Purkus et al. Energy, Sustainability and Society (2015) 5:12 DOI 10.1186/s13705-015-0040-1

ORIGINAL ARTICLE Open Access

Market integration of renewable energiesthrough direct marketing - lessons learned fromthe German market premium schemeAlexandra Purkus1*, Erik Gawel1,2, Marc Deissenroth3, Kristina Nienhaus3 and Sandra Wassermann4

Abstract

Background: Increasing the market and system integration of renewable energy sources (RES) is regarded as key toreducing the costs of RES support and transforming the electricity system. In several EU countries, feed-in premiumschemes have been implemented to better align RES production with electricity prices and to enhance theefficiency of RES marketing by increasing direct participation of producers in electricity markets. This paper examinesthe lessons learned from the German market premium scheme, which was introduced in the Renewable EnergySources Act 2012 as an optional alternative to feed-in tariffs. The 2014 reform of that law has made direct marketingmandatory except for small RES plants, thus establishing the sliding market premium as the new primary instrumentof RES support.

Methods: Combining a qualitative economic analysis with insights from sociological research on direct marketingand simulation results from agent-based modelling, we evaluate how well the optional market premium hasperformed in setting incentives for demand-oriented RES production and efficient marketing of RES electricity.Furthermore, we examine what efficiency gains can be realistically expected from the changes implemented in2014, and discuss whether the direct marketing model adopted in Germany is a promising approach for improvingthe market integration of RES.

Results: We find that direct marketing has made a positive contribution to the marketing efficiency of dispatchableRES; for intermittent RES, it provides few structural changes compared to marketing through transmission systemoperators. The benefits of a greater demand-orientation of RES feed-in remain limited when considering the extentto which load shifting is incentivised. For intermittent RES in particular, incentives for demand-oriented feed-in areonly effective in times of negative electricity prices when voluntary curtailment is encouraged.

Conclusions: For the further development of mechanisms to support greater market proximity, differentiatingbetween the various RES according to their ability to respond to electricity price signals can prove advantageous.Also, objectives such as improving security of supply and reducing the costs of transforming the electricity systemcannot be reached through RES market integration efforts alone but require an adaptation of electricity marketconditions to the requirements of RES.

Keywords: Renewable energy policy; Market integration; Feed-in premium; Direct marketing

* Correspondence: alexandra.purkus@ufz.de1Department of Economics, Helmholtz Centre for Environmental Research - UFZ,Permoser Str. 15, Leipzig 04318, GermanyFull list of author information is available at the end of the article

© 2015 Purkus et al.; licensee Springer. This is an Open Access article distributed under the terms of the Creative CommonsAttribution License (http://creativecommons.org/licenses/by/4.0), which permits unrestricted use, distribution, and reproductionin any medium, provided the original work is properly credited.

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 2 of 13

BackgroundRES market integration - objectives and instrumentalimplementationAs electricity generation from renewable energy sources(RES) continues to expand in Europe, EU member statesare faced with the challenge of integrating the growingproportion of renewables, and especially intermittentrenewables, into existing energy systems and electricitymarkets [1,2]. In this process, increasing the market in-tegration of RES is viewed as an important step towardsimproving the alignment of RES feed-in to scarcity sig-nals in electricity markets and systems, thus containingthe costs of RES expansion; these relate not only to thecosts of supporting RES but also to the wider costs oftransforming the electricity system [2,3]. The new EUenergy aid guidelines, for instance, stress that market-based mechanisms should promote the ‘transition to acost-effective delivery’ (p. 23) and highlight the import-ance of direct market participation and the assumptionof market responsibilities by RES producers [4]. Inprinciple, it appears sensible to differentiate betweentwo different dimensions of market integration (seeTable 1) [5-7]. Firstly, market integration aims for a stron-ger alignment of RES feed-in to price signals in the electri-city market as well as an efficient marketing of RESelectricity [5,6]. Incentives for this dimension of marketintegration can be implemented in RES policy instrumentswhere prices are administered by the state, by changingfrom a feed-in tariff which is paid independently frommarket prices to a feed-in premium model where electri-city prices influence total remuneration. This approach iscurrently pursued by several EU member states using

Table 1 An overview of the objectives of market integration o

Market integration objectives Dimensions of achievement of o

Demand-oriented generation of RESelectricity and increased flexibility ofRES plants

