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Energy Policy 36 (2008) 1448–1456

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Do liberalised electricity markets help or hinder CHP and districtheating? The case of the UK

David Tokea,�, Aikaterini Fragakib,1

aDepartment of Sociology, University of Birmingham, Edgbaston, Birmingham B15 2TT, UKbWelsh School of Architecture, Bute Building, King Edward VII Avenue, Cardiff CF10 3NB, Wales, UK

Received 8 November 2007; accepted 17 December 2007

Available online 11 February 2008

Abstract

This paper investigates whether and how Danish-style combined heat and power (CHP) and district heating (DH) can be implemented

in the UK in the context of a liberalised electricity market. There is currently an absence, in the UK, of the Danish system of planning

rules and also good tariffs for CHP electricity exports to the grid that led to the development of the Danish system of CHP and DH.

However, there are some changes in UK planning practice that may help CHP and DH. These would need to be strengthened, but it is

also the case that the way the liberalised electricity market operates in the UK effectively discriminates against small CHP plant selling

their electricity to the grid. A Danish system of ‘aggregating’ CHP–DH plant using thermal stores could help to overcome this problem.

However, an alternative strategy would be to establish feed-in tariffs for CHP units that are linked to DH modelled on the Danish ‘triple

tariff’. This could help the UK’s long-term objective of absorbing high levels of fluctuating renewable energy sources.

r 2007 Elsevier Ltd. All rights reserved.

Keywords: CHP and district heating; Liberalised electricity markets; Thermal stores

1. Introduction

Liberalised electricity markets and also combined heatand power (CHP) and district heating (DH) are bothpolicies that being actively promoted by the EU asdesirable (Andersen and Lund, 2007; Meyer, 2003). Meyer(2003, p. 667) says that the objective of liberalisation ofelectricity markets ‘is to achieve higher efficiency and lowerconsumer prices by introducing conditions of intensifiedcommercial competition’. On the other hand, CHP–DH isfavoured because, among other reasons, it is a strategy inimproving the efficiency of energy production and use thatcan penetrate the crucial area of heat supplies for buildings.CHP involves the simultaneous production of electricityand heat, and DH systems for housing estates, educational,health or commercial buildings and even for industrial usescan be a crucial type of realisation of CHP.

e front matter r 2007 Elsevier Ltd. All rights reserved.

pol.2007.12.021

ing author. Tel.: +44 121 415 8616; fax: +44 121 414 6061.

esses: d.toke@bham.ac.uk (D. Toke),

iff.ac.uk (A. Fragaki).

20874623.

Yet the question arises whether a policy (liberalisation)that is concerned with allowing lowest short-term costsolutions to succeed can easily coexist with a policy that isprecisely concerned with picking technological winners. Ifwe wish to reduce carbon dioxide emissions then we needto promote particular technologies that can help achievethis objective. While we do talk about ‘small’ CHP we arenot talking about domestic CHP, but rather about CHPsystems that will serve a number of dwellings or largebuildings and have electrical outputs of over 100KWe. Wewould define 50MWe as the upper limit for small CHP.The United Kingdom has one of the most developed

liberalised electricity markets, so it may be useful inanswering the above question to look at how liberalisation,in practice, affects the possibilities for expansion of CHPwith DH (often called community heating). We shall assessthe extent to which liberalisation and expansion ofCHP–DH are compatible and discuss some strategies forencouraging CHP–DH in the UK. We shall do this byassessing the extent to which a Danish-style CHP–DHsystem could be implemented in the context of the UK’sliberalised electricity markets.

ARTICLE IN PRESSD. Toke, A. Fragaki / Energy Policy 36 (2008) 1448–1456 1449

We shall begin this account with a description of UKelectricity markets and liberalisation. We shall thendescribe CHP and DH in Denmark. We do this sinceDenmark presents us with and advanced model concernedwith use of CHP and DH. We can use this example tocompare and evaluate the possibilities for development ofsimilar strategies in British conditions. Finally, we shallmove on to discuss some solutions to the problems that wehave discussed in the case of the UK.

2. UK electricity markets and liberalisation

It is useful to give an outline of the nature and historicaldevelopment of liberalisation. In 1990, electricity privatisa-tion was implemented. This broke up what was previouslyeffectively a vertically integrated public owned genera-tion–distribution-and-supply monopoly headed by theCentral Electricity Generating Board (CEGB). Competi-tion was introduced in stages so that by 1998 there wascompetition to supply (retail) electricity to all consumers.There is a wholesale market whereby generators competeto sell electricity to the suppliers. There are also separate(regional) distribution and (national) transmission agencies,although these are natural monopolies subject to regula-tion. In fact, it is all ‘regulated’ in as much as there areoften extremely complex rules about how, for example,electricity is traded between generators and suppliers.Hence, it is really a misnomer to call the changes since1990 ‘de-regulation’.

