would put a value on that disruption of about £ 770 million in the year in question. Over 5 years that would be about £ 3.85 billion.

In other words the social costs
[3] of emissions are certainly of the same order and may well outweigh the social cost of supply interruption, even in each individual year of Kingsnorth operation without CCS.

Now of course all these numbers are approximate and simplified “back of an envelope” calculations, without the benefit of sophisticated power system modelling, and are only part of the overall economic calculus. But prima facie it would take a significant change in these parameters, or in the cost of carbon or lost load valuations, to demonstrate an “open and shut” case for building Kingsnorth simply because it enabled the power system to avoid limited supply interruptions. Purely in terms of these cost-benefit calculations, even when the “need” is taken as given and assuming no other mitigating action can be taken, the case looks decidedly marginal as between proceeding with a high emissions project or accepting that there will be supply problems over a limited period. It would be even harder to make in the absence of firm guarantees on carbon capture, or guarantees that Kingsnorth would downgrade to low merit status as soon as the period of shortage had been overtaken by new carbon-free capacity. At the very least the cost-benefit question needs to be asked, and the detailed parameters examined very critically.

It is worth adding that the case for subsequent coal-fired plant, expressed in these terms, will be more tenuous, since the hours of outages avoided should decline rapidly with each subsequent unit of capacity built.

[1] Under conditions of severe strain the National Grid will normally reduce voltage, within statutory limits, before it orders any disconnection. This on its own represents a significant safety margin, albeit at some cost to the quality of supply to consumers. But voltage reduction causes far less social and economic damage than actual forced disconnection (outages).[2] Ignoring for the moment the relatively small effect of discounting a set of emissions costs with a rising profile.[3] Of course these are largely discounted future costs, whereas the costs of supply interruptions are immediate.

Thursday, October 2, 2008


John Rhys
October 2008
Recent Government policy documents have tended to put a heavy weight on market mechanisms to deliver UK targets on CO2 emission reduction, and the electricity market is of central importance to these objectives. The author argues that it is essential to monitor the efficiency and efficacy of all energy markets, but especially the power sector, and that faulty structures and poor incentives will not deliver desirable or even acceptable outcomes. The systemic health of energy markets is as important as that of the financial sector.

The genesis of this article stems from discussions within the BIEE Climate Change Policy Group, and with Mike Parker and Gordon Mackerron of the University of Sussex. It is shortly to be published by the University of Sussex Energy Group in their Electronic Working Paper series.
Comments are welcome and may be posted using the link at the end of this article. All comments are moderated.

1. Defining the Question

There is an implicit, sometimes explicit, assumption in current Government policy[1] for the reduction of UK carbon emissions that markets will play a major or leading role in the delivery of emissions targets. While few would dispute the central importance of markets in energy policy in general, and their potential value in driving efficient solutions to environmental problems, this assumption deserves critical review. Perhaps the most obvious argument for a careful critical analysis is, to paraphrase the Stern Review[2], the observation that the link between emissions and climate change constitutes “perhaps the biggest market failure the world has ever seen”. If the issue starts with an identification of market failure, ie failure to provide the efficiencies and optimal outcomes that should flow from a functioning competitive market, then market solutions need to address existing market imperfections as well as Stern’s core externality.

This implies the greatest possible care in examining all policy instruments in relation to electricity markets, to deal with the risks of further market failure arising from possible flaws that are already present in those markets. Governments have played a major role in setting up both the market structures and the regulatory policies and mechanisms that currently define electricity markets. Given the growing importance of action on emissions, the necessity for Government oversight of markets and regulatory policies, to obtain assurance that they are meeting, and will continue to meet, fundamental policy objectives, is clear.

This systemic concern with energy issues is strongly analogous to the well established necessity for the oversight of financial markets and their regulation. If markets are likely to prove inadequate or vulnerable to systemic failure, for whatever reason, then attention needs to be given either to reform of the market, or to the alternative policy instruments of regulation and direct intervention (eg through research or investment).

The natural first step in response to the challenge, as correctly argued by Stern, has been to consider how best to internalise the costs of emissions, whether through properly designed taxation or through the development of emissions trading within an overall emissions limit – the EU ETS (Emissions Trading Scheme) currently being the prime manifestation of this approach. This reinforces the importance of examining the adequacy both of this trading scheme and of the existing market structures with which it operates within the UK. We need to consider whether energy markets, as currently organised and structured in the UK, are capable of or compatible with efficient delivery of large reduction targets over ambitious timescales, and with the degree of urgency that these targets imply. We should also identify what kind of market reforms, or additional regulatory and investment measures, might be needed to ensure that the policy can be delivered.

The particular importance of the power sector, on which this paper concentrates, arises both from its intrinsic importance as the largest single source of emission reductions, accentuated by potential future substitutions of new low carbon electrical energy for traditional use of fossil fuels in transport, and because the relevant policy measures for electricity are more directly within UK control than for some other sectors. Moreover, it will be argued, ambitious aggregate targets for 2050 require early progress to an essentially carbon-free power sector.

General requirements for electricity markets to meet, almost regardless of the policy context, in order to be deemed functional and to meet the objectives of securing efficient provision of supply, include:

- demonstrating the ability to generate the right levels of investment in maintenance and replacement of sufficient capacity to maintain a secure supply and, where required, new capacity and associated infrastructure. This means that markets have to provide price levels that deliver a return on the investment required, and do not contain significant barriers to entry.

- allowing short term organisation of generation to maximise operating efficiency through the scheduling of the most efficient plant. This means that wholesale prices have to be closely reflective of marginal cost.

- allocative efficiency, in providing prices for consumers that accurately reflect the marginal costs of supply, and hence give them the correct incentives for their own choices in fuel use and across a wide range of their own investment decisions, for example in housing and transport. Prices that are too low will encourage wasteful consumption; prices that are too high may give the wrong signals for fuel substitution.

- an industry structure that provides a genuinely competitive environment, so that competitive pressures can operate to encourage innovation and efficiency at all points in the chain of energy production, distribution and use.

- To be fully effective in the context of policies for reducing CO2 emissions, electricity markets have to meet all of these requirements in a way that is fully consistent with delivery of emissions policy targets or objectives, and with the associated degree of urgency. Moreover the markets have to find, or be given, some way of incorporating the externality associated costs of emissions.

Only if all these conditions are satisfied can markets be considered fully effective as an instrument of CO2 emissions policy.

In considering these questions we start with the 1990 genesis and subsequent historical development of UK electricity markets, and examine some of the necessary conditions for a low carbon future, in order to analyse the potential problems and draw conclusions on what might be the major problem areas.

2. The 1990 market structure

The circumstances surrounding the design and construction of the new markets to be put in place to accompany the privatisation of the power sector in 1990 have largely determined both the market structures that followed and the terms of debate.