Prevention of surplus supply situatcurtailment in times of negative el

Shift of feed-in to times whendemand is strong and prices are h

• Intermittent RES: Maintenance pladesign oriented towards market varequirements

• Dispatchable RES: targeted load s

Increased remote controllability of

Participation of RES installations inmarket

Efficient marketing of RES electricity Reduced transaction costs of mark

Increased forecasting quality and rprocuring balancing energy

Competition for efficient marketing

Market-driven production andinvestment decisions

Competitive determination of RES

RES producers become regular ma

Based on BMU 2011 [7]; Klobasa et al. 2013 [6]; and Lehnert et al. 2014 [5-7].

various different design options [8,9]. While fixed feed-inpremiums offer RES producers a set bonus on top of themarket price, sliding premiums balance out the differ-ence between reference prices and average market prices[10]. Here, total remuneration remains based on state-determined prices, as is the case for fixed feed-in tariffs,so that the long-term market risks for producers of RESremain comparatively low. The second dimension ofmarket integration, on the other hand, encompasses acompetitive determination of the remuneration and acompetitive steering of investment decisions [11,12].This involves a transition to treating RES producers asregular market players with system responsibility, withcompetitive support mechanisms and electricity marketrevenues playing a significant role in their refinancing.At present, discussions about the instrumental imple-mentation of this dimension of market integration focusprimarily on competitive bidding processes, given thatthe new EU guidelines on state aid express a clear pref-erence for this instrument type [4]. A further distinctionis necessary between the market integration and systemintegration of RES - the latter aims at improving RES’contribution to grid stability [1,13] but is not the focusof this article.One example of a sliding feed-in premium scheme is

the German market premium model, which was initiallyintroduced into the RES support regime in 2012 as an op-tional alternative to the fixed feed-in tariff in order to setincentives for demand-oriented RES feed-in and efficientmarketing of electricity from RES. With the introductionof the amended Renewable Energy Sources Act (EEG)2014, this approach was further extended by making

f renewable energy sources

bjectives Contributions to overarching objectives

ions via voluntaryectricity prices

Contribution of RES to security of supply isincreased;

igh:Costs of RES promotion are reduced through anincrease in RES market value;

nning, installationlue and system

Cost reductions in the overall system (e.g. lowerbalancing energy prices and system integrationcosts)

hifting

RES installations

the balancing energy

eting RES electricity RES promotion costs are reduced

eduction of costs of

forms

remuneration RES expansion costs are reduced

rket players

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 3 of 13

direct marketing mandatory except for small plants, whileelevating the market premium scheme to the standard re-muneration model. In the literature, assessments of themarket premium scheme come to divided conclusions.While some studies evaluate the promotion of market in-tegration via the sliding market premium positively[6,14,15], others are critical of the instrument. On the onehand, market-determined incentives for RES producersare regarded as insufficient to promote market integrationand reduce the costs of RES support [11,12,16,17]. On theother hand, however, critics question the usefulness of adirect marketing-driven integration of intermittent RESinto the marginal cost-based electricity market, whichmay be structurally unsuitable to secure their long-termrefinancing [18-21]. Furthermore, there are trade-offs be-tween the objective of exposing RES producers to mar-ket price signals in order to increase the efficiency ofproduction and investment decisions on the one hand,and the creation of a secure planning basis for RES in-vestors, which is crucial to achieve a comprehensivetransformation to an RES-based electricity system, onthe other [13]. If RES producers carry a high share ofmarket risks, this would also tend to increase the costsof supporting the implementation of RES objectives, be-cause higher risks have to be compensated by higherrisk premiums in the remuneration [22-24].The following article evaluates experiences gained in

Germany from the introduction of the sliding marketpremium and discusses to what extent this form ofgovernment-supported direct marketing can serve as apromising instrument to promote the integration ofRES into the electricity market. The article begins withan outline of the design of the sliding market premiuminstrument and supplementary regulations on the pro-motion of market integration in the EEG 2014, as wellas an overview of the development of participation indirect marketing. This is followed by an evaluation ofexperiences gained with the market premium under theEEG 2012. Building on this, we examine to what extentthe new regulations set forth in the EEG 2014 can beexpected to make a greater contribution to the marketintegration objectives of realising a demand-orientedfeed-in of RES and efficient marketing.

