Economics, CO2 Reduction, Energy Policy.

CAN UK ELECTRICITY MARKETS DELIVER A LOW CARBON FUTURE? FINDING THE WAY FORWARD.

2011-02-14T13:48:00.002Z

INTRODUCTION

The starting point for this analysis is two observations on the prospects for achieving a low carbon economy in the UK. The first is that the role of the electricity sector is absolutely central and is hugely important to almost any strategy for achieving this objective. The second is that there is now considerable scepticism about the efficacy of competitive markets, as currently constituted, in delivering a low carbon future - the consequence of a number of current and potential future sources of market failure.

The central role of electricity derives in turn from a number of very simple observations:

* the power sector currently accounts for some 35% of UK CO2 emissions, and the share would be higher without current nuclear and renewable contributions.
* the second largest and fastest growing source of emissions, accounting for another third, has been the transport sector, where the main technology alternatives, at least for road transport, are electric or hydrogen solutions, both dependent on a substitution of low carbon primary electricity for fossil fuel.
* electricity plays a significant current and potential substituting role in other sectors – heating of buildings and in industrial processes such as metal melting – conventionally assumed to be dominated by direct use of fossil fuel.
* electricity is often the only economic vector for non-fossil sources of primary energy.

This contradicts the traditional arguments sometimes presented on environmental grounds, but usually driven mainly by anti-nuclear sentiment, that electricity is a relatively unimportant component of the energy mix. However this central role will, to most serious analysts, now be seen as an incontrovertible fact.

On the second starting point, scepticism over the effectiveness of the current market structures for the UK energy sector has been a feature of several recent reports and consultations, including the recent OFGEM consultation on gas and electricity markets. This was seen as radical and controversial because, in a context of security and sustainability objectives, it questioned the efficacy of markets. In this it reached a very similar set of conclusions (1) to the Committee on Climate Change. Both analyses confront the continued validity of a post 1990 paradigm in which competitive markets are expected to resolve all problems.

The UK has taken justifiable pride in its particular intellectual and technical contribution to international thinking on power sector issues and reform, in creating functioning electricity markets for predominantly fossil-fired plant. To retain intellectual leadership in this field it should now be considering how best to adapt both to a changing technical environment (post fossil) and a changing policy environment (the CO2 externality).

Part One of this paper demonstrates that concerns on the efficacy of markets are in this context very well founded and that the central role of the power sector in achieving targets for reduced CO2 emissions should imply a radical reappraisal of market arrangements. Part Two attempts to develop some ideas on how this might be addressed in order to retain the best features of competition while addressing some of the sources of market failure.

PART ONE. A CRITIQUE OF ELECTRICITY MARKETS IN RELATION TO LOW CARBON POLICY OBJECTIVES.

A first step is to examine more critically the sources of the benefits, in lower costs and prices, that have accrued under the post 1990 market regimes. (2)

POST 1990 EXPERIENCE. ASSESSING THE GAINS FROM REGULATION, COMPETITION AND OTHER FACTORS

It is the attribution of the efficiency gains and substantial cost and price reductions following the major market reforms and privatizations in 1990 that largely drives argument over the advantages of current market arrangements, and especially over particular features such as the forms of electricity trading or supply competition. Defenders of the status quo on markets implicitly attribute a substantial part of past gains to the current structure of trading arrangements rather than to the body of 1990 reforms as a whole; this conditions any assessment of the costs and benefits associated with more radical changes to current trading and market structures.

However a very high proportion of historical efficiency gains and falls in consumer prices post 1990 derived directly from factors which cannot legitimately be ascribed either to particular features of the market structure or even to the existence of a competitive market per se. In particular, and taking the whole period since 1990, the most important factors promoting lower costs and prices included:

* elimination of high cost UK coal, which disappeared as initial vesting contracts were phased out in the 1990s. This reflected abandonment of the policies of successive UK governments in forcing the electricity industry, the CEGB, to support the UK coal industry. Privatisation and competition may have provided a convenient cover for this policy change, but this gain would or could have occurred under any form of regulated or competitive industry.
* the simultaneous advent of relatively new technology in the form of combined cycle gas turbines (CCGT); since this was and is an international technology, the innovation and its development cannot be ascribed wholly or in part to UK market liberalisation.
* combination of this factor - CCGTs - with a period of low energy commodity prices, and cheap and plentiful gas.
* very substantial increases in efficiency, and cost reduction, in natural monopoly elements of the sector, especially distribution costs; these however were driven by a combination of regulatory and private sector incentives, not by market arrangements for generation and supply.
* with CEGB assets sold off at below book value, and significant capacity surpluses through much of this period, both the need and ability to earn a full return on the capital value of historic investment were largely removed.

These factors should condition any assessment of the effectiveness of competition per se as the prime driver of efficiency and cost and price reduction.

There is nevertheless evidence, especially post 1990, of significant improvements in generation efficiency, most notably in power station operation and availability, driven partly by competitive market pressures and partly by disciplines arising from private ownership of the facilities. This was reinforced by reductions in concentration within the industry in the late 1990s, driven by post-1990 competition policy concerns.

However it is very hard to argue convincingly that even these gains resulted from particular characteristics of the competitive market structure and rules since 1990 or 2000, and certainly not from the particular feature of supply competition per se, the component of the competitive framework most directly affected by more radical reforms such as a supplier obligation or a central buyer. Indeed Green (3) has argued that retail competition can raise wholesale prices, corresponding to reduced efficiency and ultimately higher consumer prices, in comparison with a market based on long term contracts and a regulated supply business.

One further factor deserves mention – the 2001 NETA changes. Inter alia this removed the element of capacity payment, with an inevitable short term downward effect on prices. However failure to provide an alternative means to reward capacity contradicts the fundamental economics of the power sector, especially the link between market driven prices and investment. It is now widely held (4) to be a significant part of the security of supply issue.

We should not therefore assume that established advantages and benefits, accruing from a structure built around competition and private investment, would necessarily be compromised even in quite major modifications to the current structure.

CRITERIA FOR A WELL-FUNCTIONING MARKET

A well-functioning market for the future, and its associated regulatory framework, must inter alia:
* induce efficient behavior from participants, leading to optimal scheduling and dispatch.
* generate price signals for allocative efficiency in production and consumption
* internalize the costs of any continuing CO2 emissions.
* deal adequately with the coordination requirements in transmission planning and system operation.
* above all, provide a secure basis for the large scale and long term investments required to move the power sector to near complete decarbonisation.

These are the main criteria that should inform judgements about the efficacy of markets. With these in mind we can consider several particular issues for the operation of markets in the context of policies to promote low carbon electricity generation.

TECHNICAL REQUIREMENTS FOR TRADING AND SYSTEM OPERATIONS IN A LOW CARBON NON-FOSSIL FUTURE.

One of the great technical achievements of the radical market design for the 1990 privatisation was that it successfully replicated the operational optimisation embodied in the CEGB merit order structure into a market bidding arrangement. Without this feature the market would have been substantially and visibly less efficient at its inception, undermining claims for the virtues of competition and private sector disciplines in promoting efficiency. It was a pre-condition imposed on the market design.

It also demonstrates the link between the technology of power generation and market structure. Pre-1990, system operation was based on deployment of flexible fossil fuel plant that could respond to meet continuously changing demand for a non-storable commodity. Central control scheduled and dispatched the lowest marginal cost plant in ascending order of merit. Post 1990 this worked through a bidding process which, conceptually at least, encouraged players to bid at marginal cost, and corresponded exactly to the merit order ranking employed within the command and control system of the CEGB. Notwithstanding the NETA modifications to trading arrangements, this close connection remains.

However a future low carbon world is likely to have very different plant operating characteristics, dominated by relatively inflexible plant (nuclear), plant with intermittent and/or stochastic characteristics (renewables), and in the medium term much greater opportunities for positive/negative storage through different types of more flexible demand (eg to serve the transport sector). Faced with very different technical and economic characteristics, where a high proportion of plant may have zero marginal cost but technology specific limitations on flexible response to load changes, electricity markets and system operations will need to be defined very differently. Efficient system operation for example may depend on more complex forms of optimisation defined over weeks or months rather than hours or days.

Some issues associated with current arrangements have already been highlighted in the Poyry report (5), paradoxically the problems for viability of fossil-fired generation dependent on price spikes and infrequent operation, resulting from intermittent wind power. We should expect new problems as both the number of new non-fossil technologies and their contributions increase.

Optimising the operation of generation based largely on a variety of non-fossil or non-thermal technologies is inevitably a much more complex task than simply stacking the short-run marginal costs of generating plant in a one stage, one price, auction process. If it is amenable to an auction process at all, it would probably be to a multi-stage auction with complex structures and no very clearly defined output of a single “price” for each period.

We cannot assume therefore that a market built around the notions of daily or half-hourly optimisation and pricing will remain “fit for purpose”, or that the current structure is capable of incremental evolution to a new and more complex system of market “auctions”, let alone any bilateral trading equivalents, that will still deliver short-term operational efficiency.

This emphasises the central importance of having market arrangements that are compatible with the predominant technologies of the day. If we are seeing an evolution towards a set of technologies with very different operating characteristics, both on the supply and demand side, then we shall need very different market structures. We cannot assume a natural incremental evolution from the rules that exist today, or even that a similar market structure will be possible or optimal.

PROBLEMS IN SECURING LOW CARBON INVESTMENT AND ADEQUATE CAPACITY UNDER CURRENT MARKET STRUCTURES

Both OFGEM and the CCC have correctly focused on the primary issue for market arrangements as being how to ensure high and unprecedented levels of investment, to meet both security and low carbon targets, all against a background of an aging plant stock. Several difficulties exist and are apparent in current market structures.

Perverse treatment of financial risks. OFGEM correctly observe (6) that “investments with stable operating and fuel costs (such as nuclear and wind) could be viewed by … suppliers as more risky than investments whose costs vary with volatile global fuel costs.” Fossil fuel plant will continue to be at the margin for some time and hence to set price. So fossil plant gets a degree of protection (varying by type of fuel and efficiency) equivalent to partial pass through of fossil fuel price volatility. This intrinsically discriminates against non-fossil plant; a pass through of fuel costs for incumbent forms of generation creates a barrier to entry of new technologies.

Asymmetry in treatment of capacity risk. Another unsatisfactory feature of current arrangements is the fundamental asymmetry between the risks of under and over provision, and in particular the conflict this creates between market and social objectives for the power sector.

From a societal perspective, the net costs of over provision may be relatively small. There is a significant resource cost in over investment, but it is partially offset by earlier retirement of less efficient plant. Under provision on the other hand is commonly seen as near catastrophic. Inelastic demand is not choked off by prices, and the outcome is load disconnection and potentially widespread loss of output across all sectors of the economy. It is a “market failure” that cannot be ignored by governments.

However, from an individual investor perspective, and in the absence of long term contracts, it is over-provision that presents worse outcomes, through a collapse of prices. Restoring equilibrium by closing capacity invites regulatory intervention on competition grounds. Under provision, by contrast, implies higher prices and better returns.

This asymmetry was balanced in the1990 arrangements through market mechanisms established specifically to provide continuity (7) in security of supply - a penal incentive requirement on public suppliers to buy in the market up to a price intended to reflect the value placed by consumers on secure supply - the Value of Lost Load (VOLL). This feature was discontinued under NETA, abandoning a fundamental link between setting a security standard and explicit assumptions about the costs of system failure.

In the context of low carbon investment, this asymmetry is even more pronounced. Over-investment implies over achievement of sector carbon targets, and hence more carbon-efficient operation of the sector. Within a rationally administered framework of national targets this would in principle allow more carbon allowances to be “spent” in sectors such as aviation where consumers implicitly attach a much higher value to their use of fossil fuel and resulting emissions. (8) Given that current carbon emissions are typically valued or priced at well below most estimates (9) of their social cost, this would be a large offsetting social gain, albeit one whose incidence may be very diffuse.

Background of uncertainty. OFGEM suggests one problem is a heightened perception of risk and hence high costs of capital. However nominal interest rates are at an all time low, and according to most of the canons of modern finance theory, investment in well regulated utility industries, with risks that are not heavily market correlated, should be low risk and low beta. Anything else implies lack of confidence in the regulatory framework. The real difficulty therefore is in attracting high levels of investment against a backdrop of contractual or regulatory uncertainty.

The most obvious historical parallel for a high investment transformation of the power sector in a modern economy is the highly successful decarbonisation of the French power sector in the 1980s and 1990s, the scale of which was certainly comparable to the challenge facing the UK today, and which was accomplished primarily through the state sector (EDF).

A more convincing statement of the problem, therefore, is to consider how the necessary and very high levels of investment can be achieved through private investment and an appropriate balance of regulation and competition in electricity markets.

Carbon prices. Markets, essentially through the EU Emissions Trading Scheme (ETS) have so far failed to deliver carbon prices that are sufficiently high and stable to support necessary investments in low carbon generation technology. This may reflect unwillingness by governments to countenance adequately tight emission limits, and this has led to consideration of carbon price fixes as one possible solution.

Coordination. Finally, in parallel with the system operation issues posed by new technologies, there are analogous questions of coordination in relation to choice of investment: to determine what combinations and proportions of technologies in the generation capacity mix are technically feasible in meeting future load patterns. Coordination issues also include incorporation of decentralised options, along with their associated infrastructure requirements, choice of sites for wind power, to maximise diversity, and for CCS, to minimize new infrastructure costs for pumping and storage of captured CO2. This suggests a possible need for an overall investment framework, in the form of additional powers and responsibilities for the National Grid, or for a new power purchasing agency with responsibility for ensuring adequate capacity and meeting sectoral emission targets.