2.1. Main objectives in designing the 1990 market.

Functioning and efficient markets do not always arise from the natural interplay of the forces of an unconstrained laissez-faire environment. In reality many depend on initial regulatory intervention and have the features of a club, carefully regulated with rules designed both to protect market participants and society at large from opportunistic, dishonest or destructive behaviour, and to ensure the most efficient outcomes. This is particularly so where the products or commodities being traded are complex and multi-faceted. Nowhere has this been more true than in the case of electricity, which has the additional complications of a network industry in which the process of production of the commodity, kWh, is also intricately related to the stability of the system and the maintenance of the quality of supply to consumers. All these factors are exemplified by the complex arrangements that were put in place in 1990 with the privatisation of UK electricity and the UK power sector.

Prior to 1990 there were few if any examples of “true” markets in electricity, the closest being some of the power pooling arrangements between utilities in North America. In their effect these replicated the merit order system of the old CEGB through a “generators’ pool” which minimised collective short term operating costs, but with an agreed sharing of efficiency gains rather than market prices and trading.

The development of UK electricity markets at privatisation in 1990, and the England and Wales Pool in particular, has to be set in the context of the primary objectives and concerns at that time for the design of a sustainable power generation market which would assure the continuing development of a power sector. It is worth reviewing what the concerns were in the 1990 market designs, how they were met, and what this might tell us for the future. The main objectives were:

- Maintenance of the benefits gained from the old CEGB merit order, a generally admired feature of the old nationalised industry operational arrangements, which sought to optimise short term operational efficiency by mimicry of a market structure and internal “competition” between stations to increase thermal efficiency and reduce fuel costs in order to be “in merit”. This resulted in least cost despatch of plant based on their position in the merit order.

- Technical stability of the power system, requiring some means of continuing or substituting the “command and control” features of the National Grid in order to ensure continuity of a reliable supply.

- Adequacy of incentives for investment in long-lived highly specific non-mobile assets, and a sector that would remain financially viable under private ownership within a framework that included both competitive markets and monopoly regulation. Asset specificity, and the risks of regulation around consumer prices make it particularly important for investors to find means of reassurance on the long term security of their revenues.

- Confidence that there would be actual investment under the new market rules, given that the old statutory “obligation to supply” requirement placed on the CEGB, would no longer exist for any of the new entities or would exist only in an attenuated form.

- Limiting the ability of large generators to dominate the market, particularly given the decision to create only two major fossil generators in England and Wales, and uncertainty over how this could be addressed through conventional competition policy

- A political imperative to create structures which allowed retail competition

All these factors are to some degree inter-related, and all had powerful influences on the actual development of the sector and its associated markets.

It is worth noting that this was a system that was essentially fossil fuel based; the market was therefore for all practical purposes designed around the technical and economic characteristics of fossil plant connected to the transmission grid. There was an awareness of the particular issues posed by plant of limited flexibility, and of particular issues that might be created by “decentralised” plant embedded within the distribution system and not subject to central despatch. On the whole these were at that time felt to be either intra-marginal, or too limited in scale to be significant.

It is also worth noting that a competitive structure militates strongly against use of the electricity sector as an instrument of policy, whether with regard to fuel poverty, support for domestic industry, or imposition of fuel choices. In particular it is not possible within a competitive market to impose a residual “obligation to supply” on any individual company within the structure. To do so would destroy their competitive position.

Of course the removal of public ownership as a potential instrument of policy was widely seen as one of its advantages. Ministers could no longer be held responsible for the problems of the UK coal industry for example. The implication for energy policy was that instruments of policy would henceforward need to be carefully constructed around the existing market structures. The first example of this was to be the treatment of renewables under the non-fossil fuel obligation (NOFFO) and its subsequent manifestations in other forms. The policy instrument of a simple directive (to the CEGB) was no longer available.

2.2. Merit order.

The traditional and longstanding CEGB approach to the despatch of generation plant had been through the establishment and maintenance of a “merit order” ranking of plant by ascending order of the short-run costs of operation; for all practical purposes this amounted to a ranking by fuel costs per kWh of electricity generated. As load changed up or down through the day, plant would be added or taken off according to its position in the merit order, which itself could change if the relative input costs or efficiencies of particular plant varied from day to day, or over longer periods, as a result of either technical or economic factors.

The new wholesale market structure, known as the Pool, closely reflected this approach to despatching plant. The half hour period taken as the basic unit of time for bidding into the market, detailed rules governing the content and nature of bids, and the development of pricing rules, were in many ways precise reflections of previous CEGB working protocols. As such they were a practical compromise between the realities of instantaneous load shifts, the longer periods over which plant can vary output and the complex “power engineering” task of maintaining stability in the system.

The pricing mechanism itself was designed to set wholesale prices on the basis of what would previously have been recognised as a system marginal cost, ie the cost of the least efficient plant in operation during that half hour. This translated under the new regime into a system marginal price calculated from the bids placed for half hourly periods through the day of marginal running costs, with the implicit assumption that, at least within a properly competitive market, the individual generating stations would have an incentive to bid in their “true” marginal running costs.

Generating plant would make a profit, or rather a contribution over and above fuel costs, when it was within merit and could operate for a lower cost than the system marginal price. This contribution would provide at least part of the necessary revenues to make a return on capital employed and meet other fixed costs.

Even in 1990 there were categories of generating plant that did not conform to what was essentially a model designed for a fossil fuel based system. The approach was imperfect even for much relatively inflexible fossil plant, as well as for nuclear plant which was not capable of easy output adjustment except at high cost, or for the particular characteristics of renewables. It is not a particularly useful mechanism for generating prices in circumstances where short run marginal cost is effectively zero or negative. However at privatisation it was felt these imperfections could safely be ignored as intra-marginal, and that they did not detract significantly from the theoretically sound characteristics of the new framework.

Prices were constructed on the basis of a system which for a very high proportion of the time would be based, for all practical purposes, on system marginal cost (SMC). This made a great deal of sense in a system of fossil plant where fuel accounted for perhaps 50% of the aggregate cost of generation even in an era of low oil (and gas and coal) prices. However the actual technical characteristics even of fossil plant do not conform perfectly to the rules of a theoretically pure on-off system of half hour costs and prices.

2.3. Adaptation to meet technical stability

The power system cannot be described solely in terms of kWh production by competing generation plant. Maintenance of system operation and stability requires that plant to be subject to centralised control, to observe particular constraints, and to provide particular services to the grid in terms of reactive power, frequency control, cold start facilities and a variety of other services. These services in turn are linked to characteristics and constraints imposed by the current state of the transmission system and the power flows within it. These had to be dealt with through a mixture of license and grid code requirements, together with financial incentives or recompense to generators. Many of these characteristics of a rule based system were inherited directly from the command and control system of the old CEGB, and will persist in some form in any future integrated system.

To a very large extent these were the rules of a club of fossil generators. The technical features of the market were designed in large measure by people who knew how the power grid operated and knew that they would be commercial players within the new arrangements.