MethodsAs a sliding feed-in premium with state-administeredprices, the market premium scheme does not aim for acompetitive control of RES investments [9,15]. Therefore,our assessment of the scheme’s performance focusses onthe market integration objectives of realising a demand-oriented generation of RES electricity and increased flexi-bility of RES plants, as well as an efficient marketing orRES electricity. Based on existing literature, measureswere identified which contribute to these objectives; these

are summarised in Table 1. Below, we discuss whether themarket premium scheme sets incentives for the adoptionof these measures and whether contributions to marketintegration objectives are effective and efficient. To con-duct this assessment, we review literature findings andavailable data, and analyse the impact of incentives onRES producers’ behaviour. This qualitative analysis iscomplemented by simulation results from the agent-based simulation model AMIRIS, which was developedat the Institute of Engineering Thermodynamics at theGerman Aerospace Center (DLR) in Stuttgart [25,26]The special nature of this article is an explicit interdis-ciplinary approach to the research topic which attemptsto integrate existing studies from sociological researchon markets [27], energy economics [9] and agent-basedmodelling [26].

Results and discussionPromoting market integration via the German marketpremium modelIn the market premium model under the Renewable En-ergy Sources Act (EEG), producers of electricity fromRES receive the difference between technology-specificreference prices and the actual, likewise technology-specific, monthly average market price (EEG 2014 Annex1). Under the EEG 2012, installation operators had theoption of switching between direct marketing andfeed-in tariffs, where the sale of electricity from RES iscentrally managed by transmission system operators(TSOs). This is no longer possible under the EEG2014. Only installations with a maximum installed cap-acity of 500 kW are now eligible to receive the feed-intariff; and as of 2016, the obligation to participate indirect marketing will be extended to all installationswith a capacity of over 100 kW (§ 37 (2) EEG 2014). Inexceptional cases, operators will still be able to fallback on feed-in tariffs, with a 20% reduction in remu-neration rates (§ 38 EEG 2014). The so-called ‘greenelectricity privilege’ provided under § 39 EEG 2012,whereby electricity suppliers benefitted from EEG sur-charge reductions if a certain proportion of their elec-tricity supply was sourced from directly marketed RES,has also been removed from the new EEG. A furtheramendment relates to the fact that under the EEG2012, RES producers were eligible for a separately cal-culated management premium to compensate for theadditional costs of trading and providing balancing en-ergy. Under the EEG 2014, in contrast, the managementpremium is implicit in the reference prices. For dispatch-able renewables, this is reflected by a reduction of 0.2cents/kWh in the reference price on which the fixed feed-in tariff is based; while for intermittent renewables, thereduction is 0.4 cents/kWh (§ 37 (3) EEG 2014). At thesame time, the remote control capability of RES

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installations, which was incentivised under the EEG2012 by offering higher management premiums for in-stallations fitted with appropriate systems, will now be arequirement for payment of the market premium (§ 35sentence 1 no. 2 in conjunction with § 36 (1) EEG2014).As a measure aimed at strengthening the demand-

orientation of all renewable energy sources, the EEG2014 also introduces cuts in financial support in timesof negative prices: In the case of installations commis-sioned after 1 January 2016, the reference prices onwhich the remuneration is based are to be reduced tozero when the value of the hourly contracts on the EPEXSpot exchange is negative in at least six consecutive hours(§24 EEG 2014). Given that installations with an in-stalled capacity of less than 500 kW are exempt, thisregulation applies only to larger installations for whichdirect marketing is obligatory (§ 24 (3) EEG 2014). Aswas the case under the EEG 2012, the market premiumfor biogas plants will be bolstered by a capacity-orientedflexibility premium (§§ 52 to 54 EEG 2014). Inaddition, for biogas installations with a capacityexceeding 100 kW, entitlement to feed-in tariff or pre-mium payments has been limited to the share of theannual amount of electricity generated which corre-sponds to a power rating of 50% of the installed elec-tric capacity (§ 47 (1) EEG 2014), a move intended toguarantee flexible plant operations.Meanwhile, the transition to a more market-driven

steering of investment decisions is supported in theEEG 2014 by the proposed switch to a competitive bid-ding process, which is geared towards establishing acompetitive determination of remuneration by 2017 atthe latest (§ 2 (5) EEG 2014). The details of its designare still unclear [28], but the model is to be tested onground-mounted solar installations (§ 55 EEG 2014).

