Wednesday, October 8, 2008

A More Stringent UK Emission Reduction Target

9 October 2008

A response to the Climate Change Committee interim advice to the government this week that the UK should adopt a more ambitious target of an 80% reduction in emissions. It welcomes the advice, and suggests the ultimate need for cumulative targets, reinforces the need to decarbonise the power sector and questions undue or exclusive reliance on markets to achieve emissions objectives.

We welcome this advice wholeheartedly and in particular endorse the recommendations of a more ambitious target, that the emission reduction targets should in principle cover aviation and shipping, and that they should in principle be expressed in terms that cover other greenhouse gases. We argued strongly for these measures in our response of December 2006 to the Stern review, and in subsequent papers, as well as in the individual evidence to parliamentary committees from members of the group.

There are a number of implications that we believe follow from the Committee's advice.

The logic of the climate science suggests that, ultimately, targets need to be formulated in terms of targets for cumulative emissions, as the true objective of policy. It is cumulative CO2 emissions that impact on climate and this implies that significantly higher environmental and economic value attaches to early sustained reduction in emissions. Moreover, for any given percentage reduction, an early rather than late reduction profile, if adopted globally, would give substantially lower concentrations in 2050. Demonstration of the fact that there is a significant front end loading to the profile of the social cost of CO2 emissions is easily demonstrable. [See a recent note on the social cost of carbon. ] Working with cumulative emissions would exert a discipline and immediacy on current policy and inhibit the postponement of necessary actions or reliance on hypothetical future measures.

For an equivalent pace of CO2 reduction, an 80% target requires much more substantial measures to be taken even in comparison to an already demanding 60% target. The advice recognises that systemic change needs to be achieved in all main sectors responsible for emissions, and should be taken to imply early and sustained programmes of action across the board.

The higher target puts even more pressure on the power sector to become virtually carbon-free by not much later than 2030. This is recognised implicitly in the interim advice, and closely reflects the conclusions of our earlier analysis of time paths for CO2 reduction. (Shaping carbon budgets)

The pace and nature of the changes required caution against excessive reliance on a market based approach and market mechanisms. A recent paper reviews the extent to which the UK electricity market is "fit for purpose" in this respect. [Will Markets Deliver Low Carbon Power Generation?]

Thursday, October 2, 2008

Will Markets Deliver Low Carbon Power Generation?

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. The paper was presented and discussed at the September 2008 Parker Seminar. It has now been published in the SPRU electronic working paper (EWP)series.

Comments may be posted using the link at the end of this article. All comments are moderated.

John Rhys. September 2008.

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

Key Issues for Policies on Climate Change

This paper was prepared by the BIIE Climate Change Policy Group in May 2008 to summarise a number of general issues the group believes should be considered by the new Committee on Climate Change: use of cumulative targets, urgency and the need for an indicative framework, and reliance on markets to deliver CO2 reductions.

The BIIE Climate Change Policy Group is a group of senior professional economists with an extensive collective experience in energy policy and the energy industries.
Our antecedents pre-date the Stern report, when we called for much greater attention to be paid to climate issues. We have previously endorsed the general recommendations of the Stern report, without necessarily an unqualified acceptance of every feature of its detailed analysis. We believe coordinated international action is essential, and that UK action can have an important role to play within a global strategy of “contract and converge”. We have been advocates of unilateral UK action on both exemplary and self-interest grounds, and we welcomed the Climate Change Bill and the creation of the Climate Change Committee (CCC). We have in the past submitted evidence to the Environmental Audit Committee and to the Joint Parliamentary Committee considering the Climate Change Bill.

In this note we wish to focus on a small number of general issues to which we believe the CCC needs to give consideration at an early stage in its deliberations. We have selected particular issues which we believe are important, under-emphasised and on which we believe our group has developed a particular and distinctive view:
  • Defining the right basis for UK and international targets for CO2 reduction – as essentially cumulative. Doing this also reinforces the general case for urgency of action.
  • What we have described as a “time-critical” approach - the value of developing an indicative framework by sector.
  • The balance of instruments available to Government – concerns about the ability of the present market and institutional framework to provide the necessary incentives and momentum for change.


The clear implications of the best available evidence from the climate science are that CO2 policies need to align with the global objective of preventing concentrations from reaching dangerous levels. This implies a focus, at the level of global objectives, on keeping cumulative emissions within “safe” limits. Targets for annual emissions in particular years are useful indicators of progress, but are ultimately of secondary significance, since they should be determined by, and should not obscure, the primary objective. This implies, potentially, more pressure for more demanding reduction regimes in the early years. It reduces the very serious risk of postponing necessary policy actions by making the consequences of poor early performance more transparent. This is reinforced by further practical and economic considerations.

First, as a matter of simple arithmetic, the shape of the path from the baseline to a given 2050 annual emission level has a very large impact on cumulative emissions over 43 years. To illustrate the point, a 60% reduction over 45 years can be met by a steady 2% pa reduction. However a 3.5% pa reduction for 20 years followed by a 1% pa reduction for 25 years yields the same annual emissions after 45 years, but a cumulative emissions total that is lower by the equivalent of 9 years emissions at the end of the period, loosely speaking “gaining” an additional 9 years of time.