Initially, after 1990, the wholesale market operatedthrough generators bidding sellers prices to a centralisedpool, with a single (at any one time) ‘pool price’ beingavailable for suppliers. However, there were charges thatbig generators were manipulating the system by taking bigunits offline at strategic moments so as to push up the poolprice, thus increasing overall revenues. The response, in2000, was to reform the system so that the centralwholesale price-setting formula was abandoned in favourof bi-lateral trading or privately organised markets.

This system is now known as British ElectricityTransmission and Trading Arrangement (BETTA). Thereis now no longer a central price to manipulate. Ratherthere is a series of contractual arrangements oftennegotiated on a bilateral basis covering forward marketsin different time periods and different types of electricitysupply. In reality, the large bulk of the ‘trading’ is doneoutside the various power markets (e.g. power exchanges)that exist. The large bulk of electricity is traded throughdeals that are internal to the large electricity companieswho own generation units as well as supply energy, or atleast between the main electricity suppliers and largegenerators through long-term contracts. Only a smallproportion of electricity is actually traded through marketmechanisms and less than 5 per cent through the ‘balancingmechanism’ organised by the transmission system operator(GridCo). However, all the generators over 50MWe haveto be registered to meet the conditions of the balancing and

settlement code (BSC). It is through this system thatgenerators face potentially steep penalties for failure togenerate the amount of power that they have registered asdoing at ‘gate closure’, which is half an hour before actualdespatch.It is here that there are major issues faced by small

generators, or at least ones below around 50MWe in size,in trading directly on the wholesale power markets.Essentially, it is not practical (under BETTA) for smallCHP units to trade directly on the power markets, and as aresult they suffer significant reductions in income forexported electricity. There is the considerable administra-tion involved in registering the projected production, andthere are also significant credit conditions on participatingin trades on power markets. In addition to this, CHPoperators are reluctant to face the possibility that they maysuffer severe penalties for failing to generate what theyhave projected to produce, especially for CHP–DH unitswhere fluctuations in on-site electricity demand may makeit difficult to come up with sufficiently accurate forwardprojections.When small CHP units (that is units under 50MWe in

size) do sell electricity onto the grid they do so throughintermediaries called ‘consolidators’. These, in effect, treatthe power from CHP units as ‘negative demand’ so that itdoes not have to be registered with the BSC. It thus avoidsthe problems that we have just discussed. However, thiscomes at a price, because the CHP units receive only adiscounted price through the consolidators. The consoli-dators are left to face the risks and responsibilities oftrading on the power exchange markets, and they earn apremium for taking on this risk. It should be noted thatthese ‘consolidator’ deals yield a much better return thanwould be earned by, say, a CHP–DH unit operated by alocal Council selling the exported electricity to the samesupplier who provided the Council with electricity. How-ever, from the point of view of ensuring parity for pricespaid with conventional power stations (who can tradedirectly on power markets) it is only a partial solutionbecause ‘consolidator’ unit sales prices will be less thanwhat would be earned by a power station who sellselectricity at the same time directly to the power exchangemarkets. Without access to the trading desks and strategiesof the consolidators themselves it is difficult to discuss theextent to which consolidators receive lower payments inrespect of electricity from small CHP.We calculated the difference between what a small CHP

operator would earn annually from a contract with a‘consolidator’ and if they were able to sell the electricity onthe power exchange market and earn the same income perMWh as was being earned by power stations. It has beenassumed that the CHP engine is running all the time atfull load.It should be noted that under the current situation in the

UK the CHP are running full load, in average 60 per centof the time. However, the addition of a device for heatstorage (thermal storage) could allow the engine to run full

ARTICLE IN PRESSD. Toke, A. Fragaki / Energy Policy 36 (2008) 1448–14561450

load more hours and could also allow engines CHP to sellelectricity when the prices are high. The use of thermalstores is an important feature of Danish CHP–DH andtheir operation is explained in more detail in Section 3.

The above calculation gives only a rough estimate ofwhat the extra profit of the CHP unit would be if it couldsell electricity at wholesale market prices. A more detailedanalysis would involve economic optimisation of CHPplants, equipped with thermal stores, with electricity pricesusing commercially available software like energyPRO(Toke and Fragaki, 2007).

