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Electric Power Systems Research 77 (2007) 1148–1159

Distributed resources and re-regulated electricity markets

Thomas Ackermann ∗Royal Institute of Technology, Department of Electrical Engineering, Teknikringen 33, 10044 Stockholm, Sweden

Available online 15 September 2006

bstract

This paper briefly defines distributed resources (DR) and discusses the current status of DR. The main focus is on discussing the value DR canrovide to re-regulated electricity markets. DR can, under certain circumstances, help to significantly reduce the main problem of re-regulation, i.e.arket power. Distributed generation and demand-side resources may, even if only small quantities in terms of size of the entire market are utilised,

e able to help to significantly reduce market power. This results in a significantly more efficient market. To achieve such benefits, however, DR

ust be in operation during times when market power issues are likely to arise. To a certain extent this is the case as demand-side resources are

sually independent of established generation companies. In addition, many business cases for DG require DG to actually operate to capture theecond revenue.

2006 Elsevier B.V. All rights reserved.

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eywords: Distributed generation; Distributed resources; Electricity market; D

. Introduction

The main aim of this paper is to analyse the impact of DR onarket power. The paper is structured in the following way: Sec-

ion 2 presents a definition of distributed generation, distributedesources and re-regulation and discusses the current status ofistributed generation. Section 3 discusses the value of DR ineregulated markets. The main focus is on the cause of marketower, e.g. demand inelasticity, and the influence DR can haven the different reasons for market power. The section closesith a short case study based on Western Denmark.

. Definitions and current status

.1. Distributed generation

In the literature, a large number of terms and definitions aresed in relation to distributed generation (DG). For example,nglo-Saxon countries often use the term “embedded gener-

tion”, North American countries the term “dispersed genera-ion”, and in Europe and parts of Asia, the term “decentralisedeneration” is applied for the same type of generation.

∗ Tel.: +46 706639457.E-mail address: thomas.ackermann@ieee.org.

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378-7796/$ – see front matter © 2006 Elsevier B.V. All rights reserved.oi:10.1016/j.epsr.2006.08.006

lation; Re-regulation; Market power, liberalisation

In the literature, there are large variations regarding the def-nition for DG. This paper will follow the general definitionuggested by Ackermann et al. [1]:

Distributed generation is an electric power source connecteddirectly to the distribution network or on the customer sideof the meter.

The distinction between distribution and transmission net-orks is based on the legal definition. In most competitivearkets, the legal definition for transmission networks is usu-

lly part of the electricity market regulation. Anything that isot defined as transmission network in the legislation can beegarded as distribution network. The definition of distributedeneration does not define the rating of the generation source, ashe maximum rating depends on the local distribution networkonditions, e.g. voltage level.

Furthermore, the suggested definition of distributed genera-ion by Ackermann et al. defines neither the area of the powerelivery, the penetration, the technology, the ownership norhe treatment within the network operation as other definitionsometimes do.

.2. Distributed resources

According to Moskovitz, distributed resources are “demand-nd supply-side resources that can be deployed throughoutn electric distribution system (as distinguished from the

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ransmission system) to meet the energy and reliability needsf the customers served by that system. Distributed resourcesan be installed on either the customer-side or the utility sidef the meter.” [2].

Distributed resources consist of two aspects: distributedeneration, located within the distribution system or on theustomer-side of the meter, and demand-side resources, suchs load management systems, to move electricity use from peako off-peak periods, and energy efficiency options, e.g. to reduceeak electricity demand, to increase the efficiency of buildingsr drives for industrial applications or to reduce the overall elec-ricity demand.

.3. Re-regulation

At present more than 100 countries are restructuring theirlectricity market. The details of this restructuring vary signifi-antly between the countries. Some countries have only adjustedome roles and functions, others have chosen a system thatntroduces competition in power generation and supply, therebyffering customers the possibility to choose their own supply.sually, the introduction of competition is called liberalisation;owever, the level of competition can vary significantly betweenifferent countries. Some countries have privatised public gener-tion assets while in other countries privatisation is not an issue.n the literature, the terms restructuring or deregulation mayndicate either liberalisation or liberalisation and privatisation,ut as neither competition nor privatisation makes regulationbsolete, the term re-regulation seems to be a more exact termhan deregulation.

.4. Current status of distributed generation

The analysis of the current status of DG is rather complicateds each country or organisation uses different definitions forG. Table 1 provides an overview of the most recent DG status

eports. It is obvious that there is no good agreement betweenhe different reports. Most studies, however, agree that Denmarknd the Netherlands have the highest share of DG in the world,ith a penetration of 23–60% depending on the study.

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able 1verview of DG status reports, DG share of total generation capacity (DG share of to

echnology CIRED (all) CIGRE (all) EnergieNed (all) WADE (all)

ource [4] [5] [6] [7]K 8.7% – ∼7% 5.7% (6.2%weden – – ∼5% –inland – – ∼15% 36%enmark 25.0% ∼37% ∼2% 50%SA – – – 8% (5.8%)alifornia – – – –ew York – – – –ustralia 12.3% ∼3.5% – –ermany – – – –etherlands 28.0% ∼40% ∼23% 39%U-15 – – – –orld – – – 7%

Research 77 (2007) 1148–1159 1149

Different understanding of renewable generation, CHPnd on-side or industry self-generation can cause variationsn the statistics. Some national statistics, for example, sum-arise all renewable generation technologies, including hydro

eneration. Hence, it is not clear which units are connectedo the transmission or the distribution network. Similarly,sually all CHP is summarised in one statistic. However,n some countries CHP is rather large and therefore mainlyonnected to the transmission level, in other it is more on aocal base and therefore connected to the distribution level.

any of the large CHP units connected to the transmissionystem, however, are connected on the customer-side ofhe meter (industry self-generation) and should therefore beonsidered DG.