Second, the undeniable primacy of cumulative emissions, implied by the climate science, means that a rational approach to the design of any international regime and its associated market mechanisms is also more likely to be based on cumulative emissions from a baseline, or on some cumulative measure of emission costs. This would allow carryover of emission rights/savings between time periods, and would place less emphasis on rigid annual numbers. It is hard to see how international agreement could be obtained for a scheme that ignored the inequities of very different national pathways to a single year target. Aligning national targets consistently with the shape and structure of future international regimes, including the ETS, will be essential.

Third, and contrary to an impression created, unintentionally, by the recent DEFRA report on the social costs of carbon, the economic damage attributable to emissions[1] is higher the earlier they occur. It follows that the economic calculus should in principle be weighted even more towards a front end loading of reductions than would be implied by a pure cumulative target, and certainly more than would be implied solely by an “end year” annual rate. It also follows that the advantage of measures to sustain early reductions is twofold. Early reductions reduce CO2 at the time when that reduction is of most value (in terms of reduced damage); assuming they can be sustained they also reduce emission in all future years. Larger early reductions, if they can be achieved and sustained, are disproportionately beneficial in reducing cumulative emissions, and hence in delaying adverse climate impacts and/or easing the pace of transition to low carbon in later periods. This is one of the factors supporting greater urgency. This should be reflected in the value attaching to early reduction in emissions, and in more emphasis on cumulative emissions as the primary objective.

Fourth the above considerations will assume much greater significance if, as part of the review of the 2050 target, policy is to be based on a UK contribution to limiting CO2 concentration to 450 ppm (rather than the 550 ppm adopted since the 2003 White Paper). Not only would allowable cumulative emissions to 2050 be significantly lower, but also, because of lack of progress over the last decade, much larger reductions are required over a shorter period, further strengthening the case for urgency.


Our approach emphasises “time criticality”. We believe that a focus on timescales, once targets are settled and clearly linked to a science based limit for cumulative emissions, is a key to embedding urgency into climate change policy. By working back from the answer, establishing feasible trajectories would help to illustrate not only the scope for progress within the first three carbon budgets but also the rate of progress required after 2020 to stay within the cumulative limit. This would focus attention on the most critical and urgent issues. Simple illustrations indicate, inter alia, the central importance of the power sector, and the rates of change necessary in transport or in heating of buildings to recover to a cumulative target after failure to reach White Paper targets.[2]

Implementation, as distinct from budget setting, must also address the issue of lead-times. Although effective short term measures are vital and should be maximised, their scope is limited and over the whole period to 2050 realistic solutions will entail the often protracted lead-times involved in removing sources of inertia and “barriers” to change, and in introducing low carbon technologies and systems, with associated changes in infrastructure, institutions and financial and economic frameworks.

Accordingly the successful implementation of any path of UK CO2 reduction by 2050, consistent with keeping global concentration levels below 450 ppm, (or such other target as may be agreed) will require rigorous scheduling of measures from now on. Given the starting point there will be frequent tension between the urgent need to accelerate emissions reduction, and the lead-times involved in taking effective action. This tension gives rise to time critical issues. We have argued elsewhere that each of the main sectors (power generation, transport and heating of buildings) should be analysed by the relevant Government departments to identify these time critical issues and to indicate the timing of key decisions and commitments and the main agents of change. We cannot see how sustainable progress on CO2 reduction can be made without this kind of time critical analysis on a rolling basis endorsed by Government and conducted throughout with emphasis on urgency and lead times, with explicit timetables for action. Such an analysis needs to become an integral part of the accountability process associated with carbon budgets.


We have a fundamental concern that, even if government objectives and carbon budgets are clearly linked to the urgency of the science, and even if time-critical analysis is effectively incorporated into the carbon budgeting process, the present market and institutional framework will not provide the necessary incentives and momentum for the rate of change that is required.

This would require a comprehensive survey of existing incentives, regulations and market structures to determine the extent to which they assisted or impeded the rate of reduction of CO2 emissions. The BIEE group intend to carry out work in this area, initially concentrating on some of the issues that will need to be addressed in the crucially important power sector.

The context is defined by the existing market and regulatory structure; this includes large incumbent private sector firms and smaller potential new entrants, and a regulatory authority historically and statutorily focussed on competition issues, price control (of monopoly sectors) and consumer protection. The economic instruments currently perceived as available to government in pursuit of CO2 related objectives are limited to what can be applied within this liberalised market framework. Essentially this means reliance primarily on emissions trading (EU ETS), with some targeted support to renewables or other low carbon capacity.

Some features of these market and regulatory structures may create the potential for market failure, and for outcomes that impede or frustrate policies geared to achieving early and substantial CO2 emission reduction. Particular concerns include the following:

  • the White Paper placed considerable emphasis on carbon trading within the EU ETS. However a carbon price from this scheme may not only be volatile but may reflect only the market’s short term view of the cost of abatement, rather than the value of long-term low carbon investment.
  • asymmetry between incumbent fossil generation and low carbon new entry in terms of the commercial risk associated with new capacity investment (separately identified by Anderson and Newberry); it arises from the fact that fossil plant costs continue to be the price setter over an extended period.
  • potential conflict between the acceptability of instruments within a liberalised market framework and the achievement of optimal outcomes; for example undue reliance on market and trading solutions will fail if other political imperatives such as fuel poverty constrain prices.
  • theoretically at least, the adoption of intermediate targets could lead to outcomes that are perverse in relation to the “true” overarching objective of minimising cumulative emissions; this could occur for example if targets were too loose, delaying investment, or too tight, with shorter term trading signals adversely affecting necessary longer term technologies by inducing “quick fix” solutions.