To a significant degree these technical requirements also explain what is sometimes criticised as the Byzantine complexity of both the Pool and subsequent NETA/BETTA trading arrangements. However it is important to appreciate that the nature of these rules can have profound implications for the profitability of different types of plant, and hence for the economics of choice in respect of new investment. This, and the potential for intrinsic bias towards fossil plant, is a major issue and is explored more fully in the later analysis.

2.4. Reward for capacity

It was immediately clear, in terms of the theory of this SMC market paradigm, that a Pool or wholesale price based only on matching system marginal cost could not be guaranteed to provide overall adequate capacity to meet load at all times, and would fail in terms of generation security. This is easily demonstrated by taking the example of plant that is only “in merit” and called upon to run at times of peak. If it bids in its true running costs, then it is rewarded by a market price exactly equal to that cost, leaving a zero contribution to overheads, other fixed costs and capital costs. Hence there is no incentive to maintain the “peaking plant” necessary to ensure ability to meet peak loads and avoid supply interruptions.

The 1990 solution to this problem was a theoretically elegant device based on loss of load probability. If the system were to approach a situation of potential physical shortage, in which demand was likely to exceed available generation, then the pool price would become the value of lost load times the loss of load probability.

Generation security was further reinforced, initially, by establishing an obligation to supply for the public electricity suppliers (PES). This took the form of an obligation to meet demand by purchasing on the market at any price up to the value of lost load (VOLL). This supplanted the statutory obligation to “meet all reasonable demand” previously placed on the CEGB. The level of VOLL was set at a level that would in principle maintain the pre 1990 level of generation security. This theoretical continuity in the standard of generation security was achieved by setting a particular value of lost load that was considered to correspond closely to the value implicitly embodied in the CEGB’s earlier level of generation security and planning margin (of capacity surplus).

2.5. Competitive structure

An important innovation of the new regime, in terms of competitive structure, was that what had begun, conceptually, as a generators’ pool, originated from a US model of sharing the gains from trade among utilities, was now open to a much wider category of membership, including the new supply and distribution companies. This was an essential innovation to meet the political imperative of creating structures which allowed the development of retail competition, since it opened up the option for supply companies, or even large consumers, to buy directly from the Pool. This anticipated, in the longer run, a much more active participation of the demand side of the market. The new regime drew a clear distinction between the business activities of distribution and supply.

The initial 1990 configuration of the market in England and Wales was built around the break-up of the old monopoly CEGB into two large fossil fuel generators, and the nuclear plant which remained in public ownership until 1996. Surplus capacity in the market in 1990 translated into low prices and hence very low asset values for the generating companies within a competitive market.

However the assumption of new entry proved correct, driven initially by the strong ambitions of the new distribution and supply businesses created in 1990. Having seen themselves as being at the mercy of the old monopoly CEGB, these companies, newly privatised, were anxious to secure their own sources of generation. Encouraged by regulatory mechanisms which initially allowed a degree of pass through of generation costs, and taking advantage of the new opportunities afforded by CCGT, a variety of joint ventures in generation were established very quickly at privatisation in 1990.

Initially the impact of competition was constrained by contractual arrangements for three years, a primary purpose of which was to provide a transitional period in which UK coal would enjoy a degree of protection against imports and competing fuels.

3. Subsequent development of the market

3.1. Fuel choice and the effect on prices

UK privatisation and the new market structures more or less coincided both with the advent of new technology in the form of combined cycle gas turbine (CCGT), giving significantly higher efficiencies and lower generation costs, and with a sustained period of low and falling fossil fuel prices, especially for gas. Gas was subject to its own reforms, and the end of BG’s purchasing monopoly in the North Sea may also have contributed to falling gas prices. Among other things, these factors dramatically accelerated the decline of UK coal, and quite rapidly changed the sector fuel mix. There were two important consequences of this fortuitous combination of circumstances.

First there was a substantial decline in real prices to consumers, beyond what might be attributed to increased efficiency. This could be claimed in part at least as a benefit attributable to the virtues of competition and regulation within a private sector environment. A significant contributory factor was the sale of the generators at significantly below book values and the absence of public sector rate of return targets and tariffs based on much higher asset values, which were in any case not attainable in a competitive environment. However these factors were enhanced and sustained by falling fuel prices and the cost advantages of CCGT plant.

Lower consumer prices normally raise consumption, and indeed there was a significant expansion of electricity demand in the 1990s. Residential electricity consumption, having been virtually static for at least a decade, surged by just under 25% over the next 15 years, a major part of this almost certainly being attributable to a resurgence in the use of electricity for space and water heating, driven by a combination of rising real incomes and falling real prices in this period. This is of course a negative from the perspective of policies seeking to contain energy use and emissions.

Second the displacement of coal for gas resulted in a significant decline in CO2 emissions. This was an important environmental gain and has enabled governments to claim significant post 1990 reductions in emissions. This gain was however to a large extent fortuitous, since it was not driven by environmental objectives, and was essentially a by-product of the introduction of CCGT technology at a time of low gas prices, and the displacement of more CO2 intensive coal.
This enabled governments in some senses to have it both ways – with lower prices and a more environmentally friendly power sector, even though lower prices had driven a major increase in electricity consumption.

It is only recently that the structural reforms set in train in 1990 are facing what may be a more challenging environment in relation to emissions reduction, with declining supplies and rising prices for gas. There are now pressures for more coal plant, and consternation at the prospect of rising consumer prices.

3.2. Market Rules

When the electricity industry was privatised in 1990 and the original trading system, the Electricity Pool, was created, there were no reference models from which to take or adapt a design. The system was designed, implemented and owned by the electricity industry and it was generally conceded that it performed well against a number of important criteria, not least in maintaining the integrity of the system control function and avoiding supply disruptions through technical or market failures.

Nevertheless there was significant dissatisfaction with the Pool arrangements which went beyond what might have been resolved through minor tinkering with the rules. This reflected a number of factors:

- the undeniable truth that the sector had been privatised with just two competing players capable of setting prices at most times, limiting the impact of competitive pressures. Nevertheless by the time NETA was introduced in 2001, new entry had brought about a substantially more competitive framework.

- belief among some of the major players in the market that a less transparent system of bilateral trading and pricing would enable them to gain commercial advantage.

- instinctive but visceral dislike, particularly among free market purists, of the “administered” LOLP/VOLL approach to the capacity charge component, and of a system marginal cost (SMC) rather than a “what you bid is what you get” (or “wybiwyg”) approach to constructing the wholesale “balancing” price.

- some obvious omissions from the original Pool, such as the incorporation of demand side bidding

This led in 2001 to a more fundamental change to the nature of the Pool and the restructuring of the market under the NETA arrangements, later re-titled BETTA with the inclusion of Scotland within the trading arrangements.

Whatever the other merits and demerits of NETA compared to the Pool, the following features of the changes are potentially important to any analysis of compatibility with policy objectives for reducing CO2 emissions, as well as for the general health of the electricity market:

- the basic economics of merit order operation continued to be reflected at least in the energy/ SMC component of wholesale prices.