. Value of distributed resources for re-regulatedarkets

Market regulations between different countries can vary sig-ificantly, and so can problems of market regulations. One mainroblem related to re-regulation, however, has emerged overhe past years: market power. As opposed to other re-regulatedf former monopoly industries, e.g. the airline or telephonendustry, in re-regulated electricity markets the market powerroblem very often continues to exist after introduction ofe-regulation. In almost all re-regulated electricity markets, e.g.alifornia [12–15], Scandinavia [10,18,19] and Australia [11],

nvestigation have been made of the use of market power inne or more of the different markets within the re-regulatedlectricity sector, i.e. spot market, balancing markets ornancial markets. Due to the complexity of markets in generalnd electricity markets in particular, it is very difficult tolearly prove the exercise of market power. Most investigationsowever have concluded that the invested incidents of extremer unnormal market price behaviours most likely involvedome form of market power. In particular the investigations

fter the California power crisis in 2000/2001, which includedhe analysis of internal documents of various market partic-pants, see [16], show clear evidence of the use of marketower.

tal production)

IEA (CHP) DTI (CHP) DTI (renewable) DTI (all)

[8] [9] [9] [9]) (5.8%) – – –

(6.0%) – – –(35.8%) – – –(62.3%) 19% (26.7%) 19.5% (12.2%) 38.6% (38.9%)

6% – – –– 11.3% (18.7%) 6.1% (5.9%) 17.4% (24.8%)– 14.1% (20.0%) 3.0% (2.9%) 17.1% (22.9%)– – – –– 28.0% (18.7%) 11.0% (4.0%) 39.0% (23.0%)

– (52.6%) 93.0% (76.9%) 4.7% (1.6%) 97.7% (78.5%)– (11%) – – –

– – – –

1 stems Research 77 (2007) 1148–1159

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In the following, the possible causes of market power areriefly presented and then the impact of DR on market power isiscussed in more detail.

.1. Demand inelasticity

Schwepp et al., the fathers of spot pricing of electricity [3],lways assumed that spot pricing would require the customerso know the real-time prices and thus enabled them to respondo the price development. Today’s electricity markets, however,ave one feature that makes them very special compared to mostther commodity markets: the demand does not react to priceariations; hence the demand is almost price inelastic.

The price elasticity of electricity demand is thereby defineds the change in the quantity of electricity in response to a per-entage change in the price of electricity:

lasticity ={

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In the context of this analysis, price elasticity of aggre-ated electricity demand refers to the immediate reaction of theemand variation in electricity prices.

Example price inelasticity: In the Swedish power exchangeonly 400 MW (1.4% of peak demand) of aggregated demandrespond to high prices, slightly more in the Norwegian marketand about 150 MW (1.8% of peak demand) in the Victorianmarket area of the NEM in Australia.

It is often argued that a higher demand participation cannote achieved because electricity is such an elementary commod-ty for today’s needs, that customers are willing to pay almostny price. There are, however, examples of higher demand-sidearticipation. California, for example, has achieved an averageggregated demand reaction of 8.3% of peak demand duringeak times.

The inelastic price elasticity of the aggregated electricityemand can cause significant problems in electricity marketss will be explained next. Fig. 1 shows the market equilibrium

or inelastic demand and a supply curve during peak demandnd comparatively low reserve margins.

During such a period the slope of the supply curve close to theeak demand Q1 can become very steep. Under the assumption

ig. 1. Market equilibrium with inelastic demand (note: numbers 1 to 11 standor different companies and their supply offers.).

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ig. 2. Market equilibrium under withholding of generation capacity (note:umbers 1 to 11 stand for different companies and their supply offers.).

hat no market power is used, the steep slope of the supply curves the result of high (long-run) marginal costs of peaking genera-ion. Now, based on Fig. 1 a supplier who supplies the quantity 6amount between 5 and 6) will have a profit described by the greyrea ABCD, which depends on his marginal cost curve between

and C.Suppliers can now influence the market equilibrium by with-

olding generation capacity from the market. In Fig. 2, the sameupplier is withholding a small part of his supply and is onlyupplying the quantity 6* (amount between 5 and 6*).

As a result, the market price increases significantly from P1o P2, and its profit increases from the area ABCD to the greyrea A*B*ZD. In other words, the increase in profit for the with-olding company is:

P = P2 − P1S − P1 − MC × WC (2)

here FP = financial profit of withholding; P1 = market clearingrice without withholding capacity; P2 = market clearing priceith withholding capacity; MC = marginal costs; S = actual sup-ly, i.e. used capacity; WC = withholded capacity; AC = totalvailable capacity, whereby AC = S + WC.

For a supplier, it is profitable to withhold supply as long as hisrofit increase as a result of a higher market price (area AA*B*X)s larger than the profit it loses due to reduced generation (areaXBC), or:

2 − P1S > P1 − MC × WC (3)

It is important to emphasise that withholding generation iseneficial for all generation companies, as long as the aboveentioned relation in Eq. (3) is given for the withholding com-

any. Therefore, in markets where market participants haveather level market shares and similar marginal costs, it can bessumed that not only one supplier but all suppliers will start toithhold a small share of their supply.

Example California: The Californian power market showedno significant market concentration before the power crisisstarted in 2000. However, during the power crisis in Cali-fornia up to 40% of the installed generation capacity was

stems Research 77 (2007) 1148–1159 1151

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declared technically unavailable, which resulted in rollingblackouts. Many argue that a substantial proportion of thisgeneration capacity was withheld from the market on pur-pose. [17]

However in a market with significant market concentration,he process of withholding generation is likely to start much ear-ier, i.e. at lower demand levels, as a much lower price elasticity isequired for withholding of generation to become beneficial. Thempact of high market concentration on markets is well known;herefore regulations and competition laws all over the worldim at limiting market concentration. Main strategies to reducer limit high market concentration focus on splitting up formeronopoly companies and on controlling merger and acquisition

ctivities.The problem of market power can get totally out of hand

hen the last supplier, who sets the equilibrium price, realiseshat he is the last supplier in the market. In this case, he will sethe price at the maximum allowed in the market or, if there is norice cap, at a level that he hopes will not provoke investigationsy the regulator.