  • since there is no certain long term carbon price and since the private sector uses a discount rate which is well above the social rate of time preference, the private sector cannot be expected to take socially optimal decisions about the time critical sequencing of low carbon power sector investments (ie there is a market failure).
  • while the twin objectives of low carbon and security of supply may, in the long-run, be wholly compatible, there are likely to be short-term conflicts which cannot always be resolved in favour of carbon; ie security is the more immediately binding constraint
  • general concerns for investors about regulatory risk, and certainty about policy and market frameworks
  • the main regulatory bodies relevant to the power sector have consumer protection and competition policy traditions that do not necessarily sit well with policies that attempt to attach primacy to climate policy
  • market participants do not need to design strategies to cover the risks of overall policy failure; governments do.

For these reasons it seems imperative that the Committee will need to focus on market and regulatory frameworks to make sure they are delivering not just on annual targets but also on future investment on a timescale compatible with overall objectives.


The group hopes the above observations will be useful to the Committee, particularly in:

  • the review of the 2050 targets and the effect on carbon budgets
  • linking the carbon budgeting process to the corpus of measures required to achieve sustainable momentum for CO2 reduction

    BIEE Climate Change Policy Group. List of Earlier Papers.

    1. Bringing Urgency Into UK Climate Change Policy. Paper by the BIEE Climate Change Policy Group. December 2006

    2. Time Critical Pathways For UK CO2 Reduction. Supplementary Note by the BIEE Climate Change Policy Group. 27 February 2007

    3. Draft Climate Change Bill. Response by the BIEE Climate Change Group. 24 May 2007.

    4. Shaping Carbon Budgets. Practical Application of an Approach Based on the Notion of Time Critical Pathways. Mike Parker, John Rhys and Gordon Mackerron on behalf of the BIEE Climate Change Policy Group. 3 January 2008

    5. Observations on the Time Profile for the Social Cost of Carbon. Technical Note by John Rhys. April 2008.

[1] The PAGE model results, which underpin both the Stern review and the DEFRA work, make it clear that a tonne of CO2 emitted in 2008 does c. 1.0 % more damage than the same emission in 2009. See also John Rhys note on this subject.
[2] Reference earlier paper on shaping carbon budgets

Urgency in Reducing Power Generation Emissions.

Time Critical Issues in Reducing CO2 Emissions in the Power Generation Sector.

This paper was prepared on 23 March 2008 by Mike Parker, John Rhys and Gordon Mackerron as an application of an approach to identifying time critical issues in the power sector. It reflects the continuing focus of the group on injecting urgency into UK policy on carbon and greenhouse gas reduction.


1. The group has consistently emphasised urgency in the conduct of climate change policy. The tension between urgency and the lead-times involved in implementing necessary steps, particularly investments, has led us to define what we have called “time critical” issues. Our earlier analysis has identified the UK power generation sector as absolutely central, within a time critical framework, to the achievement of targeted overall CO2 reduction trajectories. This first note on the identification of sector specific issues therefore concentrates on time criticality within that sector and on the implications for the carbon budgeting system. Resolution of these issues falls in large measure within the responsibility of government. Without attempting to prescribe particular resolutions, we believe the government needs to state clearly the resolutions, measures and initiatives that are required, and the timing that is needed, so that progress can be monitored within the carbon budgeting system.

Matters affecting power generation emissions up to 2020

2. The White Paper central projection has power generation emissions falling from 47 Mtc to 36 Mtc by 2020, consistent with a straight line reduction in CO2 to nil by 2050, which is broadly what will be required if the 80% path is adopted. The White Paper analysis rested on:
  • i) delivery of demand/ efficiency measures sufficient to keep electricity demand broadly stable, rather than rising under business as usual (BAU) conditions
  • ii) a trebling of renewable power generation by 2020 nearly offsetting the decline in nuclear
  • iii) a large fall ( c 40%) in coal reflected mainly in higher gas generation

Of the above (i) requires a conventional monitoring process, but (ii) and (iii) raise important time-critical issues. We therefore deal in turn with renewables and fuel substitution.

3. The whole question of the feasible expansion of renewables by 2020 was difficult even in the context of the White Paper expectation of around 15% of UK electricity generation. Now that the “EU obligation” may be for 30% or more from renewables (from a current position of 5%) in little more than a decade, any sensible discussion of feasibility must be grounded in a realistic view of what can be delivered from different renewable sources within that timescale. This may be considered to be a form of indicative plan but its essential requirement is a framework within which to monitor the effectiveness of policies, and to identify failures or gaps at an early stage. Quite apart from the renewables target per se, an early realistic assessment of the feasible expansion of renewables by 2020 is vital in order to determine the extent to which new gas and coal plants (to offset old coal and nuclear retirements) are unavoidable.

The “indicative plan” for renewables would need to indicate:

  • whether, and if so what, combinations of renewable technologies could in principle meet the 2020 target, based on time profiles, by technology, of capacity or projects under construction, in the planning system, or yet to be submitted?
  • the lead times for the capacity component elements of such combinations need to be identified, together with the extent to which these are affected by
    - constraints in construction capacity
    - complex planning issues for major projects (eg tidal barrages) and generalised planning issues for smaller scale technologies
    - insufficient R&D
    - very high costs and their implications for financing
    - any other potential resource constraints
  • implications for infrastructure; which in turn may require review of regulatory incentives and conditions governing transmission investment, as well as the integration of “distributed” supply within lower voltage local networks
  • addressing the issues associated with any potential intermittency constraints, by progressing electricity storage or other load curve adjustment measures such as sophisticated tariff and load control systems
  • whether and what changes may be required to the financial framework for investment in renewables. In particular will the Renewables Obligation, even with the reforms proposed in the White Paper, be able to cope with the quantum and speed of what is needed? How soon could a new approach be introduced?