- the VOLL/LOLP basis for capacity was abolished and not replaced by any alternative form of capacity payment; there is in consequence now no obvious source of reward to capacity beyond what can be earned through bilateral trading and balancing payments

- the “command and control” features of the old CEGB system necessarily continued under the regime, which in consequence has continued to attract criticism, as did the Pool, for its Byzantine complexity

- within this complexity, NETA remained a system designed primarily for fossil plant and for flexible fossil plant in particular; it was widely criticised as penalising renewables and it certainly damaged the commercial return to British Energy’s nuclear plant. It is hard to judge whether these penalties on non-fossil plant were truly justified even from a narrow cost perspective of minimising short term fuel costs, since the majority of market participants would have had some vested interest in lobbying to favour fossil plant. This criticism raises important questions for a low carbon future.

It would later be claimed that NETA resulted in further falls in wholesale market prices, although it is hard to measure whether this was due to abolition of the capacity charge, to changes already in train that reduced concentration and market power in the industry, or to any efficiency or increased competitiveness associated with NETA per se.

3.3. Competitive structure

Supply competition was extended quite rapidly from covering only the largest consumers to covering the totality of consumers by 1998. Consonant with this the residual obligation to supply, which had rested with the “public electricity suppliers” at the time of privatisation, disappeared and was not replaced by any new mechanism.

Extension of retail competition was allowed to develop on the basis of load profiling rather than on the basis of more complex metering, introduction of which would have slowed achievement of the politically important goal of declaring the market to be fully competitive. Load profiling can be considered as another arbitrary administrative device within the market structure. It averages all load of a particular class, in this case domestic, ignores differences in actual consumer load profiles by time of day or year, and hence reduces very substantially the possibilities for full allocative efficiency in this part of the electricity market.

The initial 1990 structure had emphasised the “unbundling” of the old publicly owned industry into a structure which separated the functions of generation, transmission, distribution (regional or local) and supply. Generation and supply were considered competitive businesses, and transmission (national grid) and local distribution were subject to price regulation.

Despite some initial unease at the prospect, subsequent developments have nevertheless been strongly in the direction of vertical integration, with the re-integration of generation and supply being the most significant in terms of competitive structure. A substantial degree of vertical integration has been allowed to develop within the industry and has come to be perceived as a major strategic advantage. This is also a factor tending to raise barriers to entry to the generation business.

It is an open question whether consumers, particularly smaller consumers, have benefited to a major degree from retail competition. A useful presentation of this position is given by Joskow.[3] Given that wholesale prices and “regulated monopoly” distribution charges should account for almost the totality of the final retail price, with little “value added” in supply, one would expect, in a competitive market, very little difference in suppliers’ retail prices. The frequent lack of transparency in retail tariffs, and the exploitation of customer inertia among those who do not switch supplier regularly, suggests that the gains, for the consumer, from retail competition, may have been overstated. The strategic importance attaching to vertical integration suggests that suppliers collectively may have been the main beneficiaries.

4. Future factors

4.1. Accommodation of carbon markets

Now and for the foreseeable future, electricity generation in the UK is likely to be covered by emissions trading arrangements. These are incorporated into Pool/NETA type markets with comparative ease, since bids will simply include the value of CO2 permits in the same way that they include fossil fuel costs.

This serves to emphasise, however, that the achievement of overall policy objectives depends on the feasibility and compatibility of the targets and associated mechanisms.

4.2. The necessity for generating plant that is low or zero carbon

It is clear that if the UK is to meet its CO2 targets, then a power generation sector that is essentially carbon free is a necessity. This has been argued strongly in earlier papers by the BIEE Climate Change Policy Group[4]. In essence this assertion derives arithmetically from the combination of the objective of a 60/80 % reduction in CO2, the current electricity contribution of some 35%, and the prospect of relatively slower progress in the other sectors.

Carbon-free electricity implies very substantial growth in the collective contribution of the following categories, and some or all of these will have to expand very dramatically:

- Nuclear
- Carbon capture and storage (CCS)
- Centralised renewables
- Decentralised renewables

All these non-fossil sources are likely to have very different technical and economic characteristics from fossil plant. A common characteristic is that they may place a premium on means of electricity storage or on matching with more flexible types of electricity demand.
Nuclear plant is typically regarded as the most inflexible, albeit this has not prevented the French from running a very successful power sector with a very high contribution form nuclear power. The reasons are a combination of technical and economic. Nuclear power output can typically be varied but for some plant this can have implications for more frequent routine maintenance schedules, reflecting safety and licensing requirements, and with large additional maintenance costs and reduced annual output. In economic terms therefore, nuclear plant is often described as “must run”, and might even bid a negative price within a market system that permitted negative bids. These characteristics will not be the same for all plant, and there will be incentives to design future plant to be more flexible, with lower cost penalties for flexible operation.

The characteristics of future CCS plant are unknown. In principle one might expect it to be similar to equivalent fossil plant, but at this stage there is no information on which to make predictions, for example, of whether or not the proportion of carbon captured in combustion is likely to vary with output level. If it did then load following would have a strong effect on the economics of CCS plant, and on the way that it could be bid into a market of the Pool or NETA type.

Renewables covers a range of technologies, with very different characteristics for wind, tidal and other sources. Typically they may be flexible in the sense that output can be turned down when the plant is available, but inflexible in the sense that they cannot deliver when not available (eg wind turbines in the absence of wind). Decentralised renewables are not normally regarded as part of the centralised control system, but they will need to be accommodated within the broader market framework of tariffs etc.

4.3. A more electric economy

The significance of electricity in achieving a low carbon economy is not confined to finding low carbon or carbon-free alternatives for the production and consumption of electricity in its current uses, since carbon-free electricity, whether generated in centralised or decentralised systems, also provides a number of the known technically feasible alternatives to fossil fuel use in both transport and the heating of buildings, the two other largest categories of energy use and hence sources of CO2 emissions in the UK.

In transport this includes both the possibility of electricity in transport, including battery operated vehicles, and the use of hydrogen, carbon-free production of which currently depends on electrolytic methods and hence electricity.

A significant proportion of total electricity requirements to meet the needs of battery charging, or of a hydrogen economy, will have one additional practical advantage, that it provides a vector for the storing of the energy generated as electricity. This could, assuming appropriate use of time of day pricing signals, remove much of the power sector’s peak load problem, and as a corollary reduce the disadvantages of the intermittent availability of renewables.

In heating of buildings, the main current uses of electricity are through conventional direct acting heaters and storage heating, but the novel use of electricity dependent technologies such as ground source heat pumps is also potentially important. As with the transport sector a significant penetration of electricity in the heating market would have a major effect.

The buildings sector may also be associated in part with a decentralised component to electricity generation, for example through individual household ownership of small wind turbines. To be effective, and in economic terms, efficient, this would require purchase and sale tariffs for consumers that were fully cost reflective at the level of the individual household, and hence an abandonment of the load profiling approach in favour of more sophisticated metering and more complex time of day tariffs.