Example Australia: In the Australian’s National ElectricityMarket (NEM), generation companies are able to continu-ously rebid until 5 min before delivery. This allows generatorsto actually test with rebids if they are the final supplier, whichhas resulted in extremely high prices. [11]

In this respect, it is often argued that bilateral contracts,etween generators and retailers or customers outside any powerxchange (PX), will remove incentives to withhold generation.uch contracts require physical power delivery; otherwise theeneration company has to pay the difference between the mar-et price and the power price specified in the bilateral contract.ence, the generation company will not gain anything fromithholding generation.If we consider Fig. 1, bilateral contracts will reduce the

emand at a PX, but at the same time less supply is offeredo the PX,1 because the generation capacity is allocated to fixedontracts. As a result, the situation at the PX does not changen principle, i.e. a steep slope of the supply curve close to the

aximum demand at the PX. Therefore, some generation com-anies may still find it beneficial to withhold generation capacitys long as Eq. (3) is fulfilled for them. The main difference fromarkets without bilateral contracts is that less market volume is

ffected by the price increase.In a similar context it is also often argued that a too extensive

ithholding of generation will attract new generation capacity.ence, generation companies will control their own behaviour

nd will keep the price manipulation within certain limits.2

s demonstrated by the California energy crisis and otherncidents, such self-control has not worked very reliably inhe past. One reason certainly is that a few incidents are not

ufficient to encourage the construction of new, large-scaleeneration.

1 Assuming the PX is not mandatory.2 The market will still experience inefficiency due to higher prices, though.

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ig. 3. Market power and congestion (TC = transmission line congestion).

.2. Impact of congestion

Transmission line congestion can result in a local market arean which one or more market players might be able to gain local

arket power to influence market clearing prices, see also Fig. 3or illustration. Local market power is especially hard to dealith. It is caused by transmission line constraints and results

n limited local market participation of generators from outsidehe constrained area. Investment costs in the generation industryre high and have a rather long pay back period. Therefore,he market may need a long period of high prices until neweneration companies decide to move into a new market or areand thus eventually reduce the market power.

As the California energy crisis showed [16,14] “fictive” net-ork congestions can also be caused, or network congestions

an be increased, by creating “fictive” loads or “fictive” usagef transmission capacity. Such strategies will not work in a simi-ar way in the other markets, e.g. the Scandinavian market has noradable transmission rights (FTRs) and the creation of “fictive”oads will result in imbalance payments.

While it is not possible to analyse all different regulationssues that may influence the above strategies within this docu-

ent, it is important to remember that high market concentrationan lead to a very inefficient market operation during periods ofongestions. In other words, the financial benefits of transmis-ion line congestions for the company with a large local markethare might be higher than any penalty introduced by the marketegulation.

For a company that is able to gain local market power, itill be economically beneficial to influence transmission line

ongestions as long as:

AP2 − LAP1S > LAP1 − MC × WC + P (4)

here LAP1 = local area market clearing price without with-olding capacity; LAP2 = local area market clearing price withithholding capacity; P = any form of financial penalty thatight incurred by using different strategies to create “fictive”

etwork congestions.

.3. Impact of reduced reserve markets

Re-regulated markets provide little incentive to install or keepeak capacity available. In Sweden, for example, more than

1152 T. Ackermann / Electric Power Systems

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pmresponse or by additional distributed generation, the market pricewill drop by about 4%.

Another source analysed the emergency demand responseprogram operated by the New York ISO during the summer of

ig. 4. Effect of elastic demand on market equilibrium (note: numbers 1 to 11tand for different companies and their supply offers.).

037 MW of peak capacity, or about 10% of installed capac-ty, was dismantled until early 20023 [20,21]. The main reasonor this is that companies consider the economic risk of spareapacity too high. Different approaches have been developed torovide incentives to keep or build additional capacity. Usually,hese approaches provide some kind of capacity payment that isndependent of the actual use of the capacity, in order to reducehe economic risk to generation companies. As it is very difficulto determine how much capacity is required to secure supply atll times, these solutions will not provide an economically effi-ient solution.

Finally, it is important to point out that congested areas canmerge independent of even reasonably high reserve margins ashe reserve margins may be located outside the congested areas.ence, high reserve margins are not necessarily an insurance

gainst market manipulations.

Example PJM market: The market has encountered pricespikes between US$300/MWh–US$900/MWh; some ofwhich have been caused by withholding generation in con-gested areas. The reserve margin in the PJM market is about19%, which can be considered high [22].

.4. Distributed resources as a means to reduce marketower issues

Distributed resources can be split into demand-side activitiesnd distributed generation. Both aspects might be able to reducearket power issues, which will be discussed in more detail

elow.

.4.1. Demand-side resources

Demand-side resources provide the means to increase

emand elasticity if customers are able to see and react to mar-et prices. Fig. 4 shows an elastic demand curve, i.e. demand

3 However 1050 MW of the above mentioned 3037 MW were already backn operation during the winter 2002/2003, due to special payments from thewedish TSO. The TSO in Sweden is responsible for the security of supply.uring the first months of 2003, an additional 600 MW were restarted with

pecial financial support from the TSO. The available peak capacity in Sweden,owever, is still around 1400 MW less than a few years ago. F

Research 77 (2007) 1148–1159

esources, will reduce or completely take away the benefits forenerators to withhold generation capacity.

This is due to the fact that withholding generation capacityill only result in a very small price increase, which will not

ompensate for the lost profits due to less power generation,ee Eq. (3). Fig. 4 also shows that in the case of a very steepupply curve, a comparatively small price elasticity is sufficiento eliminate the benefits of withholding generation.