We were able to make such a comparison because wewere given some ‘typical’ tariff rates for 2006 offered to asmall CHP unit (3.2MWe) while the tariffs on the powerexchange markets were available through daily historicaland forward prices published online2 (at the time of doingthe research). The outcome of this calculation was that theCHP operator would have earned around a third more if ithad been paid the same tariffs per MWh of electricity as aconventional power station. The general conclusion thatsmall CHP operators suffer a significant discount com-pared with the tariffs earned by conventional powerstations is confirmed by consultants in the field, forexample, Martin (2007). We shall, later describe how it ispossible for CHP units with thermal stores to overcomethis problem of discounted electricity sales incomesthrough utilising the Danish system of ‘aggregating’ theelectricity outputs of small CHP units.

CHP operators do enjoy incentives. They do not have topay the ‘climate change levy’ (CCL) on the fossil fuel thatthey use, and they also have a CCL exemption on theelectricity that is sold to the grid that is they do not have topay the energy taxes levied on fossil fuel generators. It isnot the purpose of this article to assess the value of theseincentives, which in any case will vary greatly according tothe type and context of a particular project.

CHP operators obtain the full retail value of theelectricity that they sell on-site. In addition, CHP plantalso benefits from the ‘enhanced capital allowance’ schemewhereby companies installing CHP can write off their taxeson profits against the value of the CHP capital investmentin the year in which the investment is made. However, thevalue of this depends on the amount of profits that acompany is making, and the help that this incentive gives toCHP–DH schemes may be less than other CHP activities.However the difficulties, described earlier, that CHPoperators face in obtaining a good price for their electricitysales to the grid would substantially reduce, if notneutralise these incentives. For example, the CCL exemp-tion on CHP electricity exports, worth around £4 per

2Published online by Spectron historcial indices. http://www.spectronli-

ve.com/ accessed 31/03/06 and also European Daily Electricity Markets

Heren Report http://www.heren.com/ accessed 27/03/06. The CHP

‘consolidator’ contract details were given to us by P.B. Power on a

confidential basis. Spreadsheets showing our calculations are available on

request from the authors.

MWh3 to a CHP operator, is less than the say, £10 perMWh that might be lost compared with a power marketprice of, say, £40 per MWh that a power station wouldearn for its electricity.In addition, it can be argued that when it comes to

exporting electricity to the grid, the system effectively givessmall CHP operators negative rewards for their environ-mental contribution to reducing the pollution levelsassociated with electricity generated from fossil fuels. Thelack of incentives for small CHP plant to sell power to theelectricity grid encourages designers of CHP schemes tokeep the units to a small size. This happens because itappears under the present system that this is the mosteconomic way to operate CHP in the UK that are less thanaround 50MWe in size. Unfortunately, this issue has notbeen given emphasis by the Government. For example, onerecent evaluation produced for the EU does not evenmention this issue as a ‘barrier’ to further expansion ofCHP (DEFRA, 2007). We shall now look at the CHP–DHsystem in Denmark in order to prepare the ground for adiscussion of how CHP–DH can be developed in the UK inthe context of electricity market liberalisation.

3. CHP and DH in Denmark

CHP units can involve gas turbines or gas engines, but inthe cases of Danish decentralised CHP smaller power units,say in the 1–10MWe range, have usually tended to involvegas engines. They achieve a higher rate of total energyconversion and lower maintenance costs in the circum-stances where DH systems involve power units which stopand start in response to changing electricity prices(Andersen and Lund, 2007; Lund and Andersen, 2005;Moller, 2002). As we said earlier, we take as our model forthis the Danish system of CHP with DH since it is the mostsuccessful in terms of penetration of energy markets.Conditions in other countries will be different and thedifference that may be attributable to the regulatory regimecovering electricity in the UK is an important focus in thisarticle.In Denmark around a half of all electricity produced

from all types of CHP, mainly CHP–DH, and around aquarter of Danish electricity is generated from ‘decentralised’gas engines of the type just mentioned. Gas engines thatare currently available will achieve total energy efficienciesof around 80 per cent, half electricity, and half-heat. TheDanish CHP–DH system was developed since the 1970susing a mixture of planning rules requiring domesticheating to be sourced from DH and also financialincentives favouring the building of CHP units (DanishEnergy Agency, 2007; Lund, 2000). An original powerfulincentive for the development of CHP–DH in the 1970swas that Denmark was reliant on oil imports to provide

3Nominally, the CCL exemption is worth £4.3 per MWh, but it is usual

practice for only 80 per cent of this figure to be paid to the CHP generator.

ARTICLE IN PRESSD. Toke, A. Fragaki / Energy Policy 36 (2008) 1448–1456 1451

heating, and this became very expensive following the oilcrises.

Under the Danish Heat Law of 1979 local authoritieshad to prepare plans for heat supply in their areas. Localauthorities had to oblige new buildings to connect to DH.Later on electric heating was banned. In the 1990s, the DHsystems were converted to CHP. In the 1990s, large coalfired and also large gas fired DH was converted todecentralised gas co-generation of heat and electricity.