Experiences with the market premium under the EEG2012: participation in direct marketingSince its introduction in 2012, the market premium hassuccessfully increased participation in direct marketing(see Figure 1): In April 2014, a total of 49% of the in-stalled capacity eligible for support under the EEG wasmarketed under the market premium scheme [29,30]. Atthe same time, the green electricity privilege, as analternative form of direct marketing, was largelyreplaced while the option ‘other forms of direct mar-keting’ without remuneration is practically irrelevant(see Figure 2). Initially, a high proportion of windpower producers in particular switched to the optionalmarket premium, but in the meantime participationamong other RES producers has also increased [9,31]:In April 2014, almost 60% of biomass installations

were taking advantage of the model; and as much as13% of solar installations were participating (see Figure 2).Nonetheless, the success of the sliding market premiumcan only really be measured by its contribution to theactual market integration objectives.

Experiences with the market premium under the EEG2012: efficient marketing of RES electricity?Under the fixed feed-in tariff system, quantities of RESelectricity are traded on the day-ahead or intraday spotmarket in accordance with the provisions of the Equal-isation Scheme Ordinance (§ 2 AusglMechV). By com-parison, the sliding market premium would lead tomore efficient marketing of RES if (a) direct marketingreduces the transaction costs of market participation,(b) balancing energy costs can be reduced as a result ofbetter RES feed-in forecasts and better management ofplant portfolios, e.g. by taking advantage of the ability tocontrol plants remotely or (c) innovative forms of mar-keting can increase prices obtained for renewables byoptimising the choice of markets (e.g. intraday andday-ahead spot market, balancing market, bilateral over-the-counter contracts) (see Table 1). Whether this ap-plies to the market premium model will be examined inthe following.The majority of RES installation operators are not

conventional players in the established energy sectorand, as a result, most of them have neither infrastruc-ture nor the knowledge required to sell the electricitythey produce on the central electricity markets them-selves. Introducing RES installation operators to themarket was therefore only possible through electricitytraders (hereafter referred to as ‘direct marketers’). Theyact as service providers to RES installation operatorsand in that function offer a broad range of services suchas preparing feed-in forecasts, communicating sched-ules to the grid operators as well as financially compen-sating for deviations or purchasing additional electricityto make up the scheduled amount. Based on their RESsupply forecasts and expected electricity prices, thesetraders take the initial decision on behalf of the installa-tion operator as to whether to remain within the feed-intariff scheme or to market directly. In the latter case,they determine the time, the quantity and the market onwhich RES electricity will be offered for sale. Directmarketers also have access to the specific infrastructureneeded to be able to trade on the energy exchange [25].Regarding the reduction of transaction costs, com-

pared with selling through TSOs, it can be said that ini-tially additional costs are incurred because the TSOs stillmarket the quantities of electricity in the feed-in tariffscheme. In addition, marketing costs are subject toeconomies of scale because fixed costs make up a largeshare of those costs [18,20,32]. Also, the larger the

Figure 1 Development of installed capacity in the market premium model (January 2012 - July 2014). ‘Gases’ encompass landfill, sewage andmining gases. Authors’ representation based on 50Hertz et al. 2014 [29].

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 5 of 13

management portfolio the lower the costs of balancingenergy will be, because larger portfolios are associatedwith higher forecast accuracy [6]. This suggests that interms of transaction costs, large direct marketers comeclosest to TSOs.An approximate value for the additional costs of direct

marketing under the market premium scheme is providedby the management premium: In 2012, this amountedto approximately 467 million euros, while in 2013 anestimated 354 to 400 million euros were paid out dueto a reduction in management premium rates [33-35].a

However, the management premium primarily acts as

Figure 2 Direct marketing share of the total installed capacity eligible for Emining gases. Authors’ representation based on 50Hertz et al.; Bundesnetza

an indicator for the additional support costs associatedwith direct marketing, rather than for actual transac-tion costs. Especially in 2012, it was found that an over-compensation of the costs of direct marketing led tohigh windfall profits, subsequently giving rise to stron-ger cuts in the management premium rates for inter-mittent RES [36]. While the management premiumpursuant to EEG 2012 forms the essential basis of dir-ect marketing business models [18,37], its degressivedesign increases cost pressure on marketers over time.When it comes to the marketing of wind and photo-

voltaics (PV), the marketing channels used are mainly

EG remuneration (April 2014). ‘Gases’ encompass landfill, sewage andgentur [29,30].