PART TWO. FINDING THE RIGHT PATH TO EFFECTIVE REFORM.

Part I above identified the main problems in achieving essential investment as relating to

* carbon prices, and contractual or revenue certainty for investors,
* potential inadequacies in system operation and trading linkages, as the sector moves away from conventional fossil technologies,
* the coordination and timing of investments in capacity and infrastructure, and
* adequate incentives to ensure security of supply.

OFGEM and the CCC concentrate on the first and fourth of these problems, and propose alternative approaches to reform, on a spectrum from incremental changes to existing trading arrangements, including very significant measures such as a carbon floor price, to more radical institutional changes, such as additional supplier obligations or a central agency. However it can be argued that the essential strategic choice is a binary one, between reliance on a series of possible “fixes” to correct deficiencies in existing market structures, and introduction of formal obligations to provide adequate security and meet emissions targets.

The analysis above suggests that the first approach has several deficiencies: the general problem of trying to second guess markets, the potential proliferation of complex additional rules, schemes and instruments, and failure to address the implications for market structure of fundamental technology-driven change in the sector, all of which will add to investor uncertainty and carry significantly higher risks of not delivering on the objectives.

The more radical options, for a supplier obligation or central agency, are similar, in that the first might naturally evolve into the second with suppliers creating a jointly owned agency to meet obligations, and in that both tend to imply limitations on supply competition. Such an agency offers the most certain prospect not only of securing an adequate quantum of low carbon investment, as well as supply security, but also of securing a balance of different types of capacity and load management options compatible with secure and efficient system operation, and of coordinating that with the necessary infrastructure investments.

The agency would in effect become the major purchaser and wholesaler for the sector, inviting tenders for new capacity, and coordinating its programme with associated infrastructure investment by the National Grid. With properly designed and implemented tendering procedures and contracts, this would retain both competitive pressures in building new plant and incentives for efficiency in operation. Its obligations would encourage a diverse balance of capacity types technically compatible with maintaining supplies, and higher reserve margins to ensure adequate security.

Competition in retail supply could continue but would have to focus on competition in the true supply functions of providing a billing service, rather than exploiting consumer inertia or lack of information as to the true wholesale price of electricity as a commodity.

As a purchaser and wholesaler the agency would also provide a natural channel for support to innovative solutions in the sector, including economically viable decentralised generation capacity. It would also be able to contract for existing capacity, and this would help to encourage a natural transition from existing commercial arrangements.

This part of the paper is intended to articulate in more detail how a central agency (10) might operate and how it might interact with existing market structures. The concept is not new, has frequently been proposed in other administrations, and is particularly useful in electricity systems where a “fully competitive” wholesale market based model is ruled out either on practical grounds (eg small systems, stranded assets etc) or because full competition leaves governments with an inadequate set of alternative policy instruments. In the current context we can consider relevance to low carbon and generation security issues.

Simply in terms of market mechanics, it can be designed to have important features in common with the fully competitive model. Early versions of the 1990 England and Wales privatisation model, considered in the industry negotiations but discarded in order to enhance full supply competition, were in effect based on the notion of a single buyer function exercised jointly by the twelve distribution companies. Under this scheme the twelve would forecast their own requirements and make separate contracting choices before pooling their contracts for operational purposes. One proposed scheme, the distributors’ pool, would then have had the National Grid dispatching generation plant under contract.

An alternative, close to the solution finally adopted, was based on a “generator’s pool”; this was intended to allow generators to collectively meet their scheduling and dispatch arrangements by trading through an actual or bid based (as opposed to contractual) merit order so as to maximise efficiency. The latter was eventually modified in relatively minor ways to create the actual 1990 market structure, inter alia by formally ensuring the pool was open to a wider range of participants. In an interesting parallel with some of the issues and possible solutions now emerging in relation to electricity markets, the National Grid was initially established under the joint ownership of the twelve distribution companies.

The above demonstrates that the concepts of central purchasing and organisation have not been totally alien from, indeed have at times been accepted as integral to, the development of the UK model of a competitive industry structure. The remainder of Part Two of this paper describes some of the options for how a future central agency might work in a little more detail, considers the interface with existing systems, and attempts to answer some of the more common objections raised to the concept of coordination within a market structure.

OWNERSHIP AND REGULATION

Option A. Recreation of State Owned and Vertically Integrated Industry.

This would be a traditional nationalised industry model, a publicly owned and vertically integrated monopoly, strongly resembling the old CEGB or EDF model. As such Option A is unlikely to command much support, even though it can be argued that EdF in particular had an unequalled record in driving through massive, and low carbon, changes in the primary fuel composition of the French power sector, ie just what is now required in the UK . It would necessarily be a new body, and would have to be established by statute.

Option B. A Public Enterprise with a much more limited remit.

This would be similar to Option A, except that it would not as a general rule own or operate generating plant, or control transmission or distribution.

Option C. Joint ownership by suppliers

This would be a new body, with duties and regulatory oversight of it perhaps determined by statute and/or new regulations and licence conditions, but owned jointly by the largest suppliers, the Big 6. This would be akin to the ownership model for the National Grid, as implemented with privatisation in 1990. As such it has recent historical precedent.

This body could be created from scratch by statute, or it could be created as an initiative of major suppliers. In terms of financial viability, this might have some attractions, since it would be underpinned by the main players of the sector.

Option D. Owned by and fully integrated with the National Grid.

This is a proposal that has some obvious logic in simplifying the contractual issues necessary for a system operator to exercise “command and control” on technical matters and to optimise operations, and in coordinating infrastructure requirements, thus meeting Objectives Two and Three.

Option E. Stand alone, but in private ownership.

This has the advantage of clear independence from suppliers and government, but as a privately owned body, it might be seen as excessively exposed to financial risk, and not an attractive investment. However this would depend critically on the regulatory protection and safeguards that were put in place.

Option F. A Government Department.

Few people would normally suggest this as an option, but it is a possible default option. It could be useful as a “first step” in order to push forward with important and immediate initiatives pending a proper institutional reform.

SCOPE OF ACTIVITIES AS BUYER

Option A. Minimal responsibilities confined to dealing with power purchase agreements and bulk supply tariffs or other contractual means by which suppliers purchase power, only for new low carbon plant. Operating under guidelines from government, regulator or a committee of major suppliers who would individually retain responsibility for forecasting total requirements, which could be expressed through their capacity contracts.

Option B. Responsibility for new and existing plant contracts, both low carbon and fossil; some obligation to ensure sufficient capacity to meet security and low carbon objectives, but without any monopsony rights as a “single buyer”.

Option C. Ultimately becoming the only body responsible for contracting for new capacity, with fewer or very limited exceptions, typically for large industrial consumers. Correspondingly, strongly worded duties to ensure sufficient capacity and meet carbon objectives.

OPTIONS FOR REGULATION.

This would need to reflect key concerns over performance. Rate of return issues would be relatively unimportant, since the agency itself would not “own” many assets, but the three key areas would be:

* strategic choices, eg as between nuclear, CCS, renewables and decentralised generation.
* adequate forecasting performance, although this would be less important if it operated simply by accepting contracts to provide capacity from suppliers.
* engaging in effective, transparent and non-discriminatory procurement, for example through use of competitive tendering.

Option A. Additional responsibility for OFGEM. This would be a natural extension of regulatory responsibilities for the sector.

Option B. Accountable to other parties with responsibility for delivering a low carbon outcome, eg the suppliers as joint owners, or to DECC.

Option C. Treatment simply as an arm of government. Supervision through the appropriate department – DECC, and reliance on a National Audit Office (or formerly on an Audit Commission).

CONTRACT FORMS FOR POWER PURCHASE AGREEMENTS

Contract forms are invariably subject to a great deal of detailed design and negotiation, and would vary significantly by type of plant, particularly as between intermittent plant, nuclear plant and residual fossil (with or without CCS) plant. Nevertheless there would be significant common features, such as some form of guaranteed capacity payment. There is a wealth of national and international experience in the writing and negotiation of such contracts.

We should expect the most significant negotiations to be around who bears which risks under the contract. This would follow the general principle of risk being assigned to the parties most responsible for, or best able to manage, those risks. Where market risks are concerned, it is quite unreasonable to assume that any investor in “merchant plant”, ie without a long term contract or tied customer base, will take price or volume risk when both price and volume can be affected directly by the decisions of either a single purchaser or a small group of purchasers. The purchaser or purchasers will inevitably accept this risk and place it with customers. The likely division of risks is along the following lines:

* Market price risks, ie mainly future fossil and CO2 price risk - to the single buyer, but with a strong recommendation that incentive payments might reflect current market conditions as they developed throughout the life of the contract.
* Weather (for intermittent plant) - to the single buyer
* Construction cost risk - to the plant operator
* Availability and plant performance – to the plant operator
* Demand risk, ie of capacity surplus or deficit – mainly to the single buyer

We might expect to see the following as major features of the contract with the generators successful in the tender;

* Regular capacity payment, fixed or indexed, over a contract life sufficiently long to assure reasonable prospect of securing adequate return on investment.
* kWh payment per unit generated intended to cover fuel costs or marginal costs of generation, for the types of generation where this was appropriate.
* incentive payments to reward operational performance and penalise failure, either linked directly to availability, or to output, allowing a market element linked to an SRMC-based wholesale market price (when this can be determined).
* other detailed and technology specific rules governing scheduling and dispatch arrangements, which would be specific to the type of plant or even to the individual plant.

The contract could be written to allow the purchaser the means to allow the system operator to “call” for output as part of the operator’s responsibility for short term optimisation and system stability. In the medium term this would almost certainly be necessary to replace current spot market structures.

TENDERING PROCESS AND PROCEDURES

There is a wide variety of approaches to tendering and procurement, covering all aspects from tender specification through the bidding process rules, and on to award criteria and negotiation with the successful/ preferred bidder. Variants develop in at least two important respects: the extent to which particular tenders specify technology, and the process for selecting and negotiating very large contracts, particularly where there may be only a small number of firms capable of tendering.

On specification, issues include:

* whether all tenders are potentially open to all types of plant, or with quotas for different technologies, eg nuclear, renewable, CCS, or a combination, eg set minimum quotas plus an “open” category.
* whether tenders are banded by CO2 per kWh
* the basis on which quotas are decided.
* whether tender specifications remain the same for all categories, or whether they are differentiated by category

On process a few of the important questions are:

* use of prequalification to set minimum standards for technical competence and financial viability
* how far to pre-specify contract terms in the invitation to tender, and how far to encourage innovation in contract bidding
* management of situations with small number of bidders
* treatment of price/ quality trade-offs
* parameters for negotiations with final bidder

ONWARD SALE TO SUPPLIERS

There are two main options for this, closely linked to how the agency purchases power, ie on its own responsibility or in response to capacity and energy contracts placed by suppliers:

* Sales under a multi-part bulk supply tariff, where charges would reflect the costs of supply, probably differentiated over the day and over the year, and including due account of capacity requirements and the load factors of electricity purchased
* Sales under long term contractual provisions; this would oblige the supply companies to make forecasts of their own requirements and sign contracts accordingly – sometimes known as a “contracted capacity” approach.

ANSWERING COMMON QUESTIONS AND OBJECTIONS TO AN AGENCY PURCHASER MODEL

Q. This approach means that risk, which ends up as a cost, is transferred to and has to be born by consumers, rather than by investors in a market. Surely this is unacceptable?

The fundamental components of commercial risk in the sector do not go away because they are born by investors; the latter typically charge a risk premium, or require a higher rate of return on capital to cover the risks they face. So in the end the cost of irreducible intrinsic risk within the sector will end up with the consumer by one route or another, except in circumstances where some third party, such as government, is willing to cover them.

What is important is that the sector’s structure, regulation and contracts should allow the risks to be managed as efficiently as possible. This means that where risks can be reduced and controlled by good management, this should be reflected in the incentive structures built into the commercial arrangements.

For the irreducible elements of risk which can be deemed to be outside the control of any of the actors (eg oil prices), either investors will charge a premium on cost of capital,, the cost of which will pass through to consumers, or a regulated pass through of costs will allow a lower cost of capital to be charged because the consumer. There is a strong case (in earlier notes we quoted Green) that the latter approach is more efficient and will result in lower prices.

Q. Surely this means that we are back into an era of centralised decision taking where strategic decisions are no longer left to the private sector and the competitive market?

It is possible to argue that centralised decision taking is a necessary outcome of some of the problems identified elsewhere, and that a complex non-fossil generation mix requires the imposition of constraints on what proportions of plant are technically compatible. However it is also possible to argue that most of the decisions, particularly on the quantity of plant to build, can be pushed back to the major electricity suppliers, who choose how much to contract from the central agency, under the “contracted capacity” approach.

One important purpose in proposing an agency model is to allow the introduction of some elements of central coordination into investment and operation – the third being to improve regulatory certainty for investors. However this remains consistent with incentives for innovation, and competitive market disciplines, across the main activities of proposing technical innovation in generation, choice and construction of plant, and maintenance and operations. The precise balance between a “low carbon policy” and a “market” approach can be debated, but it will need to be struck under any structure for the sector, including the current one.