4. It is not clear from the White Paper how the substantial switching out of coal, mainly into additional gas, is to be achieved by 2020 or precisely how the workings of the EU ETS will contribute, and when. There is currently considerable uncertainty [notwithstanding the explanatory note in Annex 1, DTI Paper URN/947]about the carbon price which will emerge, either in Stage II or III, and how this will interact with the variable and uncertain relativity of international coal and gas prices.

Proposals for a new coal-fired plant underline the seriousness and relevance of the issue. Failure to solve this problem soon could have a significant effect on the cumulative CO2 emissions from the power sector in the period to 2020, and thereafter.

Matters affecting power generation emissions after 2020.

5. Even if power generation emissions are reduced to 36 Mtc by 2020 (as in the White Paper central case) reductions in emissions after 2020 will be crucially dependent on decisions and measures taken before 2020. For developments post 2020 we need to be concerned with four main issues:

  • the follow-on for renewables development
  • the development of the nuclear component
  • the development of carbon capture and storage
  • preliminary indications of the role of carbon-free electricity in reducing emissions in the building and transport sectors, since this may influence plans for the development of nuclear and carbon capture after 2020 and some decisions at an earlier stage

6. Renewables. The level and momentum of renewables generation after 2020 will be heavily influenced by the performance of the sector before 2020, and, as we argue above (para. 3) this requires the time-critical analysis of an indicative plan as soon as possible. In addition further RD&D will be required to create new or improved technical options to mature after 2020 (whether on a UK, EU or other international basis). Many of the issues identified for attention pre-2020, such as issues of intermittency, and load balancing and control, will remain post 2020 although the emphasis and detailed parameters will alter with the development of both demand and other supply options in the power sector (electricity substitution in transport and heating, and the advent of nuclear and CCS contributions). Given the inherent lead times work needs to begin soon.

7. Nuclear. Generation from new nuclear is unlikely to be significant before 2020, and the overall capacity and timing of new plant thereafter remains very uncertain. Our last paper identified key issues as: licensing, reactor choice and tendering, construction, planning constraints, infrastructure provision. These issues, together with that of assuring a robust financial framework need to be resolved in the next 2/3 years to ensure the earliest feasible achievement of carbon reduction from any nuclear programme, and to get a clear view of the nuclear contribution to the position in 2030 and thereafter.

8. Carbon capture and storage (CCS). Our last paper identified key issues in terms of steps to a demonstration project, identifying storage facilities with appropriate capacity, testing security of storage, mechanisms for moving from demonstration to large scale, decisions on extent of retrofitting, infrastructure provision specifically in relation to CO2 gas gathering and liquefaction/pumping, as well as general infrastructure and financial framework issues common to renewables and nuclear.

Great store is being placed by policy makers, both in the UK and internationally on CCS. but no commercial scale CCS power generation has yet been developed in any country. Without further effort, it is unlikely that the feasibility and economics of CCS can be fully established from currently envisaged pilot plant studies (UK/EU) before 2020. If commitment of investment in major CCS projects has to wait until then, significant CO2 reductions will be further delayed, and there will be a problem of “lock-in” to “unimproved” fossil capacity, capacity that cannot realistically be expected to accomodate CCS at an early date.

With gas and coal plant further increased there is an urgent need to examine how this difficulty can be overcome by addressing, among others, the following questions:

  • i) can technical knowledge be accelerated by access to projects beyond the UK pilot scheme?
  • ii) to what extent are potential UK CCS sites limited by geography or geology? How soon can the best sites and capacity be identified?
  • iii) what infrastructure will be required for identified sites? Given lead-times, when does investment need to begin?
  • iv) when will the UK CCS Regulatory Task Force report? Which details are time-critical? [in the sense of affecting lead-times on CCS projects]
  • v) how soon can a financial framework [including incentives] be determined, both for CCS plants and infrastructure? And how far can this precede full feasibility tests from pilot plant?
  • vi) in the meantime how far can the carbon readiness requirements for new gas or coal plant be strengthened as a means of accelerating CCS preparations generally?

9. Electricity Substitution in Heating and Transport. It was implicit in our earlier paper that, at least under some feasible scenarios, we expected this to be a core component of a realistic pathway to meeting 2050 targets. The questions here are perhaps less obviously or immediately time critical for the power sector per se, but neverthless it is probable that early identification of alternative options could assist in better decision taking with respect to the power sector. The nature and pace of this substitution is relevant, inter alia, to:

  • the overall scale of power generation capacity required
  • accentuation of intermittency and load curve issues (heating load) or their partial resolution through the conversion to stored energy (batteries or hydrogen)

Reliance on the EU ETS

10. One of the themes that has been implicit in some of our analysis of time-critical issues in the power generation sector is the extent to which the Government appears to rely in future on the EU ETS to promote low carbon investment. While we believe that given the proposed reforms in Stage III, EU ETS will have a significant role, we remain sceptical on how to important the carbon price generated from the EU ETS will be for three reasons: first it is uncertain whether this carbon price will be high enough and stable enough, and how long this uncertainty will continue; second the carbon price effect will continue to be heavily conditioned by the absolute and relative prices of fossil fuels and of wholesale electricity which are themselves uncertain; third the exposure to commercial risks will vary between different potential investors - new nuclear, CCS (coal and gas) and a range of renewable technologies. This difficulty was in fact recognised in the White Paper which stated (para 5.1.34):

“Given the scale of investment in new generation assets required in the UK over the next two decades UK investors need clarity over carbon market fundamentals in good time [our italics] if they are to make investment decisions consistent with the Government’s energy policy goals. We will therefore keep open the option of further measures to reinforce the operation of the EU ETS in the UK should this be necessary to provide greater certainty to investors.”