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the same as those used by TSOs, i.e. the intraday andday-ahead spot market. This choice is structurally sup-ported by the market premium because spot marketprices are used to calculate the market value, and there-fore selling on other markets would entail higher levelsof revenue risk [6,38]. Biomass installations, on the otherhand, show greater participation in balancing markets[6,39]. In principle, differences in flexibility options avail-able to biomass installations in combination with heatutilisation concepts mean that they require more indivi-dualised marketing concepts than other RES, so that dir-ect marketing is likely to increase efficiency. In the caseof intermittent RES, marketing innovations can be founde.g. in the establishment of RES networks forming vir-tual power plants, which have spread rapidly [40].However, targeted marketing of the ‘green power’ char-acteristic, as promoted by the green electricity privilege,is not possible under the market premium model (§ 56(2) EEG 2012 and § 80 (2) EEG 2014).Summing up, it can be said that the efficiency benefits

that have been achieved with the marketing of wind andPV are mainly attributable to the fact that not only newinstallations but also existing ones were incentivised toprovide for remote control capability and availability ofreal-time data [6]. However, the marketing channelsused are largely similar to those employed by TSOs, withthe exception of bioenergy and hydropower generators,for whom the supply of balancing energy is profitable.At present, direct marketing also leads to increases inthe transaction costs of RES marketing. A lowering ofthese costs to a level that is comparable with marketingthrough TSOs alone could be achieved primarily byexploiting economies of scale. However, correspondingstronger price competition between direct marketerscould promote processes of concentration [18,25,38].

Experiences with the market premium under the EEG2012: incentives for demand-oriented RES production andflexibility?A more demand-driven feed-in and greater flexibility inRES production can be achieved when the market pre-mium sets incentives to encourage (a) voluntary curtail-ment in times of negative electricity prices, (b) in thecase of intermittent RES, electricity price-oriented main-tenance planning and plant designs that are orientedtowards a maximisation of market value and alignedwith system requirements, (c) targeted load shifting ofdispatchable renewables, (d) increased remote controlcapability of RES installations (cf. also (b) in the sectionon efficient RES marketing above) and (e) participationof RES producers in the balancing energy market (seeTable 1). Relevant factors for the analysis are not onlywhether these measures are taken but whether in this

form they contribute to the overall objectives of securityof supply and cost reduction.For intermittent RES with near-zero marginal costs,

incentives are set to make limited bids and/or to encour-age curtailment in times of strongly negative electricityprices [6,41]. Voluntary curtailment becomes profitablewhen electricity traders participating in the spot markethave to pay buyers a higher amount than that which isexpected from the market premium payment includingthe management premium [9]. Currently, for example,wind energy plants in direct marketing curtail their pro-duction at negative prices of approximately − €65/MWh[42]. Their ability to respond depends upon the remotecontrol capability of the installation, which has beengrowing since 2013 due, among other things, to corre-sponding incentives in the management premium [6].Apart from optimising maintenance planning, intermit-tent RES have few other incentives for load shifting[9,20]. Price signals are either too low or not consistentenough to make it worthwhile to base decisions aboutthe location and the design of installations on marketvalue rather than on energy yield, or to stimulate invest-ment in weak-wind installations or east-west facing PVsystems [43,44]. What is more, the advantages of themarket value of alternative installation concepts arebeing eroded by the increasing number of relevantsuppliers [18]. In the case of balancing markets, prequal-ification of intermittent RES is only possible to a limitedextent at present [5,38].So far, there are no studies available on actual changes

in feed-in behaviour for dispatchable renewables. Basic-ally, the market premium sets incentives for voluntarycurtailment when electricity prices fall below the differ-ence between the marginal costs of production and theexpected market premium including the managementpremium. For biogas plants, the uptake of the flexibilitypremium provides insight into whether the conditionsfor a demand-based, flexible operation are at least in ex-istence [45,46]: In April 2014, 370 installations with ap-proximately 216 MWel claimed the flexibility premium,which corresponds to roughly 11% of the installed biogasand biomethane capacities participating in direct mar-keting [39]. After a slow start in 2012, the use of theflexibility premium is meanwhile increasing rapidly; thedelay in uptake is explained by the fact that power plantflexibilisation is associated with financial investmentsand high information requirements [46].Next to hydropower installations, biomass installa-

tions are the most active RES producers on the electri-city balancing market. In April 2014, 24% of the directlymarketed biomass power capacity and 43% of the dir-ectly marketed hydropower capacity were correspond-ingly pre-qualified. So far, mostly negative balancingenergy is supplied [39,46]. Figure 3 gives an example of