Q. This could prejudice the market position of fossil plant, leading to its early closure and hence loss of security through inadequate medium term capacity?

As an assumption this makes presumptions about how markets would operate in a transitional period. However it is no different in principle from the risks already identified for fossil plant dependent on revenue earned in relatively short periods of operation and hence “price spikes”.

This concern also assumes no responsibility is assumed by suppliers for capacity adequacy.

A simple solution however would be just to allow the agency to contract with existing plant. Existing fossil generators not covered by a vertically integrated structure would welcome the opportunity to secure such contracts. If the central agency were responsible for ensuring an adequate amount of capacity, it would have every incentive to contract medium term for fossil peaking plant. Such generators however might be in competition both with each other and with new alternatives.

Q. A central buyer would get tied in with well established technology options and this would have the effect of shutting down innovation and new technologies. It would also operate against the interests of decentralised options?

It could be argued that this a far greater danger within the existing structure, with the development of a potentially cosy oligopoly of the Big 6. By contrast a central agency would almost certainly have to demonstrate to its regulatory body or sponsoring ministry that it was exploring all the most economic options. The central agency would not own significant generation assets, so it would not have a direct vested interest, and prima facie its duties to secure the most efficient and economic means of meeting security and low carbon obligations should give it an incentive to welcome innovation.

An interesting question is what responsibility a central agency might have for promoting decentralised options. It would certainly have no remit to constrain them and at a minimum would have to take account of their impact on “system” demand and load factor. However there is no reason in principle why it should not encourage decentralised solutions when these can be shown to be cost effective.

There are also much wider questions of how the power sector would develop in order to accommodate a very large aggregate transport load, which might nevertheless manifest itself as a very large number of “decentralised” units engaged for example in battery charging. The central agency might need to play a major role in shaping load patterns, for example through tariffs.

In all these areas it is likely that the agency would need to take account of the advice emanating from DECC and the Committee on Climate Change.

Q. A Central Agency will undervalue the diversity of alternative sources of capacity?

The opposite is more likely to be true, given that the agency would necessarily have an important role in ensuring that the balance of capacity types is technically compatible with maintaining supply. Even if we just take wind as an example, it is widely recognised that the wind capacity contribution, or “wind load factor”, can only be optimised if there is adequate geographical diversity in the siting of wind turbines. This is unlikely to happen without some element of central direction or coordination.

Q. What role would an agency in relation to developing the transition from oil and gas in the transport sector?

It is hard to analyse exactly how this might develop, since it is hard to predict how alternative low carbon technologies for the sector might develop. However the current front-runner, electric batteries, and its associated markets, would clearly need to be developed in a way that was consistent with the technical capability of the power sector to supply battery charging load at the right time and in the right places. Moreover the transport load, whether through batteries or through hydrogen, provides a potential solution to the problems of intermittent and inflexible generation, with a large controllable load providing the equivalent of storage or interruptibility.

This implies a significant role for the agency and/or suppliers in strategic consideration of this large load development together with alternative options for low carbon generation, and in development of the right commercial arrangements, notably tariffs, to make the system operate efficiently.

Q. A central agency would undermine the benefits obtained from supply competition?

There are two answers to this. The first is to question the extent of the benefit deriving from supply competition per se. Most of the benefits deriving from the 1990 privatisation can be attributed to the switch from coal, the advent of cheap gas, large efficiency gains in transmission and distribution driven by effective monopoly regulation, and the operation of private sector and competitive market disciplines in the generation sector, rather than from competition in supply.

Theoretical benefits of supply competition to consumers are largely undermined by supplier reliance on consumer inertia, and a lack of transparency. Green (11) inter alia has suggested that in principle supply competition delivers higher prices than a system based on contracts. The main drivers of cost efficiency in the sector will remain, in the form of competition and contractual incentives governing the construction and operation of generating plant and in distribution – the “wires business”.

The second response is simply to observe that supply competition could and should continue, but it would be forced to focus on the activities of supply, providing better customer service, and some additional services such as advice on energy efficiency.

Q. Surely central agencies tend to over forecast demand, and markets with decentralised decision taking will foster a more accurate match between supply and demand?

First there is no reason to assume this is the case, except insofar as a central agency may have incentives to provide adequate capacity that are better aligned with the relative social costs of under and over provision. This asymmetry is covered in the author’s submission to the recent OFGEM consultation and elsewhere. (12)

Second, the agency would not have any regulatory or financial incentive to increase its asset base, since it would not an owner of plant. It would have an incentive to ensure adequacy, which does not apply to any party within the current market structures.

Third, one very plausible modus operandi for forecasting and planning requirements would simply be based on supplier companies, faced with a well defined obligation to ensure capacity adequacy, who would make their own forecasts and contract accordingly.

Q. Surely we should not waste effort on time-consuming changes to the institutional structure of the sector, particularly if this involves legislation?

This is a powerful argument although we should not forget that the 1990 reforms went from inception to delivery in less than two years – a vastly more complex undertaking.

However the key point of our analysis has consistently been that the key requirements – regulatory certainty, resolving the functionality issue of a wholesale market in a post-fossil power sector, and infrastructure coordination – will remain and will have to be resolved by the sector even without institutional change. Move to a central agency can therefore just be seen as a direction in which the sector will have to move, and this paper has suggested several options, not all of which need require major legislation.

We would also note that the change of the Grid from joint ownership to independence was achieved with very few problems. Moreover the post 1990 state of joint ownership implies that this type of structure has never been seen as fundamentally at odds with an overall competitive framework.

Q. This would be blocked in Brussels on single market, competition or other grounds?

Given the extent of liberalisation and genuinely competitive markets across the EU, it would be a profound irony if the UK, which has largely pioneered competitive structures in power, were to be forbidden to make essential adjustments to maintain a sensible competitive framework for its own industry.

In practice this would only be likely to be a problem under some of the more extreme versions of a central agency, with an absolute monopoly over generation and no provisions for third party access. This could easily be managed, in consultation with the EU if necessary, in designing an approach to implementing a preferred package of measures.

We should also bear in mind that other EU countries, if they have truly competitive markets, should in principle be facing very similar questions.

CONCLUSIONS

This paper began by highlighting a number of very serious problems in the achievement of a low carbon power sector, and hence ambitious overall carbon reduction targets, with policies based on an assumption of the status quo in electricity markets. These include technical inadequacies leading to market failure and policy measures for provision of the regulatory certainty that will be necessary to underpin the large scale investments required. They also involve arguments of increasing need for coordination, notably in relation to the introduction and operation of new generation technologies.

Moving beyond piecemeal market adjustments, a number of the options proposed for the reform of markets lead, directly or indirectly, towards the concept of a coordinating agency involved in strategic and purchasing decisions. This paper has identified some of the alternative forms such an agency might take, and how it might evolve, for example, as a consequence of a supplier obligation.

Such an approach does have the potential to deal with all the problems identified, including those of technical consistency with efficient operation and regulatory certainty for investment, without compromising to any significant degree the gains that have been made since 1990 as a result of competition, private initiatives and effective regulation.

1 Meeting Carbon Budgets. The Need for a Step Change. Progress Report to Parliament from the Committee on Climate Change. October 2009.

2 This part of the paper is developed largely from the author’s response to the OFGEM consultation earlier this year and a short article prepared for Oxford Energy Forum in May 2010.

3 Retail Competition and Electricity Contracts, Green , December 2003

4 eg Hot air, gas prices and energy policy, Dieter Helm, December 2005.

5 How Wind Variability Could Change the Shape of British and Irish Electricity Markets, Poyry, July 2009

6 I am indebted to the late Dennis Anderson, among others, for this insight. See: Electricity Generation Costs and Investment Decisions, UKERC Working Paper, February 2007.

7 The old CEGB “three winters in a century” of insufficient capacity was deemed to correspond to a consumer valuation of £ X per kWh so that a penalty of the same value of £ X on suppliers’ failure would result in the same security outcome as under the CEGB regime.

8 Meeting the Aviation Target. Options for Reducing Emissions to 2050. Report from the Committee on Climate Change, December 2009.

9 The Stern review and other sources.

10 We generally and deliberately avoid the term “single buyer” simply because it has acquired a huge emotional baggage of association with vertically integrated state monopolies such as the CEGB. As this note is intended to show there are a variety of ways in which this model can be developed or refined to allow more or fewer degrees of control to the agency itself.

11 Retail Competition and Electricity Contracts, Green , December 2003

12 Reforming Uk Electricity Markets. A Purchasing Agency For Power. How should OFGEM approach the issues of security and sustainability? Rhys, Oxford Energy Forum, May 2010.

MEETING THE UK AVIATION TARGET

2010-02-22T18:00:00.004Z

A general comment on the Committee on Climate Change 2009 Report relating to emissions targets in aviation

January 2010.

First, identification of aviation as a high-growth premium use, which is potentially constrained but for which consumers would by definition pay a significant premium (albeit with some reduction in demand), creates a welfare economics case for earlier and broader use of the price mechanism to curb demand in both aviation and other sectors. This is a nettle which governments, for very obvious reasons, have so far been very reluctant to grasp. Second a “cumulative target” approach, which of course is not what we have, but which I and others have argued for quite strongly, further reinforces the case for urgency and hence earlier use of all available policy instruments, including possibly much more reflection of externalities into prices. Third, this issue is linked to the apparent paradox of divergence between the profile assumption of a rising carbon price and a profile of falling social cost (in the sense that one tonne of CO2 emitted today does more damage than one tonne in ten years time).

These points are developed in more detail below. My comments, like the report, can be viewed either in a “UK alone” or a wider context.

Implications of aviation as the premium use of the “CO2 emissions resource”

The TOR of the report were to consider the impact of a specific target for aviation – not to exceed 2005 levels by 2050. The interactions with CO2 reduction opportunities in other sectors, and policy successes or failures, are largely implicit in the terms of reference or in earlier CCC papers, and are not part of this report.

Nevertheless an immediate corollary of the findings is that the aviation sector has and will probably continue to have the highest “premium” value of any sector in use of scarce CO2 emissions. This is associated with low price elasticities, reflecting the very high value placed on travel, together with the fact that substitution by low carbon alternatives is not, with present knowledge, feasible.

Normally economists would argue that a logical consequence of this is that, if, as the report indicates, there is a prospect of needing to ration or constrain demand for aviation, then the pricing of emissions in all sectors should reflect that premium value. Otherwise we are collectively “wasting” CO2 emissions on lower value applications, for example additional or excess comfort in heating of buildings, which people collectively may not really value as highly as the travel from which they will at some stage be constrained (by prices or other means) in order to comply with overall CO2 targets.

Consumers should at least be given that choice by facing costs in other sectors that reflect the value foregone in future “rationing” of their air travel. The counter argument, that this will adversely affect the less well-off, is to a large extent neutralised by the report’s observation (also made by the aviation industry) that frequent air travel is now widely enjoyed by most or all sectors of society. The really poor can be protected from excessive heating costs by lifeline tariffs.

The cumulative target approach

I have previously argued strongly, both in evidence to the Environmental Audit Committee and via the BIEE group, that a cumulative target is significantly superior to a focus on a 2050 or any given year annual emissions target, because:

it has a far better correspondence with the science, which emphasises cumulative emissions – this is a view shared by some climate scientists.
the pathway matters; globally a backend loading of reductions adds hugely to concentrations compared to straight line reduction or more decisive early action; the arithmetic is quite dramatic.
a rational approach to international negotiations over national entitlements would have to emphasise cumulative consumption, for a whole variety of reasons – fairness, monitoring etc - so we should start thinking in these terms now.

Falling social cost

Once we accept that it is really cumulative emissions that matter, then the relevance of immediate action is emphasised, and is part of the general case for urgency. This is further reinforced by the valuation of emissions costs. Contrary to the impression sometimes created even in official publications, the value of saving a tonne of CO2 emission now exceeds that of saving a tonne in 10 years time – actually by quite a margin. I checked this with the Stern modellers and it is indeed the case for their models of economic costs – it is of course intuitively obvious if the incremental re-absorption rate is indeed very low.

The paradox is that we tend to talk about and anticipate a carbon price that rises over time (as the report does) whereas the social cost (of a given emission) is actually falling year on year. This is more than just a statistical oddity, since it gives the wrong message on urgency.

A few peripheral questions

1. There is a lot of discussion of improvements in technical efficiency. I wondered if there is any examination, anywhere, of the possibility of a serious re-optimisation for speed/fuel trade-offs in a low carbon world – possibly taking into account how new generation aircraft would be designed in such a world. Speed is such a big factor in road fuel consumption that it might make sense to consider it in an aviation context as well.

2. I noted the assessments on price elasticity of demand for travel, and I wondered whether the price elasticity might actually be very different at different points on the demand curve. [What would the effect be for example of an aviation fuel tax at similar levels to road fuel tax? It would at least double the price of short haul flights!] In other words would a rational pricing approach for aviation fuel change both the nature of the debate and the parameters of demand for air travel?

3. There are also some interesting issues for an international framework, which militate against national targets. For example should particular economies have more or less than their pro rata share of flights ? How should responsibility for flights properly be apportioned between origins and destinations ? If Florida markets long-haul holidays in the UK, should the US be partly responsible for the carbon consequences of dragging British holiday makers away from European destinations? [This is akin to arguments over whether consumer nations of the West have responsibility for carbon content of Chinese manufactures.]

Topical Issues of Energy and Climate Change

2009-04-07T23:34:00.007+01:00

The financial crisis. A positive for action on climate change or a catastrophe?