Minor taxes on oil were introduced starting in the 1970sbut were increased when the price of oil fell. The CHPsystems have been organised by a mixture of municipal andgrass-roots initiatives. The tax system was oriented so thatdecentralised CHP could be organised at a profit for localco-operatives organised by local residents. Lund says that‘the Danish tradition for consumer owned heat supplies’was an important factor in encouraging the rapid adoptionof the strategy at a grass roots level (Lund, 2000, p. 255).There was a ‘triple tariff’, which involved paying CHPoperators high electricity tariffs during peak demandperiods. The peak demand price was around three timesthe off-peak (nighttime) tariff and around 30 per centhigher than the daytime standard tariff (Sievers et al., 2007,p. 10).

An important feature of Danish CHP–DH is the use ofthermal stores, which are, in effect, large tanks for storinghot water. These allow the plant to generate energy whenelectricity prices are high even when there is no demand forheat because the heat can be stored in the thermal stores.The plant can then be switched off when electricity pricesare lower and heat demand can be supplied from thethermal stores. This system allows the economics ofCHP–DH to be substantially improved leading to thebuilding of larger units than would otherwise be economic-ally viable. However, a key facet of this system, which willbe the focus of further discussion in the British case, is thatelectricity generated by the CHP units is traded on short-term (day ahead or less) Danish power markets (Lund andAndersen, 2005).

It is important to point out that this system is under-pinned by a technique of ‘aggregating’ the output of thesmall CHP units so that they can sell their power directly tothe Danish power markets. This enables to access similarprices for electricity exports as those enjoyed by conven-tional large power stations. Aggregation as a means ofmaking a group of CHP sites into a tradable, despatchablepower station is a concept that does not exist in practice inthe UK at present. Commercial exploitation of aggregatedCHP would involve amassing a group of sites and signing itto one licensed electricity supplier with a contractualagreement between the CHP operators involved andthe supplier about how it is to be traded. We shall describethe details of aggregation more fully later. As we discusslater, Denmark is different to the UK where CHP unitscannot sell directly to the grid and they are paidsignificantly less than conventional power stations for theirelectricity.

This system of decentralised CHP–DH also offers astrategic possibility for reducing the costs of absorbing, orbalancing, large penetrations of fluctuating renewablesources of energy. The application of this system mayallow the economic level of wind power that can beintegrated into the system from its present 20 per cent ofDanish electricity supply to around 40 per cent ofelectricity supply. (Lund and Munster, 2006). This isbecause the decentralised CHP are able to respond in aflexible manner to changes in the output of renewableenergy. As the share of Danish electricity being suppliedfrom wind power increases beyond 20 per cent there will bean increase in the circumstances where there may be anexcess of electricity production from the windfarms. Inthese circumstances, wholesale electricity prices will be lowand so the CHP units will be incentivised to switch off andsupply heat from their thermal stores. Alternatively, heatcould also be supplied from the electricity generated by thewind power using heat pumps.These techniques avoid the need to switch off the

windfarms (thus wasting renewable energy). If there is alow production of wind power then the CHP units cancome online and produce electricity, sending surplus heatinto the thermal stores. The CHP units have a relativelylow capacity factor (between 50 per cent and 60 per cent)meaning that there is a substantial amount of slack tomake this effective in reducing system balancing costs(Andersen and Lund, 2007). We shall now look at the CHPmarket in the UK, and especially, the small CHP–DHsector.

4. CHP and DH in the United Kingdom

In the UK, electricity production from CHP amountedto around 9 per cent of UK electricity consumption in2005. Most of this was in industry, with oil and gas beingthe leading sector followed by chemicals and then paper.However, only around 350MWe was in the buildingssector, representing just 6 per cent of the UK’s total CHPcapacity of around 5600MWe (DBERR, 2007) and nomore than around half a per cent of total UK electricityconsumption. The growth in amount of CHP capacity hasstagnated since 2004 and the UK Government’s own targetof building 10,000MWe of CHP by 2010 seems unlikely tobe met on current trends.The Government has estimated that there is big potential

for CHP–DH in the UK. This potential is put at 21.5GWeby 2010 at a 6 per cent discount rate, although this falls to amere 75MWe at a 9 per cent discount rate (DEFRA,2007). This reflects the capital intensive nature of thetechnology. As we discuss later, support policies need totake this into account.Research conducted under the dissemination strategy on

electricity balancing for large-scale integration of renew-able energy (DESIRE) project suggests that the relativelysmall amount of CHP–DH capacity in the UK operatedrather differently from the schemes in Denmark. British

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CHP–DH plant tend to be built to suit minimum heatdemand in the winter and very little electricity is exportedto the grid. Many DH (community heating) schemes aresimply switched off over summer, leaving them with a lowoverall capacity factor of around 30 per cent.