Confidence that the scheme can deliver as required is itself time-critical and early resolution of these uncertainties is therefore required.

Implications for the carbon budgeting system

11. We have set out in this paper the main time-critical issue in the power generation sector. If the required rate of progress towards a virtually carbon-free UK electricity system is to be achieved, all these issues need an effective response by government, with clear statements on the measures/ initiatives required, and their timing, within the next 2/3 years [well within the first carbon budget period].

12. On the other hand because of inherent lead-times, even very rapid response by government would result in very limited CO2 savings in the first carbon budget period; a crash programme on renewables would show up in the second and third carbon budget periods; and enabling measures on new nuclear, CCS and second generation renewables would not deliver significant CO2 reductions until after the third budget period.

13. In the case of the time-critical issues set out in this paper, the gross mismatch of timescales, between government initiatives and measures and their full effects in terms of CO2 reduction, needs to be recognised in the accountability process, since the issues are too important to be excluded. The DEFRA note of Feb 2008 “Government Proposals for strengthening the Climate Change Bill” proposed strengthening the compliance mechanism by requiring the Secretary of State to bring forward proposals and policies to enable the three carbon budgets that have been set to be met, and having regard to the duty to meet the 2050 target.

14. In our view this can be done effectively only if, in addition to conventional monitoring of short term “incremental” measures on energy efficiency and demand management, there is detailed annual scrutiny of the progress of all government measures designed to “create the conditions“ for CO2 reduction, not only within the three budget periods but also beyond. In the interest of urgency in policy implementation, such scrutiny should include the time critical issues set out above.

Tuesday, June 24, 2008

Shaping Carbon Budgets


Practical application of an approach based on the notion of time critical pathways

This note was prepared in January 2008 by Mike Parker, John Rhys and Gordon Mackerron
on behalf of the BIEE Climate Change Policy Group . Its purpose was to stimulate ideas on how to use a "time criticality" approach to work from an overall and long term (2050)cumulative target for CO2 reductions to a set of sectoral policy requirements.

1. We strongly welcomed the lead given by government in the Climate Change Bill, with the creation of a new institutional framework to back a system of “carbon budgets” which will set legal limits on UK CO2 emissions within rolling five year periods.

2. However we are concerned that the carbon budgeting system, with its associated accountability and monitoring arrangements, cannot be effective without public scrutiny of the whole corpus of policies and measures concerned with the low-carbon issue, since these arrangements will need to highlight not only recent performance of carbon emissions against budget, but also those steps being taken to increase the momentum of carbon savings in the short-run[1], and to create the conditions for transition to longer term technological and system changes.

3. Moreover these procedures need to address directly the issue of urgency in the conduct of UK climate change policy. Given the long lead times involved in removing the sources of inertia and “barriers”, introducing low carbon technologies, and making the associated changes to infrastructure and institutions, the successful implementation of any 60% path to CO2 reduction is already on a very tight schedule. For an 80% reduction path the schedule would be even more demanding. Procedures therefore need to place great emphasis on lead-times and time criticality.

4. Accordingly we believe that the carbon budgeting system should incorporate detailed descriptions, endorsed by Government, on how and at what rate the emission reduction targets are to be achieved. We call these descriptions “time critical pathways” (TCPs). Our purpose here is to indicate our preliminary views as to how this approach would work, and how these ideas can be developed further.



5. Policy analysis in the White Paper and elsewhere has been based on disaggregation into sectors, given the very wide range of detailed issues involved in terms of technologies, market structures and policy instruments. We recognise there is an element of overlap in certain cases – for example micro-generation and other decentralised electricity on energy use in residential and other buildings, and the use of electricity in transport. The core sectors in our view are electricity, transport, and heating of buildings (residential, commercial and service sectors). All three depend to a very significant degree on UK-specific factors, potentially demanding UK specific strategies and policies.

6. Industrial process heat, though a significantly smaller contributor to total emissions than the above, is still substantial. The adaptation of UK industry and its competitiveness will be a large and important issue, albeit one that needs to be viewed primarily in the wider international context of the EU ETS. Two other very significant sectors – aviation and shipping - also need to be included in a comprehensive strategy and in emission targets, as we have argued in earlier papers.


7. We envisage TCPs for each of the main sectors being drawn up by the relevant Government departments (with coordination on overlaps). These would be consistent with the achievement of the aggregate target of CO2 reduction by 2050, with the minimisation of emissions in years to 2050 and associated targets for cumulative emissions, and would clearly set out the order and timing of the key developments, decisions and commitments involved. This process would clearly need to recognise uncertainties, to retain elements of flexibility, and to provide reasonable certainty of achieving targets and objectives. TCPs would be subject to periodic revision. Subject to these constraints and objectives the process would also seek to minimise the overall costs of the measures required.

8. These TCPs should also be capable of phasing into the first three carbon budget periods (2008-12, 2013-17, and 2018-22) and more broadly thereafter by decades to 2050. Moreover not only would the TCP set out what has to be done and when, but also what actors/agents would be involved and when.