5. Analysis

In the context of developing a low carbon future, a hugely important requirement of the electricity market, not present or not emphasised at the time of the 1990 privatisation, is its compatibility with investment in and successful operation of the low carbon technologies that will form the basis of power generation and electricity use in that future, together with the ability to assure a very low carbon contribution from the power sector. We analyse the prospective development of power markets, wholesale and retail, from this perspective.

5.1. Operational security and efficiency

An essential feature of the market is that it should continue to deliver efficient short term operation and cost minimisation, and system stability. The market will have to change to accommodate the operational realities of the low carbon plant that will in a low carbon world constitute by far the larger part of generation, and it seems inevitable that plant with the very different characteristics of relatively inflexible or intermittent plant, with fossil plant no longer at the margin, combined possibly with a much greater significance for demand side bidding and management (eg for battery charging or hydrogen production) will require a very different approach to the development of bidding systems and a very different approach to the optimisation and scheduling of load. If, as seems probable, the economic advantages of a national grid remain overwhelming, then the centralised optimisation, currently effected through a half-hourly based bidding system, will need to be done either through a wholly different type of market, or will have to be returned to centralised control.

It is quite possible that the basic building block of half hour bidding periods, for example, will not be suitable to guarantee the optimisation of more complex systems. Comparison can be made with complex hydro systems involving water storage for example. If the existing system were retained it would inevitably distort the market towards particular types of plant. One would normally expect to see a piecemeal evolution to a completely new optimal system, but it must be an open question as to whether the structure can actually evolve in that way, depending as it does on agreement between existing market participants. Failure to resolve this issue could be construed as a potential barrier to entry of non-fossil plant.

5.2. Correct signals for new investment

A vital attribute of a properly functioning market is that it should deliver prices that provide the correct signals to producers and suppliers for future investment. To be efficient in economic terms prices should reflect the appropriate measure of costs at all points in the supply chain, and not be so high as to promote excessive investment or so low as to promote excessive consumption and inadequate investment. Prospective investors need a market that delivers prices capable of rewarding their investment, including the recovery of operating costs and an adequate return on capital.

This places a number of requirements on the market and institutional structure, including the mechanism for internalising the “cost” of emissions, and the stability and credibility of the regulatory and policy structures within which the market operates.

One outstanding issue in this context, however, is at the core of the current market structure. It arises from the abolition of the Pool payment for capacity through the administered market LOLP/VOLL mechanism intended to reflect the value of lost load. This was previously seen as an essential feature of the Pool, necessary to reward “peaking plant”, plant required only at peak periods. Ultimately this may be an empirical matter, but at least from a theoretical perspective it appears far from certain, if not a leap of faith, that NETA based prices will deliver adequate rewards for capacity, and hence that the market is capable of delivering new capacity.

To quote Dieter Helm[5]: “The NETA-type market was deliberately designed to drive down prices. …..But at the heart of NETA lies a flaw, a flaw that did not much matter as long as there was excess supply. NETA did away with the capacity element of the market in the Pool … and introduced greater volatility. Under NETA, investment would be stimulated because as demand and supply came into closer contact, the price would rise to the level necessary to trigger investment. But in electricity markets, because supply has to equal demand at every point, there needs to be a capacity margin. But that spare capacity is not independently rewarded under NETA – it only gets paid for if prices occasionally reward it. Investors, in effect, take a bet on occasionally winning the lottery.” Similar points are made by Graham Shuttleworth in a review[6] of the NETA framework.

Helm suggests that this might work in theory, although even this is a moot point, but is unlikely to work in practice. “As soon as the price starts to spike, politicians are inevitably drawn into the frame. They were in California, and they have been here. Even the slightest suspicion that the prices may not be allowed to spike deters future investment. Hence investment is sub-optimal.” This may not have mattered in recent years, when there was a margin of surplus capacity, but eventually new investment becomes necessary. So far, Helm notes, NETA has not supported any significant investment.

This of course would be a potential defect in the market even in the absence of the need to accommodate a low emissions policy for the sector. However the combination of the absence of a clear reward to capacity, combined with the regulatory uncertainty identified by Helm, and any residual or additional uncertainties over the consistency of government policy for a low carbon future, adds up to a significant deterrent to new low carbon capacity and potentially a much slower rate of installation.

5.3. The Impact of the EU Emissions Trading Scheme

The EU trading scheme is central to the efficacy of electricity markets in relation to emissions and carbon policy since it is the only route through which the internalisation of the cost of CO2 emissions takes place. The adequacy of the EU arrangements therefore impact hugely on confidence in the ability of UK electricity markets to deliver their contribution to UK emission reduction targets.

In principle, a strictly monitored and enforced limit and associated trading system, consistent with the policy objective, should be capable of delivering a market solution. In practice the first phase of the EU ETS, even if successful when measured against the limited objectives of a pilot scheme, had a number of serious inadequacies when viewed in a wider context. Created from scratch to operate across many different political jurisdictions, it suffered many of the teething problems of a new market. Its effectiveness was also severely limited by the lobbying of national governments acting in the special interests of their own industries.

Its most serious longer term deficiencies, from the perspective of a policy for UK emission reductions, are threefold. First it is questionable whether it can bear the weight that the UK Goverment puts on it as a main instrument of policy. An important concern here is the political plausibility of the expectation that the carbon price will be allowed to reach the kinds of levels needed to induce strongly pro-low-carbon investment. Second it is questionable whether it is sensible to rely on, as a flagship instrument, a policy measure over which the UK Government has only limited influence. In effect this puts a national policy in the hands of an EU bargaining process. Third, grandfathering of emission rights is economically inefficient and has generated large windfalls.

At the very least this poses some fundamental questions for the integrity of future schemes. In addition a number of more technical questions need to be asked of the second phase and future arrangements of the EU ETS, and of its consistency with any UK aspirations for UK CO2 reductions.

- Is it compatible in terms of both its coverage and the actual emission limits set? In what sense can EU targets be said to correspond to UK targets? And how do they match for the electricity sector in particular?

- Are the timescales compatible? This question is particularly apposite viewed in the context of investment against a 2050 commitment, given the much shorter timescales against which EU agreements are currently framed and uncertainty over the nature and timing of future changes.

- Some commentators have suggested a danger that the scheme injects an artificial volatility into the price of energy. This would be a further inhibition to investment, particularly in the low or zero carbon sources of generation that are required.

5.4. Delivery of price signals for allocative efficiency

To achieve allocative efficiency, energy markets need to produce price signals that reflect correctly the costs incurred in delivering that supply of energy to them. This gives producers and consumers incentives to make rational decisions about their own expenditures, and rational choices between the fuels available to them, while paying an amount that covers the market and production costs associated with supply. Prices that are too low encourage wasteful and frivolous consumption, ie consumption that is valued by the user at less than its actual cost to others or to society as a whole to deliver. Prices that are too high unnecessarily discourage consumption or may cause consumers to substitute in favour of products that actually have higher costs. Prices that do not consistently reflect costs across different fuels, especially in the treatment of emissions costs, will diminish the overall efficiency of the energy economy, and may result in higher emissions than would otherwise have occurred. The importance of allocative efficiency in relation to consumers will necessarily tend to be higher in a period of generally higher fuel prices.
The significance of allocative efficiency in the electricity sector is enhanced by the fact that there can be dramatic short term marginal cost variations in generation. These are likely to be accentuated very dramatically as electricity generation moves from a mainly fossil based system to a mainly carbon-free system, from zero costs when nuclear or renewables are at the margin to very high values, perhaps a multiple of current retail prices, when fossil plant, costs enhanced by the cost of emissions, is at the margin.

