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

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

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

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

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.

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?

x

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.