9. For each sector the drawing up of TCPs would necessarily involve covering the following ground:

(a) assessment of CO2 savings available from short term measures to reduce demand, increase efficiency and achieve fuel switching for existing assets and systems, including measures already identified up to the recent White Paper, and the timing of these savings.

(b) identification of the likely portfolio of options for key technology and system changes [over and above those in (a)] which could contribute to the sector’s transition to a nil or very low carbon future by 2050, and an assessment of the speed at which they might be introduced in the light of :
  • Current state of technical development

  • Lead-times to widespread adoption

  • Age and turnover of existing capital stock including infrastructure

  • Nature of factors creating inertia and barriers to progress, including fiscal, regulatory and institutional factors, and the potential speed of their removal

10. For any given sector, technology pathway evolution is inherently uncertain, and also path-dependent. Within a portfolio of options, some are less certain than others and some options may conflict with others; this means that more than one pathway may need to be described, to provide an element of flexibility. This applies particularly to the electricity sector, where it will be essential to consider the relative time criticality issues arising from potentially different pathways for nuclear, CCS and renewables (centralised or decentralised). It might be thought that the use of alternative scenarios might weaken the essential urgency of policy, but this need not be the case. Indeed in such a circumstance the use of alternative TCPs would be a powerful tool in exploring the implications of such unavoidable uncertainties in terms of conflicts or synergies between policy options, particularly in the first two carbon budget periods (2008-2017). Indeed the use of alternative scenarios for the electricity sector, to decide what should be done in the next ten years, is in any case a matter of great urgency.


11. Our position is that the whole question of the balance of instruments should be addressed pragmatically relative to efficacy in reducing CO2 emissions at a rate compatible with urgency, whether or not the result is an increase in Government involvement. The use of TCPs which set out not only what has to be done and when, but also who is involved and when, would be a powerful tool in determining the most effective balance of instruments, including the role of “government” and “markets”. We are not advocating a detailed long term plan determined and controlled solely by Government, but rather a framework to create the conditions for large scale investment and system change to deliver a very low carbon economy in the UK, at a rate compatible with the urgency of the task and in ways that safeguard security of supply and minimise long-run resource costs.


12. TCPs as described in this note could be a vital and distinctive means of injecting urgency into UK climate policy because they:

(i) incorporate time criticality and lead times as essential building blocks in policy formulation

(ii) enable the phased timing of necessary measures to meet CO2 reduction targets to be clearly identified, in a way which can be related to the proposed carbon budget system. Comprehensive and coherent timetabling will be a necessary feature of any urgent conduct of CO2 reduction policy.

(iii) help to resolve potential conflicts between alternative technologies

(iv) provide a way to improve the rationale and coherence of the “balance of instruments” in a way compatible with the necessary speed and progress

(v) above all, allow much greater focus on what has to be done in the first two budget periods (2008-2016), irrespective of whether the resulting CO2 savings occur in these budget periods or later, in terms of
· major investments to be committed, started and completed,
· research and development to advance new options,
· fiscal regulatory and institutional measures to remove barriers to urgent progress


13. In this illustrative example the idea of time criticality is used in different ways and at different stages to show how a broadly defined strategy, with a loose collection of plans, policies and forecasts, could be developed and articulated in a coherent way using the notion of TCP, and how TCP would assist in some of the ways described in the first section of this paper.

14. As this is intended only as an illustration of TCP, it ducks some of the questions we have talked about earlier, in terms of where the strategy sits in the spectrum between centralised planning and a pure market approach. The distinction may be more illusory than real, if it is clear that even a market-based approach demands that particular engineering, regulatory and financial events inevitably happen in a well defined sequence. However a TCP may well indicate very quickly when either plans or markets are failing to deliver on their part of the strategy.

15. The example deliberately uses a very stylised and simplified approach, in order to avoid, as far as possible, a misleading impression of a level of precision and consistency that could be expected only after incorporation of more detailed analysis, which would have to be a feature of a real “live” application of TCP. As a first step this illustration uses a simple spreadsheet and some assumed annual percentage reductions to get a broad feel for the arithmetic of individual sector effects in relation to targets for cumulative emissions and 2050 annual emission targets. Even this very simple and approximating approach, however, quickly gives a feel for scale and orders of magnitude. Material derived from more elaborate energy sector models such as Markal, and numerous additional assumptions within a chosen strategic framework, inclusion of additional sectors and subsectors, and more precision about targets[2], could be used to convert this illustration into a more solid and reliable exercise with real UK data.

16. The example describes a fictitious world in which there are only three sectors to consider: electricity generation, heating of buildings, and (road) transport. Aviation, shipping, and process heat for industry[3] are excluded, as is the possibility of purchasing international[4] credits. Annual emissions total an annual 10000 “GHG equivalence” emission units in 2007, and the relative shares of the three sectors are of the same order as the 2005 shares for CO2 quoted in the White Paper. The relevant targets to be considered are 60% or 80% reductions by 2050, with associated cumulative emission targets based on constant percentage reductions.


17. A particular strategy has been chosen here to illustrate the TCP approach; it includes a strong supply side approach, including centralised electricity decarbonisation as a core component. In this sense it broadly resembles the recently published IPPR strategy except in that it does not rule out nuclear. It can be characterised as follows:

  • Reliance on White Paper measures in early years. Reductions to 2020 are largely limited to what can achieved through fuel switching in existing assets, including the impact of ETS, plus the impact of White Paper measures which include energy efficiency.