The importance of allocative efficiency will also grow in a period when the achievement of emissions reductions depends to a significant degree on switching fuels and on technology shifts which embody or translate into major consumer choices. To take the household sector as an important example, most low emissions scenarios depend on households engaging with a variety of technical alternatives, including condensing boilers, high levels of insulation, local or decentralised renewables, electric-powered underground heat pumps, as well as simple traditional choices such as electricity or gas for cooking.

In a context of reducing emissions in order to limit the potential damage of climate change, this means that costs or price for emissions, and indeed cost structures as a whole, should be factored into the price of a fuel use on a consistent basis that reflects actual production and emissions costs. As far as residential and domestic consumers this patently does not happen, and cannot happen, since the effect of load profiling simply averages the fuel costs charged to domestic consumers according to a load profile assumed for domestic consumers as a class. In consequence it ignores the very substantial variations in marginal generation costs that occur according to time of day and time of year, which will be accentuated very dramatically as electricity generation moves from a mainly fossil based system to a mainly carbon-free system.
This limitation to allocative efficiency could be profoundly important in settling the economics of alternative domestic heating systems, since heating load is intrinsically susceptible to coincidence with peak usage, and price signals will only lead to consumers making the best “low emission” choices if they face carefully constructed time differentiated tariffs, which in turn will require more complex but technically straightforward time of day metering. This analysis will apply to some degree even in much smaller but still important choices such as use of gas or electricity for cooking.

5.5. Unfair competition

General concern over the competitiveness of the market arose in the 1990s as a result of the highly concentrated structure of generation. This concern, at least in respect of wholesale markets, was to some extent dissipated by changes in ownership of plant, divestment, and much reduced indices of industry concentration. Even so there are residual questions over the vertically integrated structures that have developed.

A more subtle source of unfair competition has been identified, inter alia by the late Dennis Anderson[7]. In a predominantly fossil fuel based system it is fossil prices, whether or including any carbon price element, that will continue to set market prices for many years to come. This means that the variance in the net present value of investment in fossil plant is comparatively small, since changes in fuel or carbon prices simply get passed through into the wholesale price. Fossil plant investment is therefore far less exposed to the risk around fuel and carbon prices than low or zero carbon investment, even though the corresponding risk, viewed either as a social cost or in terms of consumer prices, may be much higher. This creates a degree of unfair competition, tilting the playing field against low carbon investment, which is intrinsic to a gas and coal dominated generation market. In principle at least this is a real barrier to entry.

5.6. Parties capable of contracting

Reliance on markets assumes that commercial incentives will suffice to induce investment. One of the biggest issues for potential investors in power generation is the long life and highly specific and non-mobile nature of their asset. If the wholesale market does not support “merchant” investment, essentially speculative against future prices over several decades, then such investment will depend on long term contracts. However the current structure of the sector does not provide reliable counter parties able to enter into such contracts, because this is not consistent with the competitive framework.

6. Conclusions

1. General case for review. We need to recognise that the electricity market is, and will remain a complex administrative structure, whose main features have been determined by a mixture of factors, including the corporate interests of major players. The extent to which its operations conform to the economist’s theoretical concept of a perfect market that induces efficient and optimal behaviour from participants is limited by a large number of factors. These include not only traditional competition policy concerns over market concentration but also the technical constructs that underlie wholesale pricing and the arbitrary administrative conveniences that underpin retail sales. It is therefore legitimate to question whether the market as currently constructed is actually operating in the public interest, and particularly whether it will continue to remain “fit for purpose” in a period when emissions and climate change policy is growing rapidly in importance on the policy agenda.

2. Adequacy of wholesale market and operational arrangements in new low carbon environment. A major function of an effective market is to provide a secure basis for investment with a level playing field on which alternative types of investment obtain equal treatment without undue discrimination. It is clear that the existing wholesale market mechanism, BETTA/ NETA as the successor to the Pool, has as its primary drivers the need for load following and for optimising the variable costs of fossil fuel plant, and that its design reflects the technical characteristics of fossil plant. It is not therefore surprising that the mechanism should have been accused of discrimination against non-fossil plant. More importantly it is clear that a very different mechanism is likely to be needed to cope with a power sector market from which fossil generation has been, for all practical purposes, eliminated.

3. Adequacy of capacity incentives. There remain very considerable doubts over the adequacy of the incentives to create new capacity, even if the particular concerns to get new low carbon investment are put aside. These doubts relate to the adequacy of the market mechanism to reward capacity, and would exist quite independently of CO2 emissions policy issues.

4. EU ETS. To date the EU ETS is the “only show in town” that purports to provide a mechanism for internalising the cost of emissions in the electricity sector. However there are a number of reasons to doubt its adequacy as a primary instrument for meeting UK policy targets. At the very least its operation, its impact on electricity markets, and its credibility in the context of low carbon investment, need to be subject to careful review.

5. Bias to fossil fuel and barrier to low carbon entry. While generation remains dominated by fossil fuel, it is fossil costs, including the costs of their associated CO2 emissions, that dominate the construction of prices. The market therefore limits the risk of fossil investment, creating a significant bias towards fossil plant. The wider variances associated with the net present value of low carbon plant partly offset the potential economic advantage. In effect the market inertia of a fossil dominated system constitutes a real barrier to entry.

6. Obligation to supply. There is no entity currently charged with the obligation to supply. Nor is there any obvious candidate on whom such an obligation could be put without major effects on the nature of the market. If therefore it becomes apparent that reliance on the market is failing to deliver adequate levels of low carbon capacity, then the only fall-back is government intervention in some form.

7. Smart metering and allocative efficiency. The absence of adequate cost reflective retail pricing militates against the efficient development of a low carbon future in the household sector. The use of load profiles, introduced, paradoxically, because waiting for more sophisticated systems might have delayed the introduction of retail competition, provides average cost messages that are not appropriate to the circumstances of individual consumers, and do not provide the right signals for the choices that will need to be made. This will clearly need to be changed.

8. Impact of a hydrogen or battery-electric economy, and of decentralised power generation options. In the longer term, the effect of major technical shifts in other major sectors of energy use is another factor that potentially transforms electricity markets. The effects are inherently hard to predict, but the injection of additional electricity demand associated with a hydrogen or electric vehicle-battery economy would transform the economic character of the market, essentially by creating a form of electricity storage through these alternative vectors. This would improve the economics of both nuclear and renewable sources. It would also increase the importance of price signals for productive and allocative efficiency.