.4.1.1. Impact of elastic demand.3.4.1.1.1. Case studies. Within this project, the author has

ried to obtain examples of electricity price elasticities, in par-icular for congested areas. Many markets, however, keep thisata confidential because their publication may encourage com-anies to withhold generation during a similar situation in theuture. In the following, however, examples from the USA andustralia are given.3.4.1.1.2. California and other US experience. An inves-

igation by Kyla Datta, presented in [22], shows that the supplyrice elasticity during the California energy crises in 2000 wasxtremely high at the end of the bidding stack. In an average, a% lower demand led to a 10–12% price reduction. In the caseresented in Fig. 5, a demand reduction of 500 MW – approxi-ately 1.7% of demand – lowered the market clearing price byS$165/MWh, or 22%. The next 500 MW demand reductionould have lowered the price by “only” US$85/MWh, or 17%.Therefore, the first 500 MW demand reduction or increase of

eneration would have resulted in a price drop of US$165/MWh,hich would have saved the market on that day at this partic-lar hour a total of US$4,638,810, or in other words each kWaved during this hour or additionally generated had a value ofS$9.27.According to the same source, typical price elasticity during

eak situations in other U.S. power markets is around 4%. Thiseans that if the peak demand is reduced 1% either by demand

ig. 5. Market supply elasticity, summer peak hour (29 June 2000) source: [22].

T. Ackermann / Electric Power Systems Research 77 (2007) 1148–1159 1153

Table 2Summary of price events in the national electricity market between 1 January and30 June 2001, values in AUS$, exchange rate 2/2003: 1 AUD$ = 0.55 Euro = 0.59US$, source: [25], p. 26

Trigger prices $500 $750 $1000 $1500 $2000Total number of hours 19.75 16.1 14.5 11.5 11.4Number of affected days 12 12 12 12 11Number of events 46 51 52 43 42Average length in hrs 0.43 0.32 0.28 0.27 0.27

Table 3Impact of distributed resources on specific events, values in AUS$, exchangerate 2/2003: 1 AUD$ = 0.55 Euro = 0.59 US$, source: [25], p. 26

Event 1 Event 2 Event 3 Event 4 Event 5

Average priceduring event

$960.7 $1770.8 $2942.0 $703.5 $3774.9

Impact of:100 MW 5.6% 5.3% 13.8% 7.6% 61.0%250 MW 22.6% 30.3% 66.9% 15.1% 78.9%

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vifwhen withholding DG generation capacity. Both aspects will bediscussed in more detailed next; however, possibilities to coun-teracting the impact of DG is discussed first.

5 The analysis does not take into account that generators in Australia can rebiduntil the final delivery, hence generators will most likely bid in a different way

500 MW 70.5% 86.4% 83.3% 32.5% 86.2%1000 MW 93.8% 96.2% 91.8% 88.9% 91.4%

001 [23]. During a 4-day heat wave in early August partici-ants in this program helped to reduce total load by 3.5% whichesulted in a 32% lower wholesale electricity price than withouthe demand-side program. It is estimated that the program savedS$13 million while it cost US$4.2 million [23].Finally Lafferty et al. [24] report the result of the largest

ynamic pricing program in the USA, operated by Georgiaower. The utility published the day-ahead prices as well as

he hour-ahead prices, based on expected hourly marginal costs,n the Internet and emailed them to interested parties. In gen-ral, the participants in the hour-ahead program exhibited greateremand elasticity than day-ahead participants. Hour-ahead par-icipants had a demand elasticity of 15.4, 17.1 and 18.9% forrices of US$250/MWh, US$500/MWh, and US$1,000/MWh,espectively. For very high prices, in particular industrial cus-omers in the hour-ahead program reduced their electric loadignificantly: 29% for price levels between US\$300–350/MWhnd 60% for price levels between US$1500–3000/MW.

3.4.1.1.3. Australian experience. Table 2 presents a sum-ary of high price events that occurred in the Victorian-NSW

art of the NEM between 1 January 2001 and 30 June 2001. Itan be seen that the total number of hours of such events wasery low, i.e. 0.04% of the time prices reached AUS$5004 orore. Also, the average lengths of each event was rather short,

rom 0.43 h for prices of AUS$500 or more to 0.27 h for prices ofUS$2000 or more. The start up of additional peak generationapacity for such a short period would have been expensive.

Table 3 shows the impact of price elasticity, based on anncreased demand response for certain events that occurred dur-

ng the same period on the NEM. In event 1, a 250 MW demandesponse – about 1.4% of peak demand – would have savedUS$217/MWh, or in other words a 250 MW demand response

4 Approximate exchange rates: 1 AUD\$ = 0.55 Euro = 0.59 US\$.

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ig. 6. Effect of DG on market equilibrium (note: numbers 1 to 11 stand forifferent companies and their supply offers.).

sed for 5 min during a time with a demand of 18 GW would havead a value of AUS$1302/MW or AUS$1.3/kW. In event 5, a50 MW demand response would have saved AUS$2980/MWh,r in other words a 250 MW demand response used for 5 minuring a time with a demand of 18 GW would have had a valuef AUS$17,880/MW or AUS$17.8/kW.5

The study also shows that a demand response of 1000 MWabout 5% of peak demand – would provide price drops of

8.9–96.2%. This might be influenced by the fact that the Aus-ralian market is a mandatory market; hence generation compa-ies with bilateral contacts perhaps bid very low into the marketo be scheduled during the time in question.

This shows the comparable small magnitude of demandesponse that is required to significantly improve the overall effi-iency of the market. The comparatively short lengths of suchxtreme price events, see Table 2 will not provide sufficientncentives for new peaking capacity.