  • Decarbonising the electricity sector is a central theme for the strategy as a whole. It becomes a priority in effecting reductions for the period after 2020, whether through nuclear, CCS, large scale renewables, or a combination. A critically important issue in TCP terms is the rate at which CO2-free capacity can be substituted into the power sector.

  • Electricity for heating buildings; strategy on buildings can include a raft of demand side measures, some of which (such as heat pumps) depend on electricity, but one feature of this strategy in relation to buildings might be that CO2-free electricity becomes a default option for decarbonising the heating sector at some time after 2020 (notably if there is a risk of other measures proving insufficient). The timings for emission reduction in this sector might then become dependent on the pace at which sufficient electrical capacity can be added, as well as the speed and nature of decentralised, energy saving and non-electric alternatives.

  • Transport and innovation. The transport sector is the most obviously dependent on radical technological innovation, as well as possibly major systemic and infrastructure changes. There is a presumption that by 2040 at the latest we should be able to start moving to a hydrogen or electric transport economy. As with heating, both depend on electricity generating capacity.

  • Non-exclusive; a raft of other policies can co-exist with this basic structure, including more emphasis on feeding through of carbon pricing, second generation[5] biofuels, more renewables, regulatory controls, and planning and life style measures (“joined-up government”) aimed at reducing demand; all of these are potentially helpful in terms of time criticality and/or as stopgap measures,[eg biofuels pending more radical technology and innovation]. Some of them will affect forecasts and hence the quantum of what will be required; more detailed analysis will determine whether they impact in a major way on current required actions.
18. This illustration is not intended to be normative. For illustrative purposes it arguably has the advantage that its strong “supply side” element has a more containable number of technical parameters and assumptions, and in consequence some of the TCP issues are more easily and sharply defined.


19. Alternative approaches to strategy can be set out and subjected to a preliminary evaluation of what they will be required to deliver in relation to the arithmetic of targets.

20. Stage I. Making sure the strategy is consistent with the targets. In this illustration we concentrate first on the softer 60% target, reducing annual emissions from 10000 pa to 4000 pa but insist that we also meet an associated cumulative emissions target of 289000 over all years 2007-2050 inclusive. [80% would imply 220,000 cumulative.]

We input savings to 2020 based on the White Paper estimates, taking a “low reductions case” based on the White Paper, and assuming a constant annual percentage decline in this period. This is roughly speaking a 17 % decline in power sector emissions by 2020 (mainly due to coal to gas switching), a 33% reduction in heating related emissions (mainly residential), and no overall change in transport emissions by that year.

It is quickly apparent, as one would expect intuitively, that meeting targets under this strategy depends primarily on the pace at which the power sector can be decarbonised. We can experiment with different rates of progress, but the most ambitious limit so far contemplated is one in which emissions are halved between 2020 and 2030. This may seem like an excessive rate of turnover of capital stock, but would be wholly consistent, for example, with French experience in the 1980s and 1990s, or with recent proposals for UK offshore wind. However it is very hard to see how this strategy could deliver even on the 60 % target without such a rapid rate of progress in the power sector.

The next step is to consider what rate of progress is required in the heating and transport sectors after 2020. This is a bit more hypothetical and open-ended, primarily because there is a much wider raft of possible policies and technologies, but is still worth examination. However if we assumed no further reductions in these sectors between 2020 and 2030, perhaps because the White Paper measures had by then run their course and exhausted their potential, or because of insufficient electricity, then even for a 60% target, when expressed as a cumulative target, we would require 4% annual reductions in both sectors after 2030 in order to get back within the cumulative emissions limit. Given the nature and slow turnover of the building stock, and current perceptions of the intractability of the transport sector, 4% pa reductions represent a substantial challenge.

Moving to an 80% target, together with its equivalent cumulative target, is even more demanding, and implies larger and earlier contributions from heating and/or transport sectors. A possible corollary is the earlier need for demand side measures in these sectors.

Lessons from stage I.

22. Although this is no more than simple arithmetic, it is helpful in demonstrating that the strategy can deliver, in identifying key elements of time criticality, and in alerting policy makers to the adverse consequences of falling behind “planned” rates of progress.
  • Significance of taking cumulative targets as compared to end year annual rates; low rates of reduction to 2020 make the achievement of cumulative targets much tougher than a “per annum by the year 2050” target

  • Identification of significance and benefit of early achievement of power sector decarbonisation, by whatever route.

  • Necessity of substantial and relatively early progress in the building sector after 2020, with continuing reductions in heating beyond what has been achieved by White Paper measures to 2020.

  • First impressions of rates of change that will need to be achieved in transport sector: at least 1% pa after 2020, and significantly more if there is any growth to that point or if other sectors do not deliver.

  • Sensitivities; how falling behind any part of plan will impact on pace of change required later and/or in other sectors to “catch up”.

In particular, any failure to deliver on the expected savings from the White Paper measures by 2020 has a very adverse effect in requiring difficult “catch up” later.
An 80% target increases the pressures for early action to constrain near term growth or to cut emissions in heating and transport.


23. Stage 2. Drill down into the individual sectors. This process requires much more detailed consideration of alternative and complementary options in each sector. The aim is to identify explicit objectives, actions and timetables, both positive and precautionary. Above all it is vital to bring out the extent to which a strong momentum of CO2 reduction after 2020 depends on identified urgent actions being taken over the next ten years.