There are a small number of CHP–DH schemes thathave been built with thermal stores, built either under theUK Government’s community energy programme or builtby Woking Council. In the latter case, CHP developmentshave involved building private wires so that the CHP unitscan charge consumers close to the domestic electricitytariff, thus earning much higher premiums than exportingelectricity to the grid. Thermal stores have been designedfor such CHP units in British circumstances to use the heatand the engines more efficiently rather than, as inDenmark, to maximise plant size for electricity production(Thorp, 2007).

Although there are some pressures for an expansion ofCHP–DH in the UK (which we discuss later), it is plausibleto argue that a major factor inhibiting the development ofa Danish-style CHP–DH system is the poor rates ofelectricity that CHP–DH schemes can earn for sellingpower to the grid. Instead CHP–DH units are designed tosell power to on-site consumers rather than for export.(Interviews with David Summerveld and David Barratt ofUniversity of Edinburgh CHP on 9 December 2005 andinterview with Lesley Muggeridge, Tower Hamlets EnergyManager on 28 November 2006.) A further issue is that itcan be expensive for small generators to obtain connectionsto the electricity grid (Interview with Michael King, CHPAssociation 19/09/2006).

Of course, a major factor inhibiting the growth of aDanish-style CHP–DH system is the absence of strongplanning rules favouring this strategy. There has beenplanning guidance to require conventional power stationsto use CHP through Governmental planning policy advice,for instance in para 22 of Planning Policy Statement 22(Department of Communities and Local Government,2006, p. 9). However, in practice this only applies tosituations where there happens to be sufficient consumers.This is no substitute for inducing power station developersto build plant in areas where there is sufficient heatconsumption. There is one major power plant currentlybeing considered, in Barking in London, where there aresufficient heat consumers to insist on CHP–DH beingimplemented. There are possibilities that other combinedcycle gas turbine power stations being built have heatmarkets to which they could deliver a significant amount oftheir heat load, although there are question marks aboutthe ability of the planning system to have sufficientknowledge to action this development.

There are no Danish-style regulations requiring con-sumers themselves to be supplied by DH. Indeed, currentlythere are not even any rules requiring that new andrefurbished housing developments must be served by DH(in areas where natural gas supplies are available).Certainly, such rules would help achieve the UK’s long-

term goals of building up renewable energy supplies in thata system of CHP–DH would, as earlier discussed, reducethe costs of absorbing large quantities of fluctuatingrenewable energy supplies. It should be mentioned herethat planning rules exist outside of the liberalised electricitymarket, but changes in these planning rules (for examplerequiring the establishment of DH networks) will have asignificant effect on electricity markets. The Governmentcurrently has a target of supplying 20 per cent of electricityfrom renewable energy sources by 2020. The Danish systemof flexibly operating CHP–DH with thermal stores wouldcertainly begin to offer significant help as this target isreached. It is therefore desirable that the development ofthis sort of system should be part of UK national energyplanning and that planning laws and financial incentivesshould be reoriented towards achieving such objectives.There are some contemporary changes in planning

practice that will encourage the development of CHP inbuildings. An increasing number of local authorities haveadopted planning rules requiring new and refurbishedbuildings to reduce their carbon emissions by 10 per centby using on-site renewable sources. This has encourageddevelopers to look for energy efficiency measures, includingCHP. This happens because developers, when faced withhigh costs of achieving targets to supply on-site renewableenergy, prepare building plans, which are associated withan increased emphasis on reducing energy use. The logic ofthis is that the less energy the buildings use, the lower willbe the cost of supplying a given percentage of this energythrough renewable sources.The Greater London Authority is implementing the ten

per cent target (known often as the ‘Merton rule’), andplans to extend the target so that renewables should reduceon-site greenhouse gas emissions by 20 per cent (GreaterLondon Authority, 2007). In addition the London EnergyPartnership, which is supported by the GLA, is promotingthe use of energy service companies (ESCOs) which canorganise CHP–DH in collaboration with municipal autho-rities (King, 2007). This is a technique that has been used inDenmark to great effect, as well as co-operative ownershipof CHP systems, something that we shall discuss later.While we would not rule out the possibilities of co-operatives in the UK to develop CHP, it is more in keepingwith British traditions that efforts be based on municipalplanning policies and collaborations between local autho-rities and private sector bodies, such as ESCOs. On theother hand, there are, as we now discuss, no Danish-styleincentives to supply electricity to the grid from CHP units.We shall now look at possible solutions to the problems,beginning first with a solution that requires no furtherchanges in Balancing and Settlement Code (BSC) rules.