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how biomass installation operators could generateadditional revenues through participation in direct mar-keting including the balancing market for negativebalancing energy. The figure shows the results of asimulation of the agent-based simulation model AMIRIS,which is being developed at the Institute of EngineeringThermodynamics of the German Aerospace Center (DLR)in Stuttgart [25]. Especially for solid fuel-based thermalpower plantsb and large biogas installations, the poten-tially achievable additional revenues of 6% and 11%,respectively, are worthy of note.The difference in the revenues of the two installations

mentioned above can be explained by different shares ofdirectly marketed capacity, which is higher for large bio-gas installations. Although in this model small biogas in-stallations with a maximum installed capacity of 350 kWcannot participate in the balancing market, they stillprofit indirectly from the other installations’ sales, as canbe seen from Figure 3. This results from the model as-sumption that, due to the additional revenues achievedon the balancing market, the direct marketers will alsoincrease bonus payments to their other customers whichis a possibility to improve their competitive position.Finally, by exploiting balancing markets, the flexibilisa-

tion of installations can indeed have a positive effect ontheir economic efficiency while also supporting thesystem as a whole. Thus, it appears to make sense to in-centivise a corresponding adaptation of installations andto enable their participation in the balancing market,where besides storage plant operators more and moreother new participants are competing.Viewed on the whole, however, the market premium

currently has the character of a ‘curtailment premium’:for intermittent renewables, curtailment signals becomeeffective when electricity prices are highly negative; fordispatchable renewables, this occurs earlier due to posi-tive marginal costs, especially since the supply of

Figure 3 Additional revenues generated by biomass installation operatorsfeed-in tariffs.

negative balancing energy is profitable. For bioenergyinstallations, in particular, the response to electricityprice signals sets important incentives for optimising theuse of biomass resources.However, so far, the model sets few incentives for dis-

patchable renewables to engage in positive load shifting,which might be desirable in order to increase the contri-bution of RES to the energy supply when feed-in fromintermittent RES is low, and could contribute to the sta-bility of the system. At present, this is also determinedby relatively low peak/off-peak spreads on the spotmarket [47]. Furthermore, there are still few incentivesfor dispatchable renewables to supply positive balancingenergy or for intermittent renewables to make marketvalue-oriented decisions about the design of theirinstallations.By reducing the quantity of electricity that has to be

remunerated in times of low and negative prices, volun-tary curtailment eases the EEG surcharge burden, whichis determined on the basis of the difference between thefeed-in tariff ’s or market premium’s reference prices andthe market value for RES electricity [6]. However, theongoing expansion of intermittent RES with near-zeromarginal costs and the high temporal coincidence oftheir feed-in causes the market value of intermittent re-newables to fall [25,48,49]. Even if the full costs of RESgeneration were decreasing, this would in turn lead toan increasing burden on the EEG surcharge and repre-sents a fundamental problem for the integration of inter-mittent RES in the ‘energy only’ market. Moreover,analyses of the causes of negative electricity prices showthat in times of negative prices, in addition to nuclearpower plants, particularly emission-intensive lignite coal-fired power plants continue to operate at high load[42,50]. Here, RES curtailment reduces incentives for con-ventional power plant operators to curtail their operationsor invest in flexibilisation measures. From the climate

via participation in the balancing market. In comparison with their EEG

Figure 4 Specific direct marketing costs of different directmarketers.

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policy and system transformation perspective, this situ-ation is highly problematic [18,20,51].

The market premium under the EEG 2014 - a contributionto a more objective-based market integration?The main changes in the EEG 2014 concerning RESmarket integration are the following: the mandatorycharacter of direct marketing for larger, new installa-tions; the pricing-in of the management premium in thereference prices used to calculate the market premium;cuts in payments when prices are negative for prolongedperiods; and the introduction of remote control capabil-ity as a requirement for payment of the market pre-mium. Further implications arise from the generaldecrease of remuneration rates, which is particularlypronounced for bioenergy [52]. So, the question is, com-pared with the EEG 2012, what changes can be expectedregarding the contribution of the market premium tomarketing efficiency and the promotion of demand-driven and flexible electricity feed-in?In terms of marketing efficiency, the exploitation of