Will the urgent drive out the important?

The slowdown in the global economy will slow the growth of energy consumption and give some limited relief to the apparently inexorable rise in global emissions. The consequential reduction in the need for electrical capacity should also cause the UK government to pause before permitting a go-ahead with a new coal burning plant at Kingsnorth.

But will engineering the economics of recovery also deflect attention from the equally urgent and arguably even more important long term tasks of limiting man-made climate change and avoiding catastrophic long term consequences? The tribulations of recession are real, large and immediate, but they may seem small in comparison with the costs that have to be borne if we fail to limit man-made climate change.The answer to this challenge is surely to make the best possible use of the opportunities that arise. For countries that have decided or are able to contribute a fiscal stimulus, expenditure can be steered to a high priority on CO2 reducing projects. Countries that are fiscally challenged and are forced to raise taxes should concentrate on "green" taxes. Properly designed, such taxes should be seen as reducing an economic distortion, encouraging the wasteful use of energy, and hence as more beneficial than many other taxes.

An ambiguous role for markets and prices

There is a paradox in the approach of many commentators and economists to energy policy for climate change, and this has been reflected in the approach taken by the UK government.

On the one hand, the approach is to promote the role of markets and market derived prices in promoting large scale low carbon investments, where they are patently struggling to deliver, often because of well identified market failures including weaknesses in the design of the market structures. xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx
At the same time policy is usually excessively cautious about use of the price mechanism in approaches which would ensure that the social costs of carbon, the "externalities", would be more fully reflected into consumer prices, a measure which, however unpopular, is demonstrably capable of having an effect on energy consumption and waste.

The UK led the way in the reform of new market structures for the energy utilities. Competitive market structures have many advantages over nationalised monopolies, but prima facie they also severely limit the policy instruments open to Government. The question we now have to face is whether those market structures are still fit for purpose in a world where an almost overriding policy importance should attach to creating an energy sector compatible with a global climate change agenda. Two facts are abundantly clear.

when fundamental security and stability issues are at stake, as is the case with climate issues, Governments can no more stand aside from energy markets than they can from the failures of financial markets

some energy markets, including the critically important power generation sector, have built-in elements of market failure in respects that are particularly serious in trying to promote investment in low carbon futures; they need reform, and intervention may be required to achieve necessary and targeted reductions

This site

A number of these and other issues are addressed in more depth in short papers and essays on this site. The author has no affiliations to bodies with vested interests in the energy sector, or with lobbying or special interest groups. He is an economist with over three decades experience of addressing energy and environmental policy issues in the UK, Europe and in developing countries, covering every facet of the energy industries from the design of new market structures and regulatory institutions, through financial, tariff and pricing matters, cost benefit analysis and project appraisal, to detailed research into consumer attitudes and behaviour.

Markets and prices or a regulatory approach

2009-04-07T19:47:00.006+01:00

This posting addresses some fundamental questions about the respective roles of regulatory and other policy measures, as against using prices as "market" signals to influence consumer behaviour towards reducing emissions

Earlier papers have touched on market failure in the power sector, and argued against undue reliance on market mechanisms in inducing major low carbon investment, and especially in decarbonising electricity generation. These arguments pointed to the need for policy interventions, such as direct contracting through a central purchaser or a floor price for CO2, to ensure some of the major investments that are a necessary condition for meeting ambitious low carbon targets. The focus however has been on large scale investments. This paper discusses some of the equally complex issues of balance between market-based approaches and regulatory or interventionist approaches in getting reductions in CO2 emissions through changes in the requirements or behaviours of millions of individual consumers. The case for a market approach, in the sense of relying on price signals to achieve emission reductions, is much stronger for the heating of buildings at the micro or consumer end than it is as a means of influencing large scale technology investments. Paradoxically this is the arena where governments are least willing to contemplate effective action through prices that reflect the social costs and long term damage associated with energy consumption.

The essential distinctions, in terms of policy, can be drawn between three types of instrument:

· Using higher energy prices as an instrument of policy, whether this is done explicitly via market mechanisms or through taxes justified in terms of the external costs of CO2.
· Regulation through the adoption of standards, mandatory requirements and penal sanctions for non-compliance, specifically targeted at the way energy is used.
· Indirect approaches, where lower energy consumption and emissions are important but incidental consequences of a different choice of policies that prima facie have a wider remit, such as general economic and fiscal policy, or housing and planning policies.

Market type approaches. The price mechanism as an instrument of policy.

The most obvious manifestation of a market approach is simply to find ways to allow and encourage the reflection into the prices consumers pay for fuel the very large costs of the damage associated with CO2 emissions. Policy intervention then needs to consist essentially of doing no more than setting some ground rules, based either on tradable emissions rights designed to achieve a given CO2 reduction or on a carbon tax that sufficiently reflects the cost of emissions and is calibrated to result in the same reduction. A particular form of market based policy is personal tradable quotas, which offset some of the redistributive concerns with a market approach but with high transactions costs of administrative complexity and enforcement. In each of these cases however the instrument for CO2 reduction is the price of using a fossil-based fuel and its associated emission, and it operates directly on the consumer who has to pay that price.

Market solutions have the advantage of providing a policy solution that is theoretically optimal in terms of economic efficiency, but this is only true if the full costs can be applied and translated into prices. The reality is that even in the major wholesale markets represented by the European emissions trading scheme (the EU ETS), CO2 prices fall a long way short both of the actual social costs and of the price levels that will drive down emissions and ensure low carbon futures. Moreover there are frequently institutional or other factors, such as the absence of international agreements or of adequate metering, that further inhibit a national market based approach or distort the translation of price signals developed in wholesale markets into prices to final consumers.

One can add to these factors the political difficulty, consumer resistance and possible economic dislocations of introducing dramatic changes in price relativities through major shifts in energy prices. It becomes clear that the immediate prospects for pure market solutions, based solely on the use of prices as an instrument to force reduced emissions, may be limited and insufficient on their own to achieve the reductions required.

However the fact that complete solution of the problem by market mechanisms currently seems remote does not eliminate the benefits of using prices or taxes as one of the major instruments of policy. The price mechanism has several well-known and powerful advantages, including the following:

· A strong price signal discourages actual waste and will eliminate or substantially reduce the continued use of energy for those purposes which are wasteful (the infamous patio heater) or least highly valued; these purposes will differ between households but might include, for example, the extra degree of convenience implied by heating an empty house or room, or the extra energy required for a one degree rise in internal temperature.

· It induces changes in behaviour that are essentially voluntary responses and are free of additional costs to the individual beyond the voluntary foregoing of the benefits of the extra energy that would have been used. Some of these, such as reducing internal temperatures, can be fast acting.

· It encourages market and individual innovation; individuals will find more innovative approaches to restoring their feelings of household personal comfort than can be hypothesised by regulators or planners, who tend to assume patterns of behaviour, and take heating levels or comfort standards as a given.

· It encourages lower energy lifestyle choices; it is hard to argue that the rapid growth in fuel intensive “weekending” flights from the UK would have developed on the back of aviation fuel taxed on the same basis as road transport.

· It will for most people have an impact on personal investment choices, eg on a new car[1], or a new domestic cooker, that have significant fuel consumption consequences; and it will promote the lower carbon alternatives.

· It respects and does not pre-empt the choices of individual consumers, for example in occasional low-mileage use of a vintage car or a limousine with very poor fuel consumption, which might be prohibited under a simplistic regulatory approach.

· Market based approaches generally have lower transactions/ administrative/ enforcement costs, subject only to provisos that some forms of market approach, such as tradeable personal quotas, do involve complex measurement and administrative requirements.

The effect of market measures based around price as the driving mechanism is greater the more price elastic the demand; price elasticities for the use of energy to heat buildings, for example, are likely to be significant. It is least, and price responsiveness lowest, when energy use is an essential complement to a highly valued activity such as personal mobility, or the use of typical domestic electronic equipment, but an insignificant element in total cost.

Regulatory instruments

The alternatives to market or price driven instruments include regulation and other indirect approaches to reducing energy consumption, including subsidies to investment. Simple relatively uncontroversial examples are building regulations, compulsory appliance labelling in terms of energy efficiency ratings, insistence on gas condensing boilers as replacement in domestic heating systems, and small-scale subsidies to install loft insulation. More controversial but still relatively low cost forms of regulation are the recent plans to end sale of traditional light bulbs, or proposals for speed limits introduced for fuel saving rather than road safety reasons. Much more intrusive forms of regulation have been considered however. For example a recent report by Brenda Boardman of the Oxford University Environmental Change Institute [2] has recommended a mandatory approach to the achievement of a low energy housing stock, including inter alia a proposal for legal prohibitions on sale or rent of properties not meeting very demanding insulation standards.

The limiting constraints on regulatory or associated subsidy approaches are that:

· It implies transaction and enforcement costs; local authority building inspection and enforcement for the existing housing stock, for example, would require an order of magnitude expansion of professionally qualified staff.
· Regulation may sometimes impose unnecessarily expensive and inefficient solutions on the consumer, for example in the conversion of equipment which is rarely used.
· It may lead to unnecessary or unproductive expenditure in subsidies; eg on insulation of second or holiday homes that are used only in summer.
· Expenditure that might in any case have been undertaken voluntarily is subsidised from public funds; so the public expenditure brings no additional value.
· It may destroy value through unnecessary destruction of particular parts of the housing stock.
· It ignores the preferences that consumers, if confronted with the true costs of their energy consuming choices, might choose to make, forcing them instead to accept an authoritarian view of how they should manage their affairs
But there are also many examples where a case can be made for regulatory and mandatory or interventionist approaches, and the factors disposing towards this approach are the following:

· There are very low collateral costs to either consumer or society at large in complying; this is most obviously the case in installing low cost basic insulation, or in building standards for new property.
· Low cost changes give disproportionately large savings within a particular sector of energy consumption; light bulbs, or the standby consumption of appliances, are a good example.
· The regulation is dealing with deficiencies in or lack of information, which would help to reinforce market signals; appliance labelling helps market or price signals work.
· Regulation is necessary to deal with a specific market failure; for example the economics of combined heat power (CHP) is usually critically dependent on the scale and density of the heat load scale; mandatory membership of new or retrofitted CHP might be a precondition of a scheme going ahead.
· Dealing with public goods, where the price mechanism is ineffective because the mechanisms of choice are unclear; heating of offices and public buildings is an example.
· The main obstacle to best practice is inertia or lack of information rather than consumer hostility; simple loft insulation is a good example.
· Enforcement is feasible and acceptable and there are low transaction costs.

Indirect Policies

Policies in wholly different domains can have profound implications for the demand for energy and the way it is consumed, and this is particularly the case in housing and transport.
It is very clear that the UK demand for housing has been inflated in recent decades by distortions, real or perceived, in financial markets. The number of households, and the size of properties, is a major driver of domestic energy demand, particularly for space heating. Several dimensions to this can be identified. One is the phenomenon of older people, whose children have left home, continuing to occupy large properties, sometimes in excess of their own preferred requirements, because property has been seen as the only “secure” investment. More generally the belief in the investment virtues of housing has undoubtedly expanded the housing stock and the number of households above its natural level, with large consequences.

The bold measure of introducing road pricing in London was undertaken primarily to ease congestion and improve journey times, but will nevertheless have had a consequential impact in reducing CO2 emissions, since congestion is a major cause of less efficient fuel consumption. However in a poorly analysed and ill-considered attempt to use the same policy instrument as a further driver for CO2 emission reduction, vehicles with lower emissions were exempted from the congestion charge, thus losing some of the lower congestion benefits and increasing CO2 emissions. Encouraging more lower emission vehicles into London will not only have added the still considerable emissions of those vehicles, but also increased the emissions of all the other less efficient vehicles on the road.

Heating of Domestic Buildings

Applying some of these ideas to the question of how to achieve reductions in CO2 emissions associated with domestic heating, there are a number of issues to cover. Two contrasting approaches along a spectrum from relying solely on price increases or taxation to lower use, to assuming that reductions can be achieved solely by mandating and subsidising technical means to change the energy efficiency of the housing stock.

First there are clear a priori arguments for using fuel prices at least as one of the instruments of policy, in order to limit wasteful or less highly valued energy consumption. The argument starts from the presumption of a significant responsiveness of demand, and the evidence that there have been significant increases in both aggregate fuel consumptions and internal home temperatures over a period of falling real prices. Look at domestic electricity demand since 1990.

The impact on household budgets of higher energy prices would be lessened by measures to improve standards of household energy efficiency, which higher prices would encourage, but the reality is that higher prices would be designed to change behaviour and reduce intrinsic demand as well as to encourage a more energy efficient housing stock. Minor changes in desired heat have dramatic effect on consumption. Risk that without price signals higher insulation is absorbed in higher desired temperatures.

A frequent argument raised against the use of prices in this way is the interaction with income inequality, and the real concern with fuel poverty. However it is hard to accept that a problem which starts from income inequality can only be solved by continuing the major market distortion of refusing to price at least some of the external social cost of CO2 into consumer prices. In any case the poverty issue can be addressed in several other ways. The most obvious way is to address income inequality directly and reduce it. However the simplest solution is the introduction of so-called “lifeline” or “rising rate” block tariffs, where each household gets a ration of low-priced energy, but pays a full price above that level.