5. ‘Aggregation’ of small CHP–DH units

There are theoretical possibilities in the UK for smallCHP–DH plants with thermal stores to ‘aggregate’ and actas a virtual big power unit that can be big enough to sell

ARTICLE IN PRESS

4The UK Government has a formula for measuring the minimum

energy efficiency to be achieved by a CHP plant in order to qualify for

incentives. See www.chpqa.com

D. Toke, A. Fragaki / Energy Policy 36 (2008) 1448–1456 1453

power directly on the main electricity wholesale markets.Then, the CHP can earn rather higher incomes for theirelectricity exports. This may, in turn, encourage developersto build larger CHP units to begin with in order to exportelectricity to the grid. CHP plant will usually have littlepossibility to engage in aggregation activities withoutthermal storage since they will not have the same flexibilityfor provision of heating services.

We have earlier described the nature of aggregation asused in Denmark. There is a key difference between our useof the term ‘aggregation’ and ‘consolidation’. As we havediscussed earlier, in the UK small CHP units obtain ratherlower prices for their electricity exports than largeconventional power stations. The techniques of aggrega-tion may overcome this problem. This is because CHPunits offer their exported power to consolidators who treatthe power as ‘negative demand’ for their electricity supplyprofiles. On the other hand large power stations can selltheir electricity directly to power markets.

The issue is, do practical conditions in the UK allowaggregation to be achieved? The DESIRE project (Lund,2007) investigated CHP and electricity market conditionsin the UK. The project concluded that if there were asufficient number of small CHP units with thermal stores inthe UK there are no practical reasons preventing thesegenerators from aggregating, as in Denmark’ to sell powerdirectly to the power markets and receive the same levels ofprices as big power stations (Toke and Fragaki, 2007). Asexplained in Section 3, thermal stores deal with themismatch between electricity and heat demand. As a result,firstly, the CHP engine can run more hours because it canalso run when the heat is not needed and, secondly, theengine can run when the electricity prices are high, thusimproving the economics of the CHP plant. Therefore, theeconomic performance of the CHP plants would beenhanced if CHP plant operators use thermal storage tooptimise the timing of the sale of electricity to wholesalepower markets through aggregated despatch.

Assuming an aggregation system exists, then, the cost fora CHP plant to take part in an aggregation would beminimal set up costs, which would be a few thousandpounds. These set-up costs are communications andcontrol interfaces only, which are just standard industrialelectronics. This assumes that the CHP is already equippedwith enough storage and generation to operate flexible andgood control gear for ‘normal’ operations that theaggregator can just plug into. It is clear that existing andfuture CHP operators will only be interested in participa-tion in this type of aggregation activity if they can derivevalue from it. Therefore, the maximum costs that a CHPplant would be willing to incur would be the differencebetween the value that they would receive from thetraditional export and the value for their electricity thatthey would receive through the aggregation mechanism(Toke and Fragaki, 2007). One megawatt or even halfmegawatt would be enough capacity for a CHP plant totake part in the aggregation. This is only because, given the

expected costs involved, a cost/benefit analysis of theparticipation of a plant would probably show that it wouldnot be viable for smaller plants to participate. This is onlybecause, given the expected costs involved, a cost/benefitanalysis of the participation of a plant would probablyshow that it will not be viable for smaller plants toparticipate. Further research will be needed to assess theminimum size of CHP plant that is economic foraggregation techniques.The aggregation system could be implemented in UK as

described below.Each CHP operator involved in the aggregation would

have to offer any exported electricity to the central agency/company, which would then sell that electricity in advanceon the despatch market. The central agency would need tobe a licensed supplier. The CHP operator would need apower purchase agreement to sell the electricity to alicensed supplier. Many CHP schemes have this type ofagreement at the moment but the CHP plant would have tohave this agreement with the same supplier that the othermembers of the aggregated group had chosen. Theoperator of the despatch aggregation would have tocontinuously recalculate the ability of the plant to generate(or not generate) based on what is in the thermal store, butthis could be done using communications and controlsystems which are just standard industrial electronics.However, the central agency could make precise predic-tions about what power was going to be delivered (in bulkat a particular time). The central agency could register withthe BSC, yet they could avoid penalties for despatchfailure. Hence, they could trade in the main powerexchanges and derive similar tariffs for electricity sales tothat offered to big power stations that are without thediscount that is taken off payments to small CHP operatorsat the moment.Ideally, such an operation needs to have a combined

CHP capacity of over 50MWe available for despatch. Ofcourse, at the moment there are currently not enough CHPunits with thermal stores operating, let alone ones that aregeared towards generating significant proportions ofelectricity to the electricity grid.A limitation on this strategy is that this strategy would

only work with CHP with thermal stores, which wouldinvariably be associated with the domestic or buildingsheating market. This of course leaves out what is currently94 per cent of the CHP installed capacity. While one wouldhope that the proportion of CHP–DH plant as comparedto total UK CHP would increase, this is always going toleave out a large part of the CHP market. Hence, manywould argue that some sort of incentive for exported powerneeds to be offered to all ‘good quality’4 CHP units.