the marketing channels used under the market premiummodel in the EEG 2012 seems likely to continue sincethere has been no change in the structure of the incen-tives created. For biogas installations, flexibility of opera-tors to design site-specific marketing concepts isrestricted by the newly introduced limit on the remuner-ated quantity of electricity to 50% of the installation’spower rating [53]. In that respect, it lessens the advan-tage associated with direct marketing for these dispatch-able RES of being able to optimise the marketing ofelectricity and heat to suit the specific installation. Inparticular, however, mandatory direct marketing in con-junction with the reduced management premium is ex-pected to have a tendency to strengthen larger directmarketers who have lower marketing costs due to econ-omies of scale and so can remain competitive [38]. Thementioned tendency and economic impact of the directmarketing costs in combination with a simultaneousabolition of the management premium were examinedusing the DLR simulation model described above (here,the obligation implies that the management premiumpaid out on top of the market premium under the EEG2012 is no longer provided and is also not integrated inthe reference prices, as is the case under the EEG 2014).The model accounts for fixed and variable costs of directmarketers, i.e. fixed costs represent office rents, IT andstaffing costs and annual charges for trading, whereasvariable costs refer to the amount of traded electricityand expenditures for electricity generation forecasts andbalancing power needed in case of deviation from gener-ation schedule. As depicted by Figure 4, by way of ex-ample, with the above-mentioned cost structure, thespecific marketing costs of the direct marketers in

AMIRIS assume values between €1 per MWh and €3.50per MWh for the simulation years 2012 to 2019. Thegrey-shaded area illustrates the variation of the market-ing costs as they are depending on the type of trader.The extent of the costs is strongly dependent on thecomposition of the trader’s portfolio - in contrast to dis-patchable renewables, high shares of intermittent renew-ables tend to result in higher costs to balance generationand demand. The decrease of the maximum specificcosts until 2019 is due to an increasing size of portfoliosof the direct marketers, i.e. they profit from economiesof scale and improved forecast qualities over the years.The simulated costs correspond quite accurately with es-timates given by direct marketers based on experienceand show the eligible configuration of the model.If marketing costs were no longer compensated by the

management premium, direct marketers’ revenueswould be reduced. Figure 5 shows AMIRIS simulationresults for the overall profit of the marketers under as-sumption of a decreasing management premium ac-cording to the EEG 2012 (light grey area) and acomplete abolition of the management premium (darkgrey area). The overall profit is defined as the differencebetween total income and costs, and the areas representthe variation of results of the different simulated directmarketers. As can be seen, with a decreasing manage-ment premium, the majority of the marketers still gainpositive overall profit; the reduction of the premium isreflected in the diminution of the profit over the years,with explicit gradient in 2012 and 2013. In contrast, theabolition of the premium implies negative profits for allsimulated types of direct marketers, as the dark greyarea depicts. The decrease of the minimum profit until2019 reflects the increasing expenditures for payments

Figure 5 Overall profits of different direct marketers. Overallprofits of different direct marketers in case of payment of adecreasing management premium according to EEG 2012 (lightgrey area) and in case of abolition of the management premium(dark grey area). Overall profits of direct marketers in tens ofmillions of euros.

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 9 of 13

to installation operators, as the portfolio of the directmarketers still grows in the simulation.Profit losses are accompanied by an increased pressure

to reduce costs that may lower the transaction costs ofmarketing and thus improve efficiency. But as not alldirect marketers may have the possibility to reduce costsas needed, an oligopolisation in the direct marketers’market would weaken the bargaining power of RES pro-ducers [18]. Furthermore, direct marketers would haveto ‘retrieve’ their costs from the installation operators inorder to achieve an at least comparatively balanced ac-count. This would mean that the specific direct market-ing costs could also be interpreted by installationoperators as a corresponding reduction of the remuner-ation rates.Hence, these simulations point to the following pos-

sible risks:

� Market concentration: Direct marketers with largeportfolios have comparatively lower marketing costsbecause economies of scale in power trading and thebroad spatial distribution of RES feed-in installationsreduce costs. This can lead to concentration effectsand create dominant market positions for traders,whose market power can make conditions moredifficult for further RES investments.

� Rising costs: If policy is aimed at preserving today’sdiversity among direct marketers and giving playerswith smaller portfolios a chance to compete in themarket, it must allow higher specific marketing costs

to be compensated, e.g. via a premium. Thecompensation premiums required to promote aheterogeneous market could subsequently result inrising costs of support for electricity from renewableenergy sources.