The main alternative is the intensification of a mandatory approach well beyond the low-key measures already in place. The Boardman/ Oxford ECI report provides some examples in its recommendations. An interesting and explicit feature of Boardman’s analysis has been the identification of the “large empty nest” syndrome (parents with large houses whose children have left home) as responsible, through over-occupancy, not only for a housing shortage but also for an implicit higher per capita energy consumption in larger houses. An obvious but very intrusive regulatory remedy would be tax or other measures to limit home size.

The Boardman/ ECI second major concern is with the very low rate of turnover of the UK housing stock, and they propose a fairly draconian regime to enforce the adoption of very high standards of insulation, without which the owner would be unable legally to sell or rent the property. Implicitly this would render large parts of the existing housing stock unusable, forcing a much faster rate of turnover and new house build. The resource and financial implications of this approach are potentially very substantial, which raises very serious questions of whether or not the same or superior results could be achieved through intelligent application of the “market” instrument of higher prices.

The third area, of indirect policies, is also of particular relevance to housing. It is now becoming clear, for example, that one of the potentially damaging consequences of the asset bubbles created by the absurd over-leveraging of financial markets has been an inflation of the demand for housing, particularly by inflating “investment demand” and house prices, and contributing to the “large empty nest” syndrome. A positive side-effect of the financial crisis may well be that per capita heated living space, a major driver of energy demand for heating, is reduced.

The most appropriate conclusions to draw on policy towards a low carbon future for domestic heating are that:

there is clearly a need for a balanced mix of policies, including both mandatory elements where these are not excessively costly or intrusive, and
attention to the indirect consequences of other policies, including economic policies which distort housing demand, but also
a willingness to use prices as signals to drive changes in consumer behaviour

Road Transport

Road transport presents a quite different economic profile. Individual consumer demand for fuel for transport is highly contingent on where people have chosen to live and the cars they have chosen to drive. The short run elasticity of demand is likely to be very low or negligible and the responsiveness of consumption to emissions pricing will therefore be low. Road transport is already very highly taxed and while European tax levels may have delivered more compact and efficient cars they will not on their own deliver sustainable levels of demand for fossil-based fuels in the private transport market.

The only viable long term solutions for transport, which accounts for about 30 % of emissions, depend on technical change, most probably through the introduction of electric vehicles. However in the interim it is still worthwhile to look for measures which will generate substantial savings in the short and medium term.

Two obvious and well-known contributors to higher road transport emissions are speed and road congestion. This suggests two particular candidate policies in addition to the battery of possible regulations for more efficient vehicles:

lower motorway speed limits and/or stricter and more comprehensive enforcement of existing limits.
road pricing aimed specifically at congestion, and not entangled, like the current London congestion charge, with an ill-conceived strategy to mould the composition of the local vehicle fleet.

[1] It is no coincidence that the US with low gasoline prices became the home of the gas guzzler while other countries became leaders in compact and fuel efficient cars.
[2] Home Truths; a low carbon strategy to reduce UK housing emissions by 80% by 2050; a research report for the Cooperative Bank and Friends of the Earth. Brenda Boardman, November 2007

Questions for Combined Heat Power.

2009-04-04T14:25:00.006+01:00

Does it fit with a low carbon future?

The attraction of combined heat and power (CHP) is its potential to reduce the apparent waste of energy involved in electricity production. It is almost invariably associated with fossil fuel generation but in principle applies to other forms of generation with a primary heat source, notably nuclear power. The difficulty with its widespread adoption has always been associated with the cost of getting the waste heat to places where it might be usefully employed, typically to provide household space and water heating in high density urban environments.

There are high capital costs, and also potential heat loss and pumping costs associated with the creation of large diameter pipe networks and the movement of hot water over significant distances. There are also high installation costs associated with retro-fitting into established urban environments The ideal heat load for CHP is a compact area, such as high density housing, although retro-fitting in individual buildings will still have significant extra costs, and the economics of potential schemes may depend on high rates of take-up among householders.

Most obviously, this is true of large power stations remote from centres of population. Isolation works against CHP because of the capital cost and heat loss involved in heat distribution over a rural or dispersed area. Proponents of CHP have therefore often tended to argue against large centralised power generation and in favour of smaller local or neighbourhood electricity generation. More recently there have been attempts to promote much smaller scale forms of CHP, even at the level of the individual household.

This note addresses some of the questions that need to be asked in order to determine whether or how big a role CHP might play in addressing the problems of getting to a low carbon future.

Measures of effectiveness

Examination of the contribution of CHP in the context of carbon emissions policy tends to use three measures – energy efficiency, carbon efficiency, and economic efficiency. They may sometimes point in the same direction, but they are in reality very different concepts.

· Energy or thermal efficiency in this context is usually defined in technical terms – the percentage of the energy content of the primary energy source that is not “lost” when coal or heavy fuel oil is converted into a high value output, electricity, and a not very useful “wasted” output, large quantities of lukewarm water.

· Carbon efficiency reflects the output of electricity for a given CO2 emission; it will differ from energy efficiency according to the type of fuel in use. For example heat input from a sustainable source, such as biomass, may be more carbon efficient than gas-fired generation, even if it is input to a process that is less energy efficient.

· Economic efficiency should in principle trump and incorporate both these measures, provided energy costs and the full cost of CO2 emissions are correctly valued. It should in this context take into account both the value of the energy produced, with electricity production valued much more highly than hot water for example, and the social costs of CO2 and the reality that we have to pursue policies that meet carbon targets.

The reality for CHP has indeed been that the economic measure predominates. One incidental feature of CHP very relevant to its economics is that, in order to produce water at a sufficiently high temperature to be of any practical use, it may be necessary to scale down the more valuable electricity production from a CHP plant in order for the by-product of waste heat to have a potential market. The most efficient mode of operation for electricity production, taken by itself, leaves a residual waste heat that has very little potential economic value or practical use. The mode of operation is therefore itself an economic trade-off between high value electricity and lower value low grade heat.

The other big practical and economic issues for CHP are first the capital costs, particularly where retrofitting is involved, and second the balancing of power and heat loads within the relevant consumer base. Of course these problems can be overcome, for example by using national and local interconnection to spill power or receive back-up, but this is inevitably at some cost to economic viability.

Increasing efficiencies in power generation and domestic boilers

Since the 1970s two major developments have been the extensive introduction of combined cycle gas turbine plant which operates at much higher thermal/energy efficiencies than traditional thermal generation plant, and more recently the introduction of condensing gas boilers, with efficiencies of 80-90%. This clearly has the potential to reduce substantially, even if it does not entirely eliminate, the energy efficiency advantages of CHP.

Carbon Efficiency. Compatability of CHP with effective policy for meeting CO2 targets.
CHP first came to major prominence in energy policy debates after the first oil crisis of the 1970s. Notwithstanding the fact that CHP has not achieved a substantial impact in the decades since then, we might expect that the importance attaching to CO2 emission reduction would now place a huge premium on energy efficiency, and open up new opportunities for CHP. In addition power generation technology has developed and arguments have been put forward for much smaller scale forms of CHP, operating at a highly localised or even household level, obviating some of the issues associated with large capital investment in CHP “hot water” distribution networks.

However other technologies have also moved on, and CHP is in competition, within the context of low carbon energy policies, with a number of alternatives. These include not only sources of power generation that do not lend themselves to CHP, such as nuclear[1] or most forms of renewable energy, but also with the various approaches to carbon capture and storage (CCS).
CCS is of particular importance to the future of CHP in relation to fossil plant. Since it is evident (one can cite the recent Committee on Climate Change report and other sources) that the power sector has to become virtually carbon free, it follows that CHP can only represent a major component of a realistic long term strategy if it is also associated with carbon capture. However a major issue for CCS is to establish a new infrastructure of pipe network to collect and transport the captured CO2 and deliver it to geologically suitable storage sites, including oilfields. This points initially at least to the concentration of CCS on major generation sites and militates against smaller CHP schemes simply on the grounds of excessive capital cost. Decentralised small scale CHP runs into the problem of a big CO2 collection network, unless it is based on a renewable heat source[2], such as biomass or biofuel[3].

Questions for CHP

It follows from the above that the most obvious questions to be addressed in determining the potential contribution of CHP to the future energy balance are therefore the following:

1. How significant are the energy efficiency savings associated with CHP considered to be, given the very large improvements that have occurred in recent decades both in power generation technology (CCGT) and in domestic boilers? This latter is obviously particularly important in considering the potential of smaller scale CHP designed to meet the power and heat requirements of domestic consumers.

2. In relation to building or retro-fitting CHP schemes around coal-fired plant, or other large thermal plant, has there been any change in assessment of the capital costs of the necessary networks for distribution of the waste heat? Hitherto retrofitting has rarely if ever been seen as economically or commercially viable, primarily because of capital costs, but much higher valuations attaching to CO2, particularly if these reflect Stern’s social cost of carbon rather than the inadequate numbers emerging from current carbon trading schemes, might alter the balance.

3. Any viable long term scheme for CHP associated with conventional fossil plant must require that it be associated with carbon capture. Given the cost and feasibility of building CO2 gathering networks, the emphasis may well be on fitting carbon capture to the largest point sources of power generation. To what extent will this limit the options, and hence the potential aggregate contribution, particularly for smaller scale CHP schemes?

4. Load balancing, between the electrical load and the demand for space and water heating that can be supplied through CHP, is likely to impact on the pattern of loads placed on local networks and the national grid. Given that some analysis already anticipates significant potential issues for the grid arising from the intermittency of some renewables, will CHP create any new problems for power networks?

17.03.2009/CHP notes

[1] It is conventional to assume that nuclear stations will be remote and that concerns over technical features of operation will also work against nuclear CHP. This conventional assumption perhaps deserves to be examined, but is probably correct.
[2] In fact the carbon efficiency for biomass is also substantially increased if the CO2 generated can be separated and “”fixed”. Purely in relation to carbon efficiency an electricity only generating plant based on a renewable heat source, located close to a CO2 gathering network, and with the potential for carbon capture, will be superior to a CHP scheme without carbon capture.
[3] One interesting development is the possibility of new "biofuel" crops suitable for marginal, ie non-agricultural, land.

Do we need Kingsnorth to keep the lights on?

2008-10-15T11:26:00.000+01:00

John Rhys.

October 2008

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

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

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

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

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

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

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

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

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

2. Are there no other sources of incremental capacity?

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

- any residual mothballed plant

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

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

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

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

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

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

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

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

- pricing and tariff strategies targeted to reduce peak loads

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

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

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

4. Even assuming the worst case, where there are blackouts and rota disconnections, how do the estimated social costs compare to the estimated social costs of emissions?

Obviously a lot of assumptions go into this, such as the life of Kingsnorth as a baseload station, whether and at what point it would be fitted with carbon capture, how severe the shortages might be, and so on. But just to give a feel for orders of magnitude:

Social cost of emissions. A 2 GW baseload power station operating at 85% load factor might on average consume about 6 million tonnes of coal a year. This equates to about 15 million tonnes of CO2, or 300 million tonnes over a 20 year life operating at baseload without CCS. Valuing the cost of the latter at a comparatively modest (ie only a little above Stern Review) figure of £ 80 per tonne, this would imply an annual cost of £ 1.2 billion, £ 6 billion over 5 years (say), the presumed period when Kingsnorth fills a gap, and a lifetime cost of £ 24 billion.[2]

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

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

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

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

Footnotes

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

Will Markets Deliver Low Carbon Power Generation?

2008-10-02T16:18:00.001+01:00

John Rhys

October 2008

xxx

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

The genesis of this article stems from discussions within the BIEE Climate Change Policy Group, and with Mike Parker and Gordon Mackerron of the University of Sussex. It is shortly to be published by the University of Sussex Energy Group in their Electronic Working Paper series.

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

1. Defining the Question

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

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

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

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

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

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

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

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

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

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

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

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

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

2. The 1990 market structure

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

2.1. Main objectives in designing the 1990 market.

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

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

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

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

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

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

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

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

- A political imperative to create structures which allowed retail competition

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

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

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

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

2.2. Merit order.

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

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

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

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

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

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

2.3. Adaptation to meet technical stability

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

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

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

2.4. Reward for capacity

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

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

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

2.5. Competitive structure

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

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

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

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

3. Subsequent development of the market

3.1. Fuel choice and the effect on prices

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

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

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

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

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

3.2. Market Rules

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

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

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

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

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

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

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

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

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

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

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

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

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

3.3. Competitive structure

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

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

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

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

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

4. Future factors

4.1. Accommodation of carbon markets

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

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

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

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

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

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

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

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

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

4.3. A more electric economy

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

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

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

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

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

5. Analysis

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

5.1. Operational security and efficiency

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

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

5.2. Correct signals for new investment

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

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

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

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

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

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

5.3. The Impact of the EU Emissions Trading Scheme

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

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

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

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

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

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

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

5.4. Delivery of price signals for allocative efficiency

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

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

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

5.5. Unfair competition

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

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

5.6. Parties capable of contracting

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

6. Conclusions

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

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

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

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

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

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

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

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

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

[1] Meeting the Energy Challenge, A White Paper on Energy, Department of Trade and Industry, May 2007
[2] Sir Nicholas Stern ,The Stern Review on the Economics of Climate Change, HM Treasury, October 2006,
[3] Paul L Joskow, “Why do we need electricity retailers? Or, can you get it cheaper wholesale?”, Center for Energy and Environmental Policy Research, Massachusetts Institute of Technology, revised discussion draft, 13 January 2000.
[4] John Rhys Mike Parker and Gordon Mackerron, Shaping Carbon Budgets, , January 2008,and related papers on the site Bringing Urgency Into UK Climate Change Policy. http://ccpolicygroup.blogspot.com/ This is a BIEE linked site.
[5] Dieter Helm, Hot air, gas prices and energy policy, December 2005. http://www.blogger.com/www.dieterhelm.co.uk/publications/December05.pdf
[6] Graham Shuttleworth, Pay as Bid Balancing Market Runs into Trouble in the UK, NERA Energy Regulation Insights, April 2004. http://www.nera.com/NewsletterIssue/ERI_Issue%2020_April%202004-updated_4.2006.pdf
[7] Dennis Anderson, Policies for a Low Carbon UK Energy System, August 2007, Findings of a Study for the IPPR

The Social Cost of Carbon

2008-06-26T19:44:00.001+01:00

OBSERVATIONS ON THE TIME PROFILE FOR THE SOCIAL COST OF CARBON.