.4.2. Distributed generationDG can provide similar benefits as demand-side participation

nder certain circumstances. As Fig. 6 shows, a small amount ofdditional generation with marginal generation costs lower thearket equilibrium price during peak demand, which will at least

artly remove the incentives to withhold generation, because itill move the supply curve to the right, thereby reducing the

lope of the supply curve in the point of the equilibrium price.This is of course a trivial observation, and DG will only pro-

ide such benefits if the operator of the DG unit is either anndependent market actor, i.e. it will not receive any benefitsrom withholding the DG unit,6 or it will be somehow penalised

f demand response occurs. As mentioned before, demand response will reducehe incentives to withhold generation, hence the price drop might be higher thanalculated in this study.6 According to Eq. (3) even a new, independent actor might get some benefitsf withholding some of his generation, but in total the new actor must generatedcertain amount to capture a profit, hence the overall market price will alwayse reduced.

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Price elastic demand or DG will only result in a decreasedarket price if the other power suppliers do not counteract the

ction by withholding even more generation. It can, however, bessumed that suppliers always aim at maximising their profit,ence they will maximise Eq. (2). Therefore, it will not berofitable for suppliers to withhold more generation capacityo counteract any new generation, as long as there is no sig-ificant market concentration. The contrary is the case. If neweneration capacity moves the supply curve to the right, theithholding companies will earn less than optimum, hence toaximise Eq. (2) again, the supplier(s) will withhold less capac-

ty themselves than in a situation without DG. As a result, theupply curve will be moved further to the right and the marketquilibrium price will drop further.

It is important to emphasise that additional, independent cen-ralised (large) generation capacity, if located in congested areas,ill provide similar benefits as in the examples described above.ut, as Fig. 6 shows, comparatively small generation capacity

upplied during a short period can lead to a significant priceeduction, depending on the slope of the supply curve. Hence,arge generation capacity is not always required in such situa-ions and, even more important, short term price spikes caused byithholding generation capacity might provide lower incentives

han often assumed to construct new large peaking generationapacity as discussed next. For example, assume a situationnderlying Fig. 2 where withholding of generation has caused arice increase from P1 to P2. If we now assume that the marginalosts for additional peaking generation lie somewhere between1 and P2, an investment in new generation will not be profitable

or any investor as the new generation capacity will take away theenefits of withholding generation, but the market equilibriumrice will always drop below the marginal costs for additionaleaking generation, most likely to P1.7 In addition, many DGechnologies are rather flexible – small, modular – and can be

oved much faster to areas with high prices due to lack of capac-ty or where companies exercise market power.

.4.2.1. Ownership issues. As mentioned before, DG will onlyeduce market power issues if the operator of the DG unit isither an independent market actor, i.e. the operator will noteceive any benefits from withholding the DG unit, or he wille penalised when withholding DG generation capacity. Therst issue is very much related to the ownership of distributedeneration and the impact of the ownership on incentives toithhold generation capacity. If a distributed resource project iswned and controlled by a company that has either a significantarket share or, in a market with comparatively level market

hares and similar marginal costs, by one of the companies with

imilar market shares, there are no incentives to not withholdven DR projects as long as Eq. (3) is fulfilled.

If the owner of the distributed resource project, however, has aarket share that is comparatively small, than the owner needs

7 Not to mention that new peaking generation must recover not only thearginal costs but also the investment costs, hence either a larger number of

eaking events are necessary or a higher market price than its marginal costs.

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Research 77 (2007) 1148–1159

much higher price elasticity than other market participantso start to withhold generation capacity. Therefore, if indepen-ently owned DR projects are added to an existing power markethey will not have only lower incentives to withhold generationut they will also reduce price elasticity and thereby reducingncentives for other market participants to withhold generationapacity.

Now the question arises why should DR projects be devel-ped by new market participants? The common argument ishat DG projects are more attractive to new market players ashe utilisation of second revenue streams8 requires knowledgebout market areas other than the electricity market; hence tra-itional electricity market players do not consider this their coreusiness. Also, new market participants might be attracted byhe low total investment costs for many DG projects, comparedo many centralised projects. And finally it can be argued thatxisting market participants might be too inflexible to developew business areas like DR.

The analysis of the ownership of existing DG, however, isuite difficult. As wind power and CHP can be considered theG technology with the highest market, the analysis will focusn those two generation technologies. There are, however, notatistics available regarding the connection point, i.e. if the CHPr wind power units are connected to the transmission or distribu-ion network. Wind power, for example, is in Germany, Swedennd Denmark, predominantly connected to the distribution levelhile in Spain it is mainly connected to the transmission level.HP in the Netherlands and in Denmark is predominantly con-ected to the distribution level, but very little can be said ineneral terms about the other countries.

Table 4 therefore only discusses self-generation CHP whichs usually connected on the customer-side of the meter. Table 5resents the wind power projects owned by independent powerroducers and their aggregated installed capacity and produc-ion in selected countries. The data for the wind power projectsre approximations only and mainly based on discussions witharious national wind energy associations.

It can be seen that the ownership of self-generation CHPnd wind power projects between the different countries variesonsiderably; however, most countries show a very high per-entage of independently owned self-generation CHP and windower projects. While different national incentives and regu-ations certainly play a considerable role for the interest ofndependent project developer to be involved in such projects,t can be concluded that self-generation CHP and wind powerrojects are generally dominated by independent owners. Table 4lso shows that independently owned self-generation CHPan reach an important share of the national peak demand;ence they can indeed significantly reduce incentives to with-old generation during peak times. In some countries wind

ower can also reach a significant percentage of peak demand;owever, wind power is not always available during peakemand.