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6. British regulatory reform—a ‘feed-in tariff’ for CHP?

A regulatory reform agenda in the UK could include ameasure ensuring that CHP–DH plant receives the samesort of payments for electricity exports as conventionalpower stations receive on the power exchange markets.Perhaps this could be modelled on the Danish ‘triple tariff’that used to pay premium prices to electricity from CHPplant generating at times of peak demand, although thissystem is more or less phased out now and replaced byaction at the spot market. This would also encourageinvestment in thermal stores as well as incentivising CHPelectricity exports at the time when it is most needed. Inaddition to this, there could be reform of the distributionuse of system (DUoS) charges that are paid to thedistribution system operator. DUoS was meant to helpassist development of distributed generation, by cutting thecharges on maintaining the central parts of the infra-structure which the distributed energy units will not beusing. However, CHP developers still find it difficult tosecure what they see as reasonable quotes for connectionfrom electricity distributors who, as monopolies, aredifficult to challenge.

The inception of a feed-in tariff that assured guaranteedrates for electricity sales from CHP–DH units for anextended period (e.g. 15 years) would give much moreconfidence in the long-term returns on capital investmentin CHP–DH. This is especially necessary in view of therelatively high capital cost of CHP–DH compared withother fossil fuel generating plant. Toke (2008) emphasisesthe importance of giving long-term guarantees on incomelevels if capital intensive technology is to be encouraged toachieve reductions in carbon emissions.

Guarantees of long-term income cannot be achievedthrough market-oriented solutions, such as ‘aggregation’ ofCHP units with thermal stores, however desirable that maybe in itself. There is nothing intrinsically incompatibleabout feed-in tariff and liberalised electricity markets. Theycoexist in EU states such as Spain and The Netherlands inthe form of support for renewable energy. In fact, therewas something that resembled a feed-in tariff as aconsequence of the 1983 Energy Act. This required thethen nationalised electricity system to pay independentgenerators on an ‘avoided cost’ basis. However, thisprocedure disappeared along with electricity privatisationin 1990. Since then the UK Government has not beenfavourably disposed towards the idea of feed-in tariffs, forexample in incentivising renewable energy. It has preferredwhat it has seen as being more market-oriented schemes,such as the renewables obligation. However, these havebeen subjected to considerable criticism that they are not ascost-effective as feed-in tariffs and that they do notencourage smaller, locally owned generators (Meyer,2003; Butler and Neuhoff, 2003; European Commission,2005; Toke, 2005, 2007; Mitchell et al., 2006). On the otherhand, the notion of feed-in tariffs has moved up slightly onthe UK political agenda with the formation of a coalition

of supporters for the concept to support small andemergent renewable energy technologies (Toke, 2007).It would be very wrong to argue that there is some ‘ideal’

perfectly competitive notion of a liberalised electricitymarket. As has been mentioned earlier, the nature of thecompetition has to be described in what are quite byzantinerules concerning procedures. Within that it is accepted thatthere have to be rules set up to cater for environmentalobjectives. It is a matter of debate as to whether CHPschemes should be afforded guaranteed tariff levels.A relative of the idea of a feed-in tariff, in the sense in

giving confidence in a future income stream from sales ofelectricity exports, is the so-called ‘Whitehead’ proposals toguarantee the achievement of a minimum spark spread(ILEX, 2005). The spark spread is the relationship betweenthe cost of fuel inputs and the price for which electricityproduction can be sold. This proposal has not beenimplemented. One issue was that most of the subsidieswould go to existing CHP plant rather than new plant.However, a feed-in tariff designed specifically forCHP–DH plant would cater for CHP–DH plant and cutdown the expense of such an instrument compared topaying it out to all CHP generators. It is, after all, smallerCHP (DH) plant that suffer from the rules of the BETTAmarket as described earlier and it is an area that is likely tobe expanded if there are possibilities for being affordedgood prices for power exports.The Whitehead proposals were based on the assumption

that the Treasury would offer the funds that would act as areserve to subsidise CHP if the ‘spark spread’ fell below thereserve price of £12. However, a ‘feed-in tariff’ could befunded through a levy on electricity consumer prices (apublic service obligation), much as in the way thatrenewable energy is subsidised in the Irish Republic.On the other hand, Government policy, in practice,