John Rhys.
April 2008.

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

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

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

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

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

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

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

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

Question. Suppose we have a large store containing thousands of tonnes of CO2, held under pressure in large corroding metal vessels. Technical experts have advised me that there is no means of permanently sealing the vessels, but that I can at some expense treat the seals of the vessels in a way that will prolong their expected life from 5 years to 20 years. What should I do, given an objective of minimising adverse climate impact?

Answer. According to an analysis of social and environmental costs which tells us that later emissions are more damaging, the answer is obvious. We should be prepared to spend money not on reinforcing the vessels, but on breaking them open immediately, since the social cost will be significantly higher in 5 years time and even more so in 20 years time.

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

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

Interpreting the Science on Re-absorption

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

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

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

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

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

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

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

Results from modelling of economic impacts

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

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

Conclusions

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

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

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

Footnotes

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

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

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

[4] http://www.ipcc.ch/pdf/assessment-report/ar4/wg1/ar4-wg1-faqs.pdf; FAQ 10.3, for example; and numerous other IPCC sources

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

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

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

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

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

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

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

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

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

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

[7] Appendix 3. Research on behalf of DEFRA carried out by AEA Technology et al (2005). Authors Watkiss et al. Available at http://www.defra.gov.uk/environment/climatechange/research/carboncost/pdf/aeat-scc-report.pdf

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

COMMENTS ON DRAFT CLIMATE CHANGE BILL.

2008-03-30T18:23:00.002+01:00

John Rhys
May 2007

The following notes were prepared as a basis for written evidence to be submitted to the Joint Committee on the Draft Climate Change Bill in May 2007. The comments are addressed to the themes of the Committee’s inquiry.

1. The main aims and purposes of the Bill and why it is needed.

A recent BIEE Climate Change Policy Group paper[2] summarized the case for urgency of action on climate change. The following extract provides a neat summary of at least part of the case for action in relation to the institutional framework.

Policy has over the last two decades been set in a “liberalised market framework”, with a mixture of competitive markets and regulation, and many economists and politicians continue to rely exclusively on market driven solutions. While recognising the fundamental importance and powerful advantages of markets, we believe the current framework, unamended, is unlikely to be capable of promoting large scale investments in new low carbon technologies or fundamental long-term change in complex UK (or for that matter international) energy systems, since:

· “Climate change represents the greatest market failure the world has seen” (Stern).

· “Carbon valuation”, to internalise the costs of CO2, is not embedded in the economic system, and it has so far proved very difficult to implement in a manner that will give confidence to investors in long term assets, eg in power generation, by ensuring that the reward for carbon reduction will remain over the life of the asset.

· R&D investment may be particularly susceptible to market failure problems in industries where it is difficult for individual firms to capture the benefits. The energy sector has been notable for low and declining R&D in recent years, and the potential for market failure is enhanced by the absence of a clear and stable framework to put a value on the benefit of “low carbon”.

· Solutions based on the creation of market structures, such as for the trading of carbon, must play a hugely important role; but, to be effective, they will require not only Government endorsed targets for emission reduction, but also carefully designed policy interventions and regulatory supervision.

· In a number of cases decisions on infrastructure may have a profound effect on the economic and commercial choices of preferred technology, eg on the form of the electricity grid or on a pipe network for CO2 capture and disposal, requiring some degree of centralised decision making.

All these factors suggest the need for some amendment to existing regulatory and competitive market structures. Indeed small-scale incremental adjustments to existing market and institutional frameworks are unlikely to suffice and additional policy instruments are likely to be required.”

Club of Rome. Lord Lawson, in his recent evidence to the Committee, drew parallels with the “alarmist” projections of the Club of Rome. The failure to materialise of these early prophecies of doom led, unsurprisingly, to their characterisation as neo-Malthusian fallacies. However global warming in relation to man-made climate change has one economic characteristic which destroys any possible analogy. In the main the Club of Rome addressed the subject of natural resources, such as oil and minerals, for which actual or potential shortages are translated rapidly into price movements. Higher prices can and do induce substitution and both supply and demand responses. However when the scarce resource is a common good, like many aspects of what we choose to call “environment”, it does not, absent intervention, have a market price and users do not have to bear or respond to the external costs of their own consumption. The normal checks and balances of prices related to costs, and of supply and demand response, simply do not operate. In the absence of mechanisms to internalise the externalities of excess usage of an environmental resource, in essence what CO2 emissions are, there is nothing to curb demand or increase supply.

2. Appropriate to legislate? Balance between compulsory and voluntary action.

We should recall that “voluntary” action on energy conservation has been a feature of the energy policy landscape since the mid-1970s’ and that its achievements have been at best limited and partly undermined, perhaps, by falling real energy prices. Given the urgency that now attaches to real action to reduce emissions, it is clear that a new framework is required, and that legislation is likely to be necessary for many of the market based or regulatory initiatives that will be required. Climate change legislation also provides an opportunity to inject momentum into CO2 policy.

The balances that will need to be found in the future are between “compulsory” and “voluntary” measures, when so described in relation to individual choices by consumers or other economic actors. The most important distinction that can be drawn is between “voluntary” action in response to market pressures and new market signals, admittedly helped and reinforced by public education, and “compulsory” measures based on regulation, relevant examples of which might be building standards, planning requirements or motorway speed limits.
While there may be a general preference for “market” solutions, and the scope for new markets is covered in the Bill, it is likely that there will be a significant dimension of “regulation” required in future policy. One question to address therefore is whether possible future measures in respect of regulation are adequately covered by the Bill.

3. Inclusion of GHG; and the adequacy of the proposed 60% reduction.

In principle, and in the longer term, it will be important to move to a broader and more comprehensive system of greenhouse gas control. This should therefore be kept under review. The practical case for maintaining the immediate focus on CO2 is that it allows earlier progress to be made on the largest single element of the problem. To wait on resolution of the scientific, technical and political questions associated with a full GHG system might result in unnecessary delay to essential action that can be taken now.

The position on the adequacy of a 60% target is analogous, in that

- the most recent scientific consensus[3] indicates the need to aim for atmospheric concentrations of CO2 of less than 550 ppm

- with the lack of progress in reducing emissions over the last decade there are real doubts[4] as to whether a 60% target would deliver cumulative emission reductions adequate to achieve even the less demanding target of 550 ppm in 2050.

- the BIEE Climate Change Policy Group has expressed the view that “we should at least consider the implications of a more challenging 80% target, as well as the more conservative 60% UK reduction considered hitherto”.

The essential issue is that a limit based on an 80% reduction would be a further major reduction in carbon emissions, implying only half the allowable emissions of CO2 in 2050 compared with a 60 % reduction. As such it almost certainly implies significantly higher adjustment costs, and is also likely to imply measures which would impinge on the nearer term targets. It would therefore be harder to justify an 80 % reduction as a UK unilateral measure at this juncture.
Thus, if risks of delay to the passage of the Bill are to be avoided, the most appropriate compromise or practical approach is to proceed for the time being with limits based on the 60% target as outlined in the Bill, but to recognise the probability that the UK will wish or indeed need to move to a tighter limit in the future, most probably as part of a coordinated international response. This does not appear to call for any obvious major adjustments to the Bill, other than to ensure that both Government departments, in their monitoring and policy development, and the Committee on Climate Change, in its advisory role, do take into account the implications of tighter international objectives as exemplified by an 80% path.

Finally it is important that CO2 targets align with the true underlying objective. This is to minimise cumulative emissions, not to achieve a particular level by a given date. A target such as 60% reduction in annual emissions by 2050 may be a useful indicator of what is required, but it should not obscure the primary objective, reinforced by Stern, of keeping cumulative emissions within “safe” limits. Exclusive preoccupation with ultimate 2050 targets ignores the importance of the path of emissions reduction both in determining ultimate emissions and the “exemplary value” of UK action. There is therefore a case for expressing targets in terms of cumulative emissions.

4. What difficulties face the Government in controlling UK carbon?

The carbon budgeting system, and its associated accountability and monitoring arrangements, should facilitate public scrutiny of the whole corpus of policies and measures concerned with the low carbon issue. Effective accountability will need to consider not only recent emissions against budget but also those steps being taken to create the conditions for necessary long term technological and system changes.

The carbon budgeting system should therefore have space for detailed descriptions, endorsed by Government, on how the emission targets (both short and long term) are to be achieved, subject to necessary flexibility and with due regard to “urgency”. The concern here is not only with direct action by Government but also with action by other agents for change operating within policy frameworks set or influenced by Government

In this context the ideas set out by the BIEE Climate Change Policy Group[5] on time critical pathways, essentially documents that set out expectations on how sectoral targets are to be achieved, could play an important role in making the proposed carbon budgeting system fully effective. There are two specific points of entry.

(i) Section 6 requires the Government, whenever a carbon budget is set, to produce a report setting out its proposals and policies for meeting the carbon budgets for current and future budgetary periods. Note 34 to the Bill states that “this clause aims to enshrine transparency in the system so that Parliament is clear about how the Government intends to achieve its new obligations”.

(ii) Section 21 requires that the Committee on Climate Change report annually to Parliament its views on progress being made towards meeting not only the carbon budgets already set, but also the long term target for 2050.

It is difficult to see how these duties could be discharged satisfactorily without reference to something like Government-endorsed “time critical pathways” for the main sectors of electricity, transport and buildings.

Economic Costs of Adjustment. While one should not underestimate the scale of the task, I believe that the purely economic costs of adjustment, either to GDP or to consumers, are frequently overstated. As an example, the electricity sector accounts for some 35% of UK CO2 emissions and clearly has to become virtually carbon-free by 2050 if even a 60% target is to be achieved. However this is a sector in which a very large replacement programme would in any case be required over the next 20/30 years just to replace aging nuclear and coal stations.

Just to get a feel for the magnitude of the economic impacts for this sector, it is instructive to look at the French economy, which effectively converted electricity to carbon neutrality in two decades, from c 1980 on, while at the same time maintaining some of the most competitive power prices in Europe. France, apparently, made at least half the progress associated with a 60% target, within two decades, without any obvious excessive cost burden or adverse economic consequences.

5. Use of credits from overseas investment projects should be permitted ?

The BIEE Climate Change Policy Group has addressed this question directly in its submission to Government.

“We recognise that emissions reduction is properly regarded as a global issue, and this requires in principle that there should be no restriction or disincentive to UK agents making genuine cost effective investments to reduce CO2 or GHG emissions in other countries, especially where these may be more cost effective than UK investments. However the use of overseas credits does raise a number of serious practical questions that need to be resolved.

First, the integrity, credibility and additionality of such schemes needs to be assured, as any revelations of schemes of dubious validity will serve to undermine both the domestic political consensus for action on CO2, and any exemplary value of UK action internationally.

Second, if the purchase of even soundly based international credits was on a scale that left only minimal “domestic” reductions, then the exemplary value of UK action would be severely damaged.

Third, analysis suggests that the availability of international credits will be very difficult to predict, as it will depend both on the implementation of projects in countries with sometimes difficult regulatory regimes, and also on the demand from other developed countries whose policies are still evolving. Unconstrained use of such credits could create significant uncertainty about the level of domestic emission reduction that is required, and undermine the stability of the CO2 price, with a damaging impact on investment.”

6. Constitution, remit, powers, and resources of the Committee on Climate Change.

Remit. There is a good case for separating the design and implementation of climate change policy, on the one hand, from monitoring and accountability on the other; this would increase the credibility of the monitoring agency and thus improve the enforcement of emission targets. However the Committee is likely to develop considerable expertise and may be drawn into an advisory role on policy. This may create tensions for its main role.

Factors to consider (section 5.55). While all these factors are relevant, they are rather all-encompassing and should not all have equal weight in the Committee's deliberations. The Committee needs primary objectives more narrowly defined in terms of climate, technological, and energy policy issues within a sound framework of economic analysis.

Composition. The focus should be primarily on expertise. Stakeholders would not carry credibility and would inevitably be drawn into protection of special interest positions.

Resources and expertise. In 5.57 of the consultation document, part (e) should be redefined as energy production, supply and utilisation. Energy policy should also be included explicitly as an area of expertise. Most importantly, the list should include expertise in regulatory or regulatory economics issues. The Committee itself needs considerable strength on these issues as well as some sound grounding in climate science and technology. Some areas will inevitably need to be supplemented in the supporting staff and perhaps in commissioning additional research.