8 Fore a more detailed discussion of the second revenue streams see nextection.

T. Ackermann / Electric Power Systems Research 77 (2007) 1148–1159 1155

Table 4Percentage of self-generation CHP projects with electricity markets 2001/2002, source: IEA, Cogen Europe, Eurostat, DTI

Country Installed capacity(GW)

Peak demand(GW)

Installed CHP(MWe)

Independentlyowned (%)

Independentlyowned (MWe)

Independently owned CHP asshare of peak demand (%)

England and Wales ∼64 ∼51 ∼4,000 ∼30 ∼1,200 ∼2.3Sweden ∼31 ∼27 ∼3,200 ∼30 ∼960 ∼3.5Denmark ∼6.5 ∼3.6 ∼2,480 ∼71 ∼1,759 ∼48.8Finland ∼15 ∼13 ∼5,000 ∼50 ∼2,500 ∼19.2New Zealand ∼7 ∼6 ∼360 ∼95 ∼342 ∼5.7Australia ∼27 ∼18 ∼2,000 ∼75 ∼1,500 ∼8.3California ∼51.6 ∼49.3 ∼6,457 100 ∼6,457 ∼13.0Netherlands ∼20 ∼15 ∼8,500 ∼50 ∼4,250 ∼28.0Germany ∼120 ∼78 ∼34,500 ∼33 ∼11,594 ∼14.1Spain ∼53 ∼35 ∼3,500 ∼100 ∼3,500 ∼10.0

Table 5Independently owned wind power in comparison to the whole market 2001/2002, data are approximations only as no statistics available

Country Installed capacity(GW)

Peak demand(GW)

Installed wind(MWe)

Independentlyowned (%)

Independentlyowned (MWe)

Independently owned wind asshare of peak demand (%)

England and Wales ∼64 ∼51 ∼552 ∼80 ∼441 ∼0.8Sweden ∼31 ∼27 ∼310 ∼80 ∼248 ∼0.9Denmark ∼6.5 ∼3.6 ∼2,556 ∼86 ∼2,193 ∼60.9New Zealand ∼7 ∼6 ∼37 ∼0 0 0.0Australia ∼27 ∼18 ∼103 ∼50 ∼51 ∼0.3California ∼51.6 ∼49.3 ∼1,820 ∼90 ∼1,638 ∼3.3GS

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Hence, it can be concluded that at least a significant sharef distributed generation utilising either CHP or wind powers independently owned in most countries. It is, however, alsomportant to mention that this can change, e.g. by mergers orcquisitions, but on the other hand it also seems that DG oftenrovides an easier market entrance for independent power pro-ucers.

.4.2.2. Importance of second revenue stream. A second incen-ive to not withhold DG is related to the second revenue streamhich is often required for DG as DG is often not competitive

nough to compete purely with centralised generation in thenergy (kWh) market on the base of marginal costs. The elec-rical efficiency for most DG technologies with a capacity of0 MW or less is below the electrical efficiency of large DG orentralised generation. As many of the DG technologies use nat-ral gas as fuel source, the marginal generation costs vary onlyue to different electrical efficiencies; hence marginal costs ofmall and medium-size DG are usually higher than those of largeG or centralised generation. In addition, larger projects usu-

lly can realise some economies-of-scale when purchasing theeneration technology as well as regarding the permit-grantingrocess.

The economic advantage DG has, however, is that energyroduced within the distribution network and used within the

istribution network avoids the costs for transmission services.ence, the marginal costs for energy (kWh) produced by DG are

conomically competitive as long as the marginal generationosts of DG are lower than the marginal generation costs of

∼95 ∼11,400 ∼14.6∼30 ∼1,233 ∼3.5

, OFGEM, Swedish Energy Agency, DTI (UK)

entralised generation plus the avoided marginal transmissionosts:

C × DG < MC × CG + ATC (5)

here MC × DG = marginal costs distributed generation;C × CG = marginal costs centralised generation; ATC =

voided transmission costs.The marginal transmission costs are usually avoided losses,

ut under certain circumstances they can also include avoidedapacity payments. If the energy (kWh) is generated and usedn the customer-side of the meter, DG is competitive as long ashe marginal generation costs plus avoided marginal transmis-ion and marginal distribution costs are lower than the marginaleneration costs of centralised generation:

C × DG < MC × CG + ATDC (6)

here ATDC = avoided transmission/distribution costsTable 6).

Example England and Wales: Table 6 lists the avoided costsof DG connected within different distribution networks inEngland and Wales based on NETA market regulations. Com-pared with the average spot market price in the England andWales system, which was around 24 pounds/MWh in 2001,a DG unit installed in the London area can have 8% higher

marginal costs compared to a generation unit connected to thetransmission system in the London area or even 19% highermarginal costs compared to a generation unit connected tothe transmission system in the Northern area.

1156 T. Ackermann / Electric Power Systems

Table 6Estimated economic value of DG under NETA in pounds/MWh, source: [26]

Embedded benefits London S. Yorkshire North

Avoided demand transmissionnetwork use of system(TNUoS) charges

1.88 0.68 0.14

Avoided generation TNUoScharges

−1.45 (1.19)a 0.52 1.19

Avoided balancing systemuse of system charges

1.22 1.22 1.22

Avoided transmission lossescharges

0.04 0.04 0.04

Avoided balancing systemadministration charges

0.20 0.20 0.20

Avoided trading charges 0.04 0.04 0.04Total 1.93 (4.57) 2.70 2.83

a Generators located in the London area get paid TNUoS benefits, becausethey provide benefits to the power system. Now, a generation unit within thedistribution network is not paying TNUoS charges, hence, it does not receive anyof those payments either. Therefore, the benefits can be considered to be negativeicN

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f compared to a generation unit in the London area, but, 1.19 pounds/MWh ifompared to a generation unit connected to the transmission network in the areaorth, for instance.

In the long-run, projects are only financially viable if they areble to recover the investment costs, which requires earningsbove the marginal costs. Now, while some DG technologiesre able to compete with centralised generation on the basisf marginal costs together with avoided network charges, itften will be very difficult to earn investment costs, in particulars investment costs for most DG technologies are significantlyigher than those of centralised generation.

Hence, if centralised and distributed generation earn the sameargin per kWh, e.g. 10% on top of the marginal costs, DGust have significantly higher utilisation times to earn the invest-ent costs. However, DG units are seldom able to compete witharginal costs of base-load power stations, even if avoided net-ork costs are taken into account.Therefore, DG projects often require additional income, also

nown as second revenue stream, to make the overall projectnancially viable. Here it is important to mention that the financ-

ng of DG projects, due to considerable large upfront investmentompared to centralised CCGT, for example, becomes consid-rably easier if the additional income is a fixed income and doesot depend on highly volatile markets.