9. The Way Forward. Some though not all of the market weaknesses identified in this paper are clearly susceptible to reform and innovation. Operational bias against non-fossil plant may be a matter of simple rule changes; incentives for capacity can be created with or without CO2 targets; smart metering requires major investment and changes to the retail market, but is clearly feasible. However these, as well as the potentially more difficult issues associated with the EU ETS, are non-trivial reforms and will be time-consuming to pursue. Reliance on markets as the sole or primary instrument of change therefore risks serious delay as market structures are “adjusted”, without any absolute confidence that all the market barriers to low carbon entry can be overcome. The urgency of progressing low carbon electricity suggests that anticipated investment in electricity generation needs to be closely monitored, starting immediately, with a view to additional measures if it becomes clear that market signals are not delivering solutions on the scale that is required.

[1] Meeting the Energy Challenge, A White Paper on Energy, Department of Trade and Industry, May 2007
[2] Sir Nicholas Stern ,The Stern Review on the Economics of Climate Change, HM Treasury, October 2006,
[3] Paul L Joskow, “Why do we need electricity retailers? Or, can you get it cheaper wholesale?”, Center for Energy and Environmental Policy Research, Massachusetts Institute of Technology, revised discussion draft, 13 January 2000.
[4] John Rhys Mike Parker and Gordon Mackerron, Shaping Carbon Budgets, , January 2008,and related papers on the site Bringing Urgency Into UK Climate Change Policy. This is a BIEE linked site.
[5] Dieter Helm, Hot air, gas prices and energy policy, December 2005.
[6] Graham Shuttleworth, Pay as Bid Balancing Market Runs into Trouble in the UK, NERA Energy Regulation Insights, April 2004.
[7] Dennis Anderson, Policies for a Low Carbon UK Energy System, August 2007, Findings of a Study for the IPPR

Thursday, June 26, 2008



John Rhys.  April 2008.

The arguments in this piece have been updated in the more recent April 2016 posting

The ideas in this piece were subsequently developed for an OIES Working Paper and an OIES Energy Comment on UK Treasury Guidance, later discussed with DECC and HM Treasury officials.

In December 2007 DEFRA published recommendations[1] on the social cost (SCC) and shadow price (SPC) of carbon dioxide (CO2) emissions to inform policy and investment appraisals across government. The importance of the subject, in a policy setting, is that it provides at least a starting point, and some necessary if not sufficient conditions, for “joined up” government that embraces climate change policy. The purpose of the exercise, whether in investment or policy appraisal, is to enable comparisons to be made of streams of CO2 emissions in future years as between project or policy alternatives, and to estimate their net benefits or costs.

The subject of this note is the time profile of carbon. Quite apart from its role in the technical requirements of net present value calculations for appraisal purposes, the presentation of that profile, and in particular the answer to the question of whether current emissions do more or less damage than future emissions, conveys an important message for the urgency of policy on climate change.

It is generally assumed, correctly, that CO2 emissions are essentially cumulative or have such a long life in the atmosphere that they can be regarded as very nearly so for most practical purposes. Logically, this implies a time profile for social costs, measured in terms of their current net present value (ie as at 2008), in which significantly higher values should attach to reductions in current emissions than to reductions in emissions in (say) ten years time. This simply reflects the fact that this year’s emissions are still contributing an increment to CO2 concentration in ten years time, but have had an additional ten years of impact. The cumulative effect of CO2, without re-absorption, implies higher social costs should attach to current emissions.

A first reading of the DEFRA paper might, however, suggest that the opposite is true. The paper proposes a time profile for the social cost of carbon which rises over time, by 2.0% per annum, and seeks to explain this as follows:

• As time goes on, the damage comes closer, and is discounted less heavily; so its present value rises, increasing the SCC.

• The concentration of carbon in the atmosphere is rising towards its long-run stabilisation level, and expected climate-change damages accelerate with higher concentrations. An extra unit of carbon will do more damage at the margin the later it is emitted because, even with a plausible concentration goal, it will be in the atmosphere while concentrations are higher and higher concentrations mean larger climate-change impacts at the margin (as damage is a function of the cumulated stock); this too increases the SCC. Additionally, as incomes grow, so the monetary value of damage is likely to grow, owing to an associated higher willingness to pay to avoid warming damage.

The first explanation is clear. DEFRA is presenting a time profile for the SCC in which damage of emissions in each year is presented as a net present value (NPV) of all future damages discounted to the year of the emission, so that the comparison of damage, as between emissions now and in the future, cannot be deduced directly from the profile. Given that DEFRA appears to use a 3.5% per annum discount rate in this context, one would expect this factor alone to result in a 3.5% per annum rate of increase in the SCC, and so this more than explains the profile growth, taken on a year of emission basis, of 2.0 % per annum. If the DEFRA series were discounted back at 3.5% per annum to a common base, it would show, as we should expect, more damage from earlier than from later CO2 emissions.

However the second explanation makes an assertion about the physical nature of CO2 concentration which is at odds with the hypothesis outlined above, that the essential link for climate change is to cumulative concentrations. It would imply that emissions now cause less damage than those in the future. One example of a perverse conclusion for policy, that would arise from acceptance of this argument, is the following:

Question. Suppose we have a large store containing thousands of tonnes of CO2, held under pressure in large corroding metal vessels. Technical experts have advised me that there is no means of permanently sealing the vessels, but that I can at some expense treat the seals of the vessels in a way that will prolong their expected life from 5 years to 20 years. What should I do, given an objective of minimising adverse climate impact?Answer. According to an analysis of social and environmental costs which tells us that later emissions are more damaging, the answer is obvious. We should be prepared to spend money not on reinforcing the vessels, but on breaking them open immediately, since the social cost will be significantly higher in 5 years time and even more so in 20 years time.

This is clearly absurd if we regard CO2 emissions as purely cumulative.

Fortunately the second DEFRA explanation above is incorrect, and is contradicted by DEFRA’s own research. The question of how to compare the options of emissions now and emissions in the future, on a comparable basis, clearly matters, not least for the urgency that should be attached to early action. It is worth checking first, that current understanding of the climate science does indeed support the notion that CO2 emissions are essentially cumulative; and second, whether the modelling of economic costs confirms, as logically it should, the hypothesis of higher costs associated with current emissions.

Interpreting the Science on Re-absorption

The re-absorption rate for carbon in the atmosphere is a crucial measure in determining whether emissions are cumulative in their effect, a little less than wholly cumulative, or “more than cumulative” with positive feedback. To be precise, it is not the average rate of re-absorption of the stock of CO2 concentrated in the atmosphere that is most relevant in this context, but the incremental re-absorption rate for the additional units of CO2 emission. This requires interpretation of the available science.