[1] The group consists of a number of energy experts, but does not claim to represent the views of the BIEE membership as a whole.
[2] Bringing Urgency Into UK Climate Change Policy. BIEE Climate Change Policy Group, December 2006
[3] The recent IPCC report for example suggests that lower concentrations, of between 445ppm and 490ppm, would keep the temperature rise in a range of 2.0-2.4C. This compares with EU policy of seeking to avoid rises of more than 2C.
[4] Tyndall Briefing Note 17, March 2007

[5] Bringing Urgency Into UK Climate Change Policy. Paper by the BIEE Climate Change Policy Group, December 2006, and also Time Critical Pathways For UK CO2 Reduction, Supplementary Note, February 2007

BEYOND STERN. FORECASTING, COST EFFECTIVENESS, CLIMATE CHANGE

2008-03-30T17:39:00.001+01:00

John Rhys
April 2007

The following notes were prepared as the basis for written evidence to be submitted to the Environmental Audit Committee in April 2007. The comments are addressed to the themes of the Committee’s inquiry.

KEY POINTS

Targets should retain focus on the key objective - the control of the level of global cumulative emissions; annual emissions in particular years such as 2020 or 2050 are useful landmarks but are ultimately only secondary or intermediate targets.

Official forecasts sometimes do not appear to have the benefit of detailed end use analysis. This is essential to monitoring many aspects of policy, particularly those that depend on influencing consumer behaviour; a comprehensive research programme to remedy this could be established for a comparatively modest cost.

Statistics highlight the fundamental importance of the electricity sector, not only as the largest current source of CO2 emissions, but because of its potential future “carbon-free” contribution in buildings and transport; a successful long term strategy demands an essentially carbon-free power sector.

Cost effectiveness; a significant economic issue in the Stern analysis suggests Stern might have attached an even higher social cost to current CO2 emissions.

There are some limitations to the use of cost effectiveness analysis, including the danger of inconsistency between public policy and private sector decisions; a corollary is that the value of carbon should feed through to the supply chain and into consumer prices.

Short term incremental measures provide important but limited reductions in emissions. Ambitious longer term targets imply systemic change both in supply and in demand; this attaches key importance to more urgency in long term plans.

For the longer term, annual forecasts are likely to be significantly less important than the monitoring of actions against a credible pathway for each sector, with long lead times involved. Monitoring arrangements need to reflect this.

Competitiveness issues have been exaggerated, given the relatively small emissions from industrial fossil fuel use and the small or indirect impacts on competitiveness from policy initiatives in the key sectors.

FORECASTING AND TARGETS.

A first requirement of CO2 targets is that they should align with the objective. This is to minimise cumulative emissions, not to achieve a particular level by a given date. Targets such as 60% or 80% reductions in annual emissions by 2050 may be useful indicators of what is required but they should not obscure the primary objective, reinforced by Stern, of keeping cumulative emissions within “safe” limits.

This distinction is important for two practical reasons. First, 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 requires a 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.[1]

Second, the undeniable primacy of cumulative emissions implies that a rational approach to the design of an international regime and associated market mechanisms is also likely to be based on cumulative emissions from a baseline, with carryover of emission rights/savings between time periods, not on rigid annual numbers. Aligning national targets consistently with the shape and structure of future international regimes, including the ETS, will be essential.

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 behind the recent call by a group of UK energy economists for a greater urgency in UK climate change policy.[2]

Question 1. Government approach to forecasting.

The Government’s forecasting methods may be the best that is available for a high level view of energy trends. However there are issues in forecasting and monitoring targets, which are difficult to address without significant improvements to the knowledge base. This is particularly the case with “aspirational” targets or forecasts of non-specific “efficiency” gains.

Medium and long term forecasts normally fall down either because key economic assumptions prove to be wrong, for example on GDP growth or relative fuel prices, or because of new trends and relationships, including technical change. In a policy context this creates the risk of not very useful debates around the “counterfactual”, a hypothetical “what might have happened but for…”, rather than the policies themselves.

The real priority has to be the effectiveness of policy and the achievement of targets. Monitoring short term targets should be about evaluating the effects of particular initiatives and policies. This requires more attention to the detail and understanding of exactly how energy is used in particular sectors. Some aspects are relatively easy, such as modelling how changes in relative fuel prices for gas and coal impact on the carbon emissions from a given capital stock of electricity generation. By contrast it is much harder to assess the factors impacting on household use of electricity and gas.

I am not aware for example of any regular publication of estimates of how much energy is used by households for major sources of consumption such as space and water heating, cooking, refrigeration, lighting and other uses, let alone any monitoring of trends. One consequence of this may be exaggerated estimates of the carbon savings available from apparently trivial behavioural changes, for example in charging cell-phones. More seriously it makes it more difficult to assess accurately the impact of more significant changes, such as low energy lighting, or the impact of the housing stock on consumption for domestic heating. The less well founded any original savings estimates are in concrete assumptions about physical parameters, the more unreliable any monitoring will become.

An incidental but unfortunate by-product of the energy sector privatisations was the fragmentation and abandonment of the consumer research programmes carried out by the nationalised fuel industries. I would therefore recommend re-establishment of a comprehensive programme of load[3] and market research monitoring the nature of gas and electricity usage by consumers, and perhaps enhancing programmes aimed at better understanding of the dynamics of fuel use in the transport sector. Such a programme would be a relatively inexpensive form of “hard-edged”, quantified social research and could provide important inputs to policy formation across the board. Carried out on an annual basis it could provide considerable assistance in monitoring the effectiveness of policies to promote fuel efficiency, and give an early indication of, for example, the rebound effects that occur if extra efficiency is absorbed in extra consumption.

Question 2. Independent check, uncertainty and inclusion of international aviation.

The BIEE Climate Change Policy Group proposed[4] that “there should be an early and rigorous independent check on the feasibility of CO2 savings to 2020 projected to result from the enhanced ‘climate change programme’ of the July 2006 Energy Review”. Given the very limited real progress over two decades (as opposed to fortuitous reductions unrelated to carbon policy, notably the “dash for gas” or UK de-industrialisation), we need to be much more confident that this aspiration is achievable. Such an independent review might be commissioned by the new Carbon Committee.

Uncertainty should be set in the wider context of evaluating how targets are to be achieved. The correct response to uncertainty is emphasis on target achievement, not on hypothetical evaluations of excuses and counterfactuals.

International aviation and shipping are critical to a successful global outcome. Their exclusion reduces the credibility of other achievements. Hence they clearly need to be monitored, but as a distinct and separate component of the overall task, a component in which progress to international agreement will be a key factor.

Question 3. Projections to 2020 and 2050.

While alternative forecasts and scenarios for the longer term development of the energy sector can be instructive, the view of the BIEE group has been that the emphasis needs to shift to focus on the pathways required to achieve the overall target, and the policies that need to be put in place to implement them. The task of monitoring progress then becomes that of monitoring progress for a number of sectors, of which by far the most significant are electricity, buildings and transport, to ensure that the required changes are happening, and that the relevant infrastructure, market and regulatory arrangements are in place to support progress to sector targets.

To illustrate the point, I believe the arithmetic of current emissions makes it very clear that UK carbon targets can only be met if the electricity sector becomes virtually carbon free. If the position can be reached by (say) 2020 that no new generating capacity is being constructed other than renewables, nuclear or fossil with full carbon capture, then the range of possible outcomes for electricity demand in 2050, while still important, becomes much less relevant to carbon policy per se. If the sector is by then intrinsically carbon free, higher or lower levels of demand in 2050 may still have investment implications, but will be accommodated mainly by market-led adjustments to construction programmes.

SOCIAL COST OF CARBON. COST EFFECTIVENESS. APPROACH TO POLICY.

Question 4. For the purposes of policy discussion we need to distinguish carefully between the incremental social cost, the incremental costs of mitigation, and the “market price” of carbon under particular sets of emission control arrangements, all of which are important measures. Stern makes it clear that the social cost of carbon emissions is very high, and has indicated a current value of around $85/ tonne of CO2. However Stern also makes it clear that in many sectors the cost of mitigation is well below this cost.

There is an important point on the social cost of carbon where the generally sound Stern analysis may be flawed. The Stern report suggests that the social cost of CO2 emissions rises over time because damage increases as the ppm limit is approached. I believe this is misleading. Evaluation of the economic cost of current emissions must reflect a central feature of the physical models of climate, namely the identification of the cumulative concentration of gases as the main driver of climate change and hence of negative economic consequences. If an incremental tonne of carbon emitted today results in an incremental tonne of carbon in 2050, then its future impact after 2050 is essentially the same as a tonne emitted in that year. [5] It follows that its total social cost impact will be greater by the extent to which it has already contributed to a higher concentration[6]. If this argument is correct, then $85/ tonne might be a significant understatement of the cost of current emissions.

As a very broad policy instrument, it would appear right for the government to recognise a high social cost of carbon, as part of the rational underpinning for a number of necessary policies both short term and long term, and for choices between options and sectors. However there are a number of caveats attaching that should inhibit uncritical use of the approach.

a. Regular review of carbon valuation will be needed as both the science and the economic analysis is developed. A more pessimistic outlook emanating from the science is likely to translate into higher valuations of social cost. Technical advance by contrast could reduce mitigation costs and market valuations of carbon.

b. Consistency should obtain between public policy and private economic decisions. In principle both should be based on the same valuation of carbon. Inconsistencies will arise if a high value of carbon is put into public policy making, but not into the price that consumers pay for fuel. It may for example be cost effective to subsidise a consumer to insulate a large heated garage or a heated but unoccupied second home, when the same householder, if forced to bear the cost of carbon directly in fuel prices, would choose a cheaper and more effective solution.

c. A corollary of the above is the general principle that an appropriate value of carbon should be allowed to feed through into consumer prices and into supply chains, so that consumers can make genuine economic choices informed by the high real cost of carbon. Potential hardship resulting for particular fuel-dependent sections of the community can and should be addressed through other policies.

d. Other aspects of policy choice are involved. Policy needs to be set in a context that compares relative costs of mitigation, particularly where these are in competition for the same market. Policy has to be assessed not only on cost effectiveness but also on consistency with overall delivery of carbon targets. For example a policy built around a new technology that cut by 25% the carbon emissions from fossil fired power generation might appear cost effective with a high valuation of CO2. But it would not be consistent with a CO2-free power sector; if the latter were a pre-requisite of achieving the overall target, then the technology would not pass muster as a long term solution.

Questions 5, 6. Approach to Policy.

The government needs to move quickly to put more emphasis on the policy measures that will be needed to achieve the longer term targets. We need to recognise that relatively “easy” short term measures, which include some “low hanging fruit”, can only deliver a small part of the total reduction that will be required. Longer term measures that require major systemic and infrastructure changes, or major investments, should be given at least as much urgency, and will deliver much more of the ultimate reductions required.

A sectoral approach should focus on electricity, transport and buildings.[7]

The Main Sources of UK Carbon Emissions

An estimate of current UK carbon emissions can be constructed from official fuel use data, using conventional assumptions of each fuel’s CO2 content, to show how sectoral policies and targets might be framed and prioritised. Excluding emissions within the oil and gas industries themselves, an admittedly imperfect but reasonable approximation, based on 2004 data, is the following

power generation (for final use in all sectors) xxxxxxxxxxxxxxxxxxx 34 %*
transport (mainly road but including rapidly growing aviation) xxx33 %**
domestic use of fossil fuels, mainly gas xxxxxxxxxxxxxxxxxxxxxxxx x17 %
general industrial use of fossil fuels (excl energy industries) xxxxxxx12 %
other, including commercial and public sector xxxxxxxxxxxxxxxxxx 4 %
total xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx x100%

* NB this excludes power already taken from nuclear and renewables
** aviation is often excluded from aggregate numbers for UK

Given the absence of proven near term alternatives in transport, and the inertia inherent in the building stock, this indicates very strongly that even a 60% reduction target implies that electricity has to be carbon free, and underscores the huge importance of getting electricity right. Electricity would constitute an even bigger share but for the 20% of generation that is already carbon free (some renewables but mainly nuclear). Its future importance is accentuated by its potential role to substitute in transport (electric vehicles or as a primary source for hydrogen), and to replace direct use of oil or gas in heating buildings.

Electricity is also significant because international experience shows that the capital stock could be turned over within comparatively short timescales, of one or two decades, to be virtually carbon free. The French experience (admittedly with nuclear power) is very instructive in this respect. This is also a market in which comparatively easy and very cost-effective policy initiatives to reduce uncertainty, such as a policy commitment or a floor price for CO2, could lead to significant increases in CO2 reducing investment.

More generally the BIEE group concluded[8] that the need for urgency in policy making requires that the government should demonstrate a singleness of purpose, at the earliest opportunity, by emphasising the importance of carbon targets within a “joined up government” approach. Wherever possible, policies to meet other objectives (eg fiscal, housing and other policies) should be consistent with and should not obstruct CO2 reduction. Where other policies do run counter to CO2 reduction, it should be made explicit that additional countervailing measures will be needed.

ACCOUNTABILITY TARGETS AND REPORTING.

Questions 7,8. The BIEE group[9] argued that there is a strong case for aligning the main sectoral targets with government departments and introducing ministerial responsibility for them. Annual cumulative emissions should be monitored and any excess over the target path should be justified and addressed convincingly in the evolution of policy.