Usually, the second revenue stream is based on a bilateralong-term contract, e.g. for heat or green power. This meanshat these DG units have to operate at certain times or a penaltyill occur and DG operators will, therefore, bid into the elec-

ricity market – if they do not also have a long-term contractor electricity supply. This bid into the electricity market wille below the expected market clearing price, as they want to

apture an additional income from the second revenue and wanto avoid any penalty payment.9 In other words, these DG unitsill always contribute to a lower market clearing price.

9 Hence, DG will only withhold generation if the gain is larger than the penaltynd the mist income from the second revenue payment.

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Research 77 (2007) 1148–1159

In the following, the different values DG can provide to gen-rate a second revenue are briefly discussed.

3.4.2.2.1. Ancillary services value. The ancillary servicealue combines all the services that DG can provide to the dis-ribution and, maybe, even to the transmission network.10 Thisncludes voltage support, power quality support, capacity valuereducing local peaks in the network and thereby reducing over-oading of certain network equipment), as well as the activearticipation in ancillary service markets, such as balancing mar-ets, e.g. spinning reserve.11 This value, however, is very seldomealised. DG operators mainly claimed that the main reason forhis low realisation rate is based on barriers in the regulations,.g. DG is not allowed to participate in markets for spinningeserves in most national markets, but also on the limited interestf network companies to cooperate with independently ownedG projects.3.4.2.2.2. Values on the customer-side. In the following,

he different values that DG may be able to capture on theustomer-side are briefly presented. Thereby, it is important tonderstand that some DG project developers provide their cus-omers with a contract similar to an insurance policy. With thisontract, the DG project developers usually guarantee a certaineliability level and/or power quality level. Other options arelso possible; for example, a project developer may guaranteeo limit power consumption of the customer to a given thresholdpeak-shaving) to reduce capacity payments.

In all these cases, the customer will pay a constant insuranceee, independent of the action that was required from the DGroject developer. If the guaranteed service is not achieved, e.g.power outage occurs, the DG developer pays a usually very

igh penalty to the customer. It is important to understand thatDG unit installed at a customer location can sell its energy

o the market or can provide network services, as long as therid supply to the customer is within the agreed specifications.n case the power network fails or other problems arise, the DGnit must be able to take over the power supply of the customer.s most customers within such programs are very sensitive to

ny power supply irregularity, hence, often the DG unit(s) muste able to take over power supply within one or two cycles ofC current.

3.4.2.2.3. Renewable energy value. Renewable distributedeneration, i.e. wind power, photovoltaic, biomass, waste energynd small hydro, often depend on various forms of subsidies.hese subsidies can be considered a second revenue. Many sub-idy payments, like for green certificates or for feed-in tariffs,or instance, depend on the actual amount of energy produced.

ithholding of generation capacity that can earn such subsidiesould therefore only be profitable if:

here Sub = subsidies.

10 If DG provides ancillary services to the distribution network it would actuallye better defined as distributed capacity, see [1].11 See [22] for case studies of ancillary services that DG can provide withinhe network.

stems Research 77 (2007) 1148–1159 1157

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Table 7Power load and production capacities (end of year 2002) in Western Denmark

Power (MW)

Local CHP (combined heat and power) 1596Wind power 2315Primary thermal (extraction) units 3107Peak load 3685Typical off-peak load, summer 1400Typical off-peak load, winter 1900

Minimum load 1189

Table 8Distribution of production in Western Denmark (year 2002)

Energy (GWh) Percentage of consumption

Primary (extraction) units 12,928Local CHP 6,723 32.2Wind power 3,825 18.3Total production 23,476FC

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T. Ackermann / Electric Power Sy

Hence, production depending on subsidies increases thehreshold to withhold generation capacity. The effect dependsn the amount of subsidies.

3.4.2.2.4. CHP distributed generation. Combined heat andower DG represents a classical DG concept using two revenuetreams by selling power and heat. The existing CHP schemesan be very different in design, e.g. from large boilers for heatroduction with only a small power generation capability toather large power generation units with a small heat supply.imilarly, CHP DG projects can be designed and operated in

wo ways, either focusing on the heat requirements of the heatustomers or focusing on the electricity production.

It is possible to argue that CHP systems that predominantlyocus on heat supply have little incentive to withhold powereneration because they will have to operate as long as there isheat demand.12 So if a CHP system is mainly designed for

eat supply it can be assumed that the marginal costs for powereneration are almost zero, hence withholding of generation isnly profitable if

2 − P1S > P1 − MC(=∼ 0) × WC (8)

Hence, also in this case the threshold for withholding genera-ion is increased. It is, however, important to point out that not allrojects have such incentives. For example, projects with a suf-cient heat storage system have the option to switch off the CHPcheme as long as the head storage capacity is sufficient to sup-ly the heat demand; hence withholding of generation capacityill not result in a penalty for not supplying the heat demand.Hence, it can be summarised that DR can help to increase

arket efficiency by increasing demand elasticity or reducingarket power. Nevertheless, the described impact of DG in

egards to market power is difficult to measure. The followingase study, however, cannot be considered as a proof but as annteresting example for further discussion of the issues raised inhis chapter.

.5. Case study Western Denmark

Unfortunately, it is rather difficult to obtain empirical dataegarding the impact of DR on market power. For instance, dur-ng the Californian energy crisis DR played two different roles.

hile a large amount of independently owned diesel gensetsere moved into the state to provide peak capacity, DG thatualified as QFs under PURPA – mainly renewable DG in Cal-fornia – was slowly removed from the power market duringhe power crisis. The reason was that QFs had power purchasegreements with the former monopolist companies in California.uring the power crises in California these former monopolists

topped paying the QFs months before they went bankrupt, soost renewable power generation capacity – about 11% of total

eneration capacity in California – stopped operation. Hence,his process increased the lack of power in the California marketnd increased the market power issue during that time. These

12 It can be assumed that not supplying the heat demand will result in someiability or penalty payments.

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ircumstance, however, are unique to the California market setp.