24. White Paper measures, 2007-2020

Objective: to ensure that the White Paper measures deliver both volume and to timetable.

Time criticality: monitoring of progress in detail, and dealing with observed shortfalls[6], if necessary seeking to strengthen existing measures or find additional savings.

Actors and agents: energy companies, government, ETS players and energy markets, regulatory bodies.

25. Power sector

Objective: to enable major carbon substitution beyond what can be achieved through the White Paper measures, with first carbon-free capacity starting 2020-22.

Time criticality: this is based around activities and preconditions associated with the alternative generation options, namely clear timetables for action on:

  • CCS; steps to demonstration project, identifying storage facilities with appropriate capacity, testing security of storage, mechanisms for moving from demonstration to large scale, decisions on extent of retrofitting, infrastructure provision specifically in relation to CO2 gas gathering and liquefaction/pumping;

  • Nuclear: licensing, technology choice and tendering, construction, planning constraints, infrastructure provision;

  • Large scale renewables – offshore wind or tidal power; resolve technical issues and uncertainties, planning constraints, infrastructure provision.
In each of the above cases, it is also necessary to determine whether the market will currently support the investment and on what terms. If the answer is negative then an immediate analysis/decision is required either on a viable alternative strategy, or on taking measures to make this strategy commercially viable eg by dealing with factors that predispose to market failure[7]. Similar questions need to be asked if only one, or only two, of the three main options can be considered commercially viable.

Actors and agents: energy companies; project promoters and finance providers, national grid, government on infrastructure issues, energy markets

26 Heating after 2020.

Objective; ensure ability to effect continuing rapid rate of emission reduction after 2020.

Time criticality; closely linked to the multiplicity of individual measures affecting this sector, but may include preparation of legislative and regulatory frameworks; part of strategy dependent on power sector capacity, but also need to examine in more detail policies and timing for zero carbon new housing, and need to have additional options available.

Actors and agents: government, builders, local authorities, architects, regulatory bodies, housing markets

27. Transport.

Objectives; develop sufficient number of options to ensure capability to meet sustained rates of reduction as soon as feasible; to be consistent with target arithmetic this should be no later than 2030.

Time criticality; The time dimension will be based partly around international research and development directions for the several, not mutually exclusive, options that include hydrogen, electric (batteries), and “type 3” biofuels. However the first two of these also rely on electricity, and on significant infrastructure changes (hydrogen production and distribution, and battery charging) which will tend to bring forward decision dates. Even if biofuels are supply limited they may still have a significant stopgap role.

If the overall arithmetic requires more from the transport sector, especially in the context of an 80% target, then demand side options need greater prominence. Two significant options for short to medium term reductions might be the enforcement of lower speed limits, and move to universal congestion (road) pricing, the second of these having very substantial technology, infrastructure and political/legislative dimensions.

Actors and agents: research bodies, car manufacturers, other manufacturers, energy companies, public transport bodies, government and local authorities.


28. The TCP approach provides a means of incorporating estimates, ideas and logical connections within a strategic framework. It differs from but may be complementary to more familiar approaches to forecasting, scenarios and optimisation models.

The BIEE group will therefore be continuing to develop the concept by examining particular projections, scenarios and sectoral policies from a TCP perspective. The objective will be to construct or identify strategies that deal explicitly with urgency and time criticality, and to do so in a form that will be useful for the carbon budgeting process, particularly for the first two periods.

Annex 1. Hypothetical 3-sector example. Indicative charts showing required rates of change over a 43 year period to 2050 in order to meet a 60% target (interpreted as a cumulative equivalent).

Chart of total emissions with sectoral breakdown. (above)

Chart of emissions for each sector

Horizontal axis is years 2007 to 2050. White Paper reductions assumed to 2020.

Chart of emission levels consistent with 60% target interpreted as an equivalent cumulative target. This profile requires a 63.5% reduction in annual emissions by 2050.

Annex 2. Same hypothetical 3-sector example. Indicative charts showing required rates of change over a 43 year period to 2050 to meet an 80% target (interpreted as a cumulative equivalent).

Chart of total emissions with sectoral breakdown. (above)

Chart of emissions for each sector

Horizontal axis is years 2007 to 2050. Emission levels consistent with 80% reduction when interpreted as an equivalent cumulative target. Almost impossible to achieve without increasing assumed White Paper savings [applied to electricity in this example] and also assuming very dramatic transport reductions from 2020. This profile requires a 90% reduction in annual emissions by 2050 to meet the cumulative target!


[1] The short run in this context is defined to mean the immediate future within which no major changes to existing assets are feasible.
[2] eg on GHG as opposed to CO2 equivalence and the associated technical parameters required for a GHG calculation.
[3] If we did compare this stylized example with UK actual data, then inclusion of these sectors would tend to make the targets harder. Even though the excluded sectors are smaller, industry presents a problem because the WP measures assume little change by 2020, and aviation and shipping are fast growing.
[4] In contrast with the exclusion of the smaller sectors, allowing international credits tends to soften the impact of the targets.
[5] Sometimes referred to as “ligno-cellulose”, these biofuels are typically derived from marginal land without alternative uses for food production. Lower CO2 emissions are involved in their cultivation, and their net contribution to carbon reduction is consequently higher.
[6] Particular concerns attach to the EU ETS and its ability to deliver the amount of coal to gas switching postulated in the White Paper.
[7] This might include consideration of guarantees, floor prices or other measures.