Climate science is too complex, and many of its individual parameters too uncertain, to allow an unqualified statement of any simple mathematical relationship between CO2 re-absorption rates and concentration levels. Actual re-absorption depends on a wide range of factors, and will change over time with the state of other climate and climate system variables. For example one possible feature of terrestrial and oceanic carbon sinks might be that they become saturated, but their cumulative absorption limit is likely to depend on a variety of climatic and other factors, and will not necessarily be driven directly by CO2 concentration levels.

Pursuit of a fully estimated mathematical function, remaining broadly unchanged over time, and differentiable with respect to concentration levels, may therefore be neither realistic nor meaningful. However it is possible to make sensible inferences, in context, from a number of sources, including Stern[2], other studies referenced in Stern, and IPCC publications, about current best estimates of re-absorption.

Stern, in Chapter 8 of his review, describes a current stock in the atmosphere of around 3000 GtCO2, and annual man made emissions of 35 GtCO2, of which about half, or about 17 GtCO2 per annum are currently removed. This indicates an annual re-absorption rate, expressed as an average in relation to the stock, of about 0.56 % per annum[3]. This is presented as a guide to the future, but only with the proviso that there are no feedbacks into the carbon cycle, such as those that might be associated with a maximum level of cumulative re-absorption. Other sources, such as the IPCC[4], indicate similar estimates of the “historic” rate of re-absorption.

Stern, drawing on the climate literature, warns very clearly that carbon feedback can have a dramatic effect, quoting a recent study[5] showing that, if feedbacks between the climate and carbon cycle are included in a climate model, the resulting weakening of natural carbon absorption means that the cumulative emissions at stabilisation are dramatically reduced. The “with feedback” calculation allows emissions of 1600 GtCO2, of which 1050 GtCO2 are removed in the course of a century; this equates to about 10.5 GtCO2 or 0.3 % per annum.

The inclusion of the effect of feedbacks to the carbon cycle should be expected to have an even more pronounced effect on the measurement of the incremental impact. Climate model projections incorporating carbon cycle feedbacks imply that net absorption is falling in absolute terms. This makes it much harder to assert that an incremental tonne of carbon this year results in less than an additional tonne in five years time. Indeed it suggests that the process may well be purely cumulative, possibly as carbon sinks approach capacity limits, or that there may be a positive feedback.

Overall this reading of current scientific understanding on the subject suggests that it is hard, even on the most optimistic reading of the data, to support re-absorption rate estimates much higher than 0.5 % per annum, and more likely figures are much lower at around 0.2 %. The decline in re-absorption associated with feedback into the carbon cycle suggests that, incrementally, re-absorption rates might even be zero or negative. Re-absorption is therefore likely to provide no more than a minor adjustment to the assumption of a cumulative effect. It is easy to show mathematically[6] that the rate of growth in SCC cannot exceed the rate of “decay” of CO2 in the atmosphere.

Results from modelling of economic impacts

Economic models of the impact of climate change may be subject to qualification, but the work commissioned by DEFRA[7] , and which provides the basis for their cost estimates, serves to provide further confirmation. This has the time profile of SCC discounted to a common base year 2000, which shows a pattern consistent with our hypothesis, of a falling time profile of around 1% per annum. This confirms that any re-absorption effects, as currently understood, do not have a significant effect on the time profile. Describing the SCC in the year of emission shows annual increases of about 2% per annum, the difference being entirely attributable to the 3.5% per annum discount factor[8].

It is interesting that the same result does not hold for all greenhouse gases. Methane for example has a much shorter life and is not therefore cumulative. Later emissions may indeed be more damaging in the case of methane, and this is confirmed by model results.


The presentation of a time profile for the social cost of carbon deserves care, and the DEFRA explanation of its own time profile, in terms which contradict the cumulative CO2 hypothesis, indicates the scope for confusion. The true position can be stated unequivocally: emissions now are more damaging than those in ten years time. The apparent paradox is that the social cost of emissions is falling at the same time as the perceived damages are rising; the paradox is however apparent, but not real.

This should reinforce the hand of all who argue for a post-Stern presumption in favour of early action. It remains true (as DEFRA suggest) that climate problems are likely to grow in severity over time, together with public perception of their economic and environmental impact. This may well be reflected in continuing willingness to increase the attention we pay to CO2, and to attach higher social costs to it. However that re-assessment would necessarily include, implicitly at least, a retrospective increase in the cost of emissions in past years and hence a higher “regret” for the opportunities foregone.

A higher value to early emission reduction, at least for CO2, and whatever values we might attach to climate impacts in the future, enhances the case for acting with urgency to reduce the economic impact of climate change. This is further emphasised by the fact that many of the possible short-term opportunities for reducing emissions do not depend on changes in capital stock, and represent comparatively low cost abatement opportunities, or “low hanging” fruit.


[1] Economics Group, DEFRA. The Social Cost of Carbon and the Shadow Price of Carbon. What They Are And How To Use Them In Economic Appraisal In The UK. December 2007.

[2] Nicholas Stern. The Economics of Climate Change. The Stern Review. Cabinet Office - HM Treasury 2007

[3] The calculation is performed with respect to the total stock of carbon.

[4]; FAQ 10.3, for example; and numerous other IPCC sources

[5] Jones, C.D., P.M. Cox and C. Huntingford (2006): 'Impact of climate-carbon feedbacks on
emissions scenarios to achieve stabilisation', in Avoiding Dangerous Climate Change,
Schellnhuber et al. (eds.), Cambridge: Cambridge University Press.

[6] A brief mathematical demonstration of a point that may be fairly obvious to the reader intuitively:

Let Dn be the economic damage over all future years attributed to an incremental unit that exists in the atmosphere in year n only, discounted back to year 0. Let Zn be total impact over all years, ie an infinite series, of a one-off emission in year n of volume K, discounted back to year 0. [NB In this formulation impacts are always discounted back to the base year.]

Let the reduction factor V, assumed to be constant, be the proportion of incremental CO2 not re-absorbed after a year, so that the proportion remaining after n years is Vn . [NB V =1 if no re-absorption.]

Now let us compare Z0 and Z1 , the total effects of the same amount of emission K but a year apart.

Z0 = K x D0 + V x K x D1 + V2 x K x D2 + … + Vn x K x Dn + …

Z1 = K x D1 + V x K x D2 …. + Vn-1 x K x Dn + ……

So Z0 = K x D0 + V x [K x D1 + V x K x D2 …. + Vn-1 x K x Dn + ..... ]

= [K x D0 ] + [V x Z1]

Hence unless D0 is zero or negative, impact of emission in year 0 is greater than the impact of emission in year 1 times the reduction factor; ie if reduction is 1% pa, then SCC cannot increase by more than 1% pa. Setting V=1 equates to no re-absorption, and the simple form of the cumulative hypothesis on SCC, ie a decreasing profile.

[7] Appendix 3. Research on behalf of DEFRA carried out by AEA Technology et al (2005). Authors Watkiss et al. Available at

[8] These orders of magnitude suggest that the shape of the time profile for the social cost of carbon may have as much influence over the outcome of an appraisal as the more familiar debate over the appropriate choice of discount rate.