An interesting case, however, is the situation in Western Den-ark during the first months in 2003. Western Denmark is a

ricing area within the Nordic electricity market, also ofteneferred to as Nordpool.13 Western Denmark is probably the areaith the highest share in DG in the world, see Tables 7 and 8.

n 2002, local distributed wind power and CHP generated about0.5% of the consumption, see also [29] It is important to men-ion that the share of distributed and CHP in Eastern Denmark isignificantly lower. The installed wind power capacity in easternenmark is only about 400 MW compared to 2315 in West-

rn Denmark and about 800 MW of CHP compared to almost600 MW in Western Denmark.

For the Nordic market in general, and the Swedish and Nor-egian market area in particular, it is often argued that the market

s energy constrained and not capacity constrained due to itsery high share in hydro power.14 Hence, withholding gener-tion will be less critical for the market as there will alwayse enough capacity available. However, due to reduced reserveargins and high variations in hydro generation in the Nordic

ystem, withholding generation is likely to be beneficial for someeneration companies during certain periods.

While this case study does not investigate any market powerssues in the Nordic countries in general, the case study wouldike to focus on the winter 2002/2003, which saw a very lowydro reservoir level, which can be considered as a (natural)ithdrawing of generation capacity. This situation has lead to

ral Europe, e.g. Germany, was frequently imported into Norwaynd Sweden via Denmark and the transmission lines between

13 During times with no congestion, the whole Nordic market is one pricingrea; if congestion occurs different pricing areas are possible.14 Sweden: Hydro power share about 50%, Norway about 98%.

1158 T. Ackermann / Electric Power Systems Research 77 (2007) 1148–1159

Table 9Weekly average power prices in Denmark and Nordpool system price for first 10 weeks 2002 and 2003 in Euro per MWh

Week 2003 2002

Price Area System DK West DK East System DK West DK East

1 96.87 38.68 95.64 28.86 28.69 24.832 103.65 82.88 101.13 32.91 24.29 24.363 62.80 33.39 59.01 23.99 22.84 22.964 45.88 37.59 45.79 23.62 23.65 22.045 43.86 33.73 43.60 23.27 23.28 22.106 46.45 40.64 46.33 19.76 19.76 19.677 48.20 46.44 48.44 20.46 20.26 20.008 51.03 49.65 53.01 20.73 20.73 20.069 48.61 42.71 48.92 20.16 20.16 20.1110 47.00 40.53 46.43 19.05 19.04 19.00

Average price 59.43 44.62 58.83 23.28 22.27 21.51

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ource: http://www.nordpool.com/.

enmark and the remaining Nordic power system become fre-uently congested. As a result, Western and Eastern Denmarkre treated frequently as two single pricing areas. It is importanto mention that the Western and Eastern Danish system are notnterconnected, but both systems have connections to the Nordicower system (mainly to Sweden) and to Germany.

Table 9 shows the weekly average power prices for thewo pricing zones in Denmark and the Nordpool System Priceor the first 10 weeks in 2002 and 2003. The year 2002 cane considered an average year in terms of available water inydro reservoirs. During 2002, the power price for the first0 weeks in both pricing zones was lower than the Nordicystem price, while the power price in Western Denmark wasn average about 3.4% higher in Western Denmark than inastern Denmark. In 2003, the year with significant lowerydro reservoir levels in the Nordic countries, the market pricen Western Denmark was almost 25% lower than the systemrice and 24.1% lower than the average market price in Easternenmark. While the Swedish and Norwegian power price

ertainly was effected by the very low hydro reservoir level, its much more difficult to understand why Western and Easternenmark have such significantly different prices. The analysisf the significantly lower prices in the Western Danish systems certainly a very complex issue and has no simple explanation,ut it seems that the very high share of distributed wind powernd CHP in the Western Danish system compared to the Easternanish system might play a significant role.Morthorst [27], for example, analysed market data from

ebruary and November, December 2002 and found that theres a tendency for a high wind power production in the Westernanish system to lead to relatively lower prices in the power

xchange. It is important to mention that wind power produc-

ion during the first 10 weeks of a year is usually very high due tointer storms. It is also important to point out that wind power

s well as CHP in Denmark is treated as priority production;15

15 For all wind power installed until the end of 2002. For wind turbines installedince 1.1.2003 new rules apply, see [27].

R

−1.0 −4.3 −7.6

ence the owners of those generation units get paid a fixedrice per kWh independent of the market price. For CHP therice is somewhat time dependent, i.e. the price is higher dur-ng peak times than during base-load times. Also, about 86% ofhe installed wind power capacity and 71% of the installed CHPapacity in Denmark is independently owned. Hence, neitherind power or CHP have any incentives to withdraw generation

s both must generate power to generate an income. While thisight explain the lower prices in Western Denmark, it does not

xplain the higher prices in Eastern Denmark. The question ofhether any form of market power influenced the higher prices

n Eastern Denmark requires further investigations.

.6. Conclusion

The paper briefly describes the different benefits DR can pro-ide for market operation, in particular in regards to reducingarket power. In general, the cost and benefits of DR are difficult

o evaluate due to the complexity of the problem. Nevertheless, itan be generally assumed that DR, depending on size of the gen-ration unit, the location and the ownership, can help to reducearket power issues and thereby lead to a more efficient market.or a more detail discussion of the findings see [28].

cknowledgement

The author would like to thank ELFORSK (Swedish Elec-rical Utilities R&D Company), ABB Corporate Research andhe Swedish Energy Authority for their sponsorship and col-aboration in this project. The author would also like to thanker-Anders Lof for valuable comments.

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[

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T. Ackermann / Electric Power Sy

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