seems to be shying away from giving additional incentivesto CHP. The draft Government climate change Supple-ment to PPS1 published in December 2006 spoke ofpromoting ‘low carbon options’ but CHP did not appear asa major priority. CHP was evaluated as being less costeffective than other contributions (Department of Com-munities and Local Government, 2006; p. 66).Three points could be made here. First, it should be

mentioned that the cost assumptions of technologies suchas solar photovoltaics (pv) were based on what they mightcost in 2020–2025 rather than what they cost now. Second,the evaluation was based on a comparison with micro-CHPused in domestic dwellings (personal communication withProfessor Dennis Anderson 22/10/2007). This is an (as yet)largely unproven technology. On the other hand, in thisarticle we are discussing gas engine CHP that would servewhole blocks of dwellings or even large estates andcomplexes and which also has a reputation in Denmarkof reliability and energy efficiency. Third, such compar-isons do not take into account the current relativecheapness (compared to some emergent renewable tech-nologies) of providing energy needs, regardless of costs of

ARTICLE IN PRESSD. Toke, A. Fragaki / Energy Policy 36 (2008) 1448–1456 1455

carbon abatement. This means that CHP–DH willneed much lower incentives compared to something likesolar pv.

There is an argument that energy—in buildings is a vitalresource for carbon abatement and that a range ofclean(er) energy technologies need to be deployed, includ-ing solutions such as solar pv, solar thermal, micro-windturbines, ground source heat pumps, biomass boilers(possibly alongside gas CHP), biomass CHP and alsogas-fired CHP with DH. Indeed analysis of building plansthat have been adopted to fit in with local renewablestargets for new buildings in the Greater London Authoritysuggests that energy efficiency techniques, including CHP,are by far the biggest contribution to the carbon reductionsachieved by these targets for on-site renewable energy(Day, 2006). As we mentioned earlier, developers try toreduce the cost of installing on-site renewables by makingthe buildings much more energy efficient, thus reducing theoverall amount of energy that the building will consume(and thus the amount of investment in renewables).

7. Conclusion

The research question contained in the title of the articlewas whether the promotion of CHP–DH conflicted withthe existence of a liberalised electricity market. The notionof ‘aggregation’ of electricity production’ as describedearlier (using CHP with thermal stores) could, if combinedwith strong planning rules designed to mandate thecreation of DH schemes, create financial conditionssuitable for significant growth in CHP–DH in the UK.This would be in the context of a liberalised electricitymarket.

Even the inception of a feed-in tariff for CHP–DHwould not destroy what we know as a liberalised electricitymarket. This is because the liberalised market is alreadyconstituted in a world of carefully constructed markets,which among other things, absorb environmental andsocial criteria in the form of specially designed incentivestructures. Feed-in tariffs can be effective means ofachieving environmental objectives. A feed-in tariff forCHP–DH could be an instrument that could ensure amajor take-up in CHP–DH, again, if it is combined withplanning policies that oblige the spread of CHP–DH intonew and old buildings. It could form a necessary part of arange of incentives needed to reduce carbon emissions inthe buildings sector and, moreover, create a more flexiblebasis for integrating increasing quantities of fluctuatingrenewable energy supplies into the electricity grid.

The notion of a feed-in tariff for CHP–DH could gotogether with ‘aggregation’ techniques if the feed-in tariffassured a minimum price level (perhaps in comparison tothe spark-spread) while aggregation arrangements couldallow the CHP–DH units to earn higher prices when theyare available on the market.

Whichever precise path is taken to encourage CHP–DH,it is also apparent that the development of the flexible

generation capacity represented by CH–DH will help in thereduction of costs associated with absorbing large quan-tities of fluctuating renewable energy sources into the grid.It will be some time before the levels of fluctuatingrenewables are high enough to increase the costs ofabsorbing them. However, it is also the case that it willtake a long time to build up a CHP–DH system withthermal stores. This suggests that more attention needs tobe given to encouraging this system in the near future.Researchers can learn from this article that the Danish

system can be widely applied to other countries regardlessof the extent of their transition to liberalised electricitymarkets. It can also be expected that considerabledevelopment of CHP–DH can be achieved from adoptionof the strategies recommended in this article.

Acknowledgements

The research that led to the writing of this article wasconducted under the DESIRE project (Disseminationstrategy on Electricity balancing for large Scale Integrationof Renewable Energy). The DESIRE project was funded bythe EU’s FP6 programme and comprised a consortium ofuniversities and commercial bodies from several EU statesco-ordinated by the Department of Development andPlanning at Aalborg University, Denmark. We are gratefulto Dr. Robert Everett of the Open University Energy andEnvironment Research Unit for comments which improvedthis article, and also to the anonymous peer reviewers.

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