It is important that reporting and monitoring should be viewed not only in terms of the annual reduction of emissions against the required trend, but also in terms of progress with measures necessary to secure sustainable momentum in future years. The use of an independent agency to monitor whether policies of individual ministries deliver on an annual basis, and also on mid-term targets, is attractive. Separating design and implementation from monitoring could increase the credibility of the monitoring agency and thus improve the monitoring and enforcement of targets.

The composition of the Carbon Committee should not be based on special interest groups, as this would weaken its independence and its credibility. It is important that it should include a substantial body of scientific, engineering and economic expertise to provide a good practical understanding of the many complex issues with which it will have to engage.

COMPETITIVENESS ISSUES.

Question 9. I believe that, in the context of measures by the UK to combat emissions, the significance of competitiveness, as an issue inhibiting unilateral action, has been greatly exaggerated. First, an analysis of the sources of emissions makes it clear that direct industrial use of fossil fuels (other than for power generation) is quite a small part of the total, so targeting industry is not a first priority. Second, the measures necessary to contain emissions in the most important sectors, electricity[10], housing and transport, will mostly have only small and indirect effects on industry costs, and in terms of competitiveness are dwarfed by the much more direct and overarching effects of exchange rate movements. Third, those fuel intensive industries which are subject to international competition account for only a small percentage of GDP. In this context it is useful to distinguish intra-EU and extra-EU competition. UK power costs for industry are already higher[11] than in much of the EU. In shaping the EU ETS we should certainly aim to prevent economic distortions that merely “export” emissions to countries outside the EU with lower energy efficiencies, but this is best done either by limited “ring fencing” for the few industries concerned, or by pursuing wider international agreement.

SETTING SHORT TERM TARGETS

Question10. Targets should be framed to reflect emphasis on the longer term objective of cumulative emissions; they should have a sectoral element to reflect individual ministerial responsibilities, be realistic on short term achievements and be capable of being monitored in fairly concrete terms; they should cover not only CO2 emissions but also progress with the fundamental longer term systemic aspects of policy.

[1] Likewise a back-end loaded reduction path adds a similar and substantial amount to cumulative emissions.
[2] BIEE Climate Change Policy Group. Bringing Urgency Into UK Climate Change Policy. December 2006
[3] For electricity, load research is based on sample recordings of load on individual circuits or appliances.
[4] BIEE Climate Change Policy Group. Bringing Urgency Into UK Climate Change Policy. December 2006
[5] A possible partial counter argument to this might apply if the extra emission were to increase the re-absorption rate; however with limited re-absorption or positive feedbacks it is perhaps more likely that an incremental tonne of carbon emission results in more than one incremental tonne in 50 years time.
[6]The comparison ignores time discounting in the context of this particular argument.
[7] Note that, if we exclude its share of electricity, industry is of less significance.
[8] BIEE Climate Change Policy Group. Bringing Urgency Into UK Climate Change Policy. December 2006
[9] Ibid.
[10] In the case of electricity, it may also be noted that French electricity for industry, already essentially carbon-free, has been very competitively priced.
[11] Arguably just part of an exchange rate issue.

Response to Draft Climate Change Bill. May 2007

2008-03-30T17:10:00.001+01:00

These notes were prepared as the basis for a written response by the BIEE Climate Change Policy Group to the Draft Climate Change Bill in May 2007.

1. Introduction. We welcome the introduction of the draft Climate Change Bill as indicating the importance Government attaches to climate change policy, particularly the creation of a new institutional framework to back a system of carbon budgets and to set statutory limits to carbon emissions. Concerns are not so much with possible amendments to the Bill as the need for clarity on the Government’s position on certain key issues which may well arise during the passage of the Bill and will influence the effectiveness of the carbon budgeting system in due course.

2. However, notwithstanding the above level of agreement with the main framework of the Bill, we have comments which we believe will be very important in making the proposed carbon budgeting system fully effective. These concern:

a. The CO2 reduction target proposed for 2050, and its effect on the intermediate target for 2020 and the trajectory of 5 year budgets.
b. The extent to which effort purchased by the UK from other countries should be eligible in contributing towards UK emission reduction.
c. How the whole corpus of detailed policies/ measures to reduce emissions can be incorporated within the carbon budgeting process, and thus clearly linked with accountability.

We deal with each of these in turn.

3. Unilateral Legal Target of CO2 reduction by 2050 and associated trajectory. The proposed unilateral legal target of 60% CO2 reduction by 2050 derives from the RCEP report published in 2000 and was adopted in the 2003 Energy White Paper on the basis that it was consistent with a global strategy of limiting the ultimate atmospheric concentration of CO2 to 550 ppm. As such it has been very helpful in promoting a national consensus on the scale of the actions required. On these grounds alone there is a strong case for embedding this 60% target in the proposed legislation.

However this position is not without difficulty, since

-the most recent scientific consensus indicates the need to aim for atmospheric concentrations of CO2 of less than 550 ppm [1]
-in the light of the lack of progress in reducing emissions over the last decade there are real doubts as to whether a 60% target would deliver cumulative emission reductions consistent with 550 ppm in 2050. [2]

Accordingly in an earlier paper [3]we expressed the view that “we should at least consider the implications of a more challenging 80% target, as well as the more conservative 60% UK reduction considered hitherto”.

The question is how should these concerns be dealt with within the proposed framework in the Bill? Clearly this has to be done in such a way as to minimise long term uncertainty on the government’s position. Otherwise many of the advantages of three rolling 5 year budgets could be prejudiced.

The essential issue is that a limit based on an 80% reduction would be a further major reduction in carbon emissions, implying only half the allowable emissions of CO2 in 2050 compared with a 60 % reduction. As such it almost certainly implies significantly higher adjustment costs, and is also likely to imply measures which would impinge on the nearer term targets. It would therefore be harder to justify an 80 % reduction as a UK unilateral measure at this juncture.

Thus, if risks of delay to the passage of the Bill are to be avoided, the most appropriate compromise or practical approach is to proceed for the time being with limits based on the 60% target as outlined in the Bill, but to recognise the probability that the UK will wish or indeed need to move to a tighter limit in the future, most probably as part of a coordinated international response. This does not appear to call for any obvious major adjustments to the Bill, other than to ensure that both Government departments, in their monitoring and policy development, and the Committee on Climate Change, in its advisory role, do take into account the implications of tighter international objectives as exemplified by an 80% path. The combination of explicit legal limits, with a recognition that the UK may need to adjust to even tighter targets in the future, should effect a substantial reduction in the uncertainty facing investment in CO2 emission reduction.

Because of the difficulty of these issues we would also propose that:

(i) at the earliest opportunity the Secretary of State should decide whether there had in fact been significant developments in scientific knowledge about climate change such as to raise doubts on the validity of the 60 % target [section 1.4]

(ii) the Secretary of State should seek the advice of the Committee on Climate Change [section 22.1] on:

a) the implications of adopting an 80% rather than a 60% target for 2050, in terms of the validity of the interim target for 2020, and the probable limits for the first three 5-year carbon budgets

b) clarification of the probable link between the 2050 target, whether on a 60% or 80% basis, and the cumulative UK emission reductions to 2050 (and therefore the implied carbon budgets to 2050)

(iii) the advice of the Committee should assume that targets/budgets would include aviation and shipping

4. Counting overseas credits towards the budgets and targets.

Any presumption that “effort purchased by the UK from other countries should be eligible in contribution towards UK emission reductions, within the limits set out by international law” needs to be clarified and qualified.

We recognise that emissions reduction is properly regarded as a global issue, and this requires in principle that there should be no restriction or disincentive to UK agents making genuine cost effective investments to reduce CO2 or GHG emissions in other countries, especially where these may be more cost effective than UK investments. However the use of overseas credits does raise a number of serious practical questions that need to be resolved.

First, the integrity, credibility and additionality of such schemes needs to be assured, as any revelations of schemes of dubious validity will serve to undermine both the domestic political consensus for action on CO2, and any exemplary value of UK action internationally.

Second, if the purchase of even soundly based international credits was on a scale that left only minimal “domestic” reductions, then the exemplary value of UK action would be severely damaged.

Third, analysis suggests that the availability of international credits will be very difficult to predict, as it will depend both on the implementation of projects in countries with sometimes difficult regulatory regimes, and also on the demand from other developed countries whose policies are still evolving. Unconstrained use of such credits could create significant uncertainty about the level of domestic emission reduction that is required and undermine the stability of the CO2 price, with a damaging impact on investment.

Under present practice and within the framework of the EU ETS, UK reliance on such credits is limited to some 8% of total emissions. The “partial regulatory impact assessment” attached to the Bill examines the issue of greater flexibility and states (5.1.38) that the use of such additional flexibility would:

- restrict the pace of decarbonisation of the UK economy, by encouraging Government and firms to use overseas credits as a cheaper short-term option, expose the UK to the risk of “lock-in” to high carbon technologies, and potentially reduce the ability of the UK to demonstrate leadership

We would give considerable weight to these observations at this juncture. They are of greatest relevance for the next 5-10 years, since it will be during this period that

- the exemplary value of UK action would have the greatest leverage in progress towards a “post Kyoto” settlement
- potential reforms to the EU ETS will have to be implemented and tested
- long term foundations for the UK low carbon economy need to be laid, requiring strong incentives

On this issue we propose that the use of overseas credits (particularly CDM and JI) should remain very limited for the first budget period to 2012, and be subject to review thereafter in the light of progress with EU ETS reform and international negotiations on a “post Kyoto” settlement.

This would also involve specific guidance from the Secretary of State to the Committee on Climate Change to limit its discretion on this point. (Section 20.i.b)

5. Incorporating the corpus of policies and measures into the carbon budgeting system, including accountability and monitoring.

We are concerned that the carbon budgeting system, and its associated accountability and monitoring arrangements, should facilitate public scrutiny of the whole corpus of policies and measures concerned with the low carbon issue. Effective accountability will need to consider not only recent performance of emissions against budget but also those steps being taken to create the conditions for necessary long term technological and system changes.

We believe that the carbon budgeting system should have space for detailed descriptions or “time critical pathways”, endorsed by Government, on how the emission targets (both short and long term) are to be achieved, subject to necessary flexibility and with due regard to “urgency”. We emphasise that here we are concerned not only with direct action by Government but also with action by other agents for change operating within policy or market frameworks set or influenced by Government.

Our ideas on “time critical pathways” have been set out in earlier documents[4], and are summarised again in Annex 1 to this note. We believe they could play an important role in making the proposed carbon budgeting system fully effective. There are two specific points of entry.

(i) Section 6 requires the Government, whenever a carbon budget is set, to produce a report setting out its proposals and policies for meeting the carbon budgets for current and future budgetary periods. Note 34 to the Bill states that “this clause aims to enshrine transparency in the system so that Parliament is clear about how the Government intends to achieve its new obligations”.

(ii) Section 21 requires that the Committee on Climate Change report annually to Parliament its views on progress being made towards meeting not only the carbon budgets already set, but also the long term target for 2050.

It is difficult to see how these duties could be discharged satisfactorily without reference to something like Government-endorsed “time critical pathways” for the main sectors of electricity, transport and buildings.

23.05.2007/mjp/jr

Annex 1. Summary Of Proposals On Time Critical Pathways

In the detailed evolution of Climate Change Policy, and within the framework of carbon budgets proposed in the draft Climate Change Bill, there is also a need for an approach which will address “urgency” directly. Given the long lead-times involved in removing sources of inertia, introducing low carbon technologies and making the associated changes to infrastructure and institutions, the successful implementation of any 60- 80% path is on a very tight schedule. To provide clarity and credibility there is therefore a need to draw up “time critical pathways” for the three most significant sectors —electricity, transport, and buildings. These would be drawn up by the relevant Government departments, and endorsed by Government. They would identify, for each sector:

i) the extent and duration of the CO2 savings likely to be available from short term behavioural changes to reduce demand, increased efficiency of existing assets and systems, and fuel switching between existing assets and systems.

ii) the likely portfolio of options for key technologies/ system changes, over and above those in (i) above, which could contribute to the sector’s transition to a very low carbon future by 2050 and an assessment of the speed at which they might be introduced, taking account of:

- stage of technical development (in light of R&D both in the UK and internationally)
lead-times to widespread adoption
- age and turnover of existing capital stock (including associated infrastructure)
nature of factors creating inertia and barriers to progress, and the potential speed of their removal

iii) description of “time critical pathways” based on analysis of the above factors, which clearly set out the order and timing of key decisions and commitments involved, if the ultimate goals are to be achieved, in terms of:

· who will be the main agents for change; and therefore who is to be incentivised to do what, and when?
· what incentives will be most appropriate for urgent progress?
· what issues of coordination (e.g. on infrastructure) will arise and when?
· how sufficient flexibility can be retained to cope with uncertainty.

Such descriptions of “time critical pathways” could be an important means of establishing a coherent link between the whole corpus of climate change policy measures and the carbon budgeting system and its associated accountability framework.

[1] The recent IPCC report for example suggests that lower concentrations, of between 445ppm and 490ppm, would keep the temperature rise in a range of 2.0-2.4C. This compares with EU policy of seeking to avoid rises of more than 2C.

[2] Tyndall Briefing Note 17, March 2007
[3] Bringing Urgency Into UK Climate Change Policy. Paper by the BIEE Climate Change Policy Group, para 3
[4] Bringing Urgency Into UK Climate Change Policy. Paper by the BIEE Climate Change Policy Group, December 2006, and also Time Critical Pathways For UK CO2 Reduction, Supplementary Note, February 2007