� Lower remuneration: For installation operators,mandatory direct marketing without payment ofcompensation via the management premium impliesan indirect reduction in remuneration in theamount of the specific marketing costs and areasonable margin of profit for intermediaries. Thiseffect could weaken investment incentives, especiallyfor intermittent RES.

In contrast to the effects on intermittent renewableenergy sources, the introduction of mandatory directmarketing for dispatchable renewables such as biomassinstallations presents a comparatively lower risk. Inaddition, bringing dispatchable renewables onto the mar-ket would increase their flexibilisation potential, pro-vided the financing of a corresponding technologicaldesign is guaranteed.The temporally unlimited fall-back option provided by

§ 38 EEG 2014, meanwhile, is essentially to be wel-comed, as capital investors would otherwise impose sig-nificant risk premiums to account for cases where RESproducers lose their direct marketers [18,38]. However,the 20% cut in remuneration results in substantial in-come losses so that the exploitation of the feed-in tariffin exceptional cases only provides a short-term option,which in turn strengthens the bargaining position of dir-ect marketers. Producers are therefore all the morereliant on strong competition between direct marketers -but precisely this competition may be diminished if econ-omies of scale reduce the number of direct marketingcompanies. Meanwhile, the remuneration of RES gener-ation increasingly depends on the conclusion of individualcontracts and so predictability and transparency suffer.How this will be reflected in risk calculations and invest-ment inclination still has to be examined.Regarding the promotion of demand-oriented feed-in,

it again makes sense to differentiate between dispatch-able and intermittent renewables. In combination withrevenue prospects associated with a participation in bal-ancing markets, the market premium scheme under theEEG 2012 has set meaningful flexibilisation incentivesfor bioenergy plants, particularly for biogas installationseligible for the flexibility premium. In the EEG 2014,there are interactions between market integration incen-tives and the significant general cuts in remuneration forbioenergy. To what extent new biomass installations areeconomically feasible is questionable [52], so that the roleof new installations as a flexibility option in the electricitysystem is likely to be limited. Although, in principle, the

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 10 of 13

limit placed on the amount of electricity eligible for remu-neration in the case of biogas installations provides an in-centive to sell electricity at the highest possible price (seeabove), it is likely to deteriorate further the profitability ofnew installations. Furthermore, in terms of climate im-pacts, the one-sided focus of the eligibility requirementson flexibility should be evaluated critically because con-cepts involving high levels of heat use - which lead tohigher reductions in greenhouse gas emissions comparedto pure electricity production [54] - are neglected. Hence,as a flexibilisation option, mainly existing plants whichcan claim the market premium based on the remunerationunder earlier versions of the EEG are likely to play a role.Here, a flexibility premium that includes solid fuel-powered biomass installations might have been appropri-ate in order to encourage the relevant changes in feed-inbehaviour and make flexibilisation investments worth-while [55].On the side of intermittent renewables, the introduc-

tion of remote control capability as an eligibility require-ment for new installations represents a sensibleamendment [32]. Apart from this, the lack of responsive-ness of intermittent renewables to electricity price sig-nals beyond curtailments continues to be a problem, andit will only be aggravated by cutting remuneration intimes of negative electricity prices. While the marketpremium under the EEG 2012 primarily served to pre-vent negative price spikes, the new regulation is aimedat curtailing production once prices fall below zero forsix or more consecutive hours. This encourages inter-mittent RES producers with near-zero marginal costs tocurtail production before continuously operating con-ventional power plants with positive marginal costs doso - a situation which, from efficiency and climate policyperspectives, does not appear advantageous. At the sametime, the existence of ‘moderate negative prices’ [41], p.104, is considered to constitute an economically reason-able means of sending flexibilisation signals to the oper-ators of conventional power plants [5,18,41]. However,the new regulation largely relieves the latter of responsi-bility for implementing the system transformation; RESoperators tend to bear growing electricity price risks[42,56], while the less frequent occurrence of negativeprices benefits conventional power plant operators, whocan avoid the costs of investing in flexibilisation. Whilethe new regulation might ease the EEG surchargeburden in the short term, the long-term costs oftransforming the electricity system can be expected torise, since flexibility incentives for the system as wholeare reduced.

ConclusionsIn summary, it can be stated that the sliding premium,in the form in which it has been introduced in Germany,

has made a positive contribution to the marketing effi-ciency of dispatchable RES in particular, because it al-lows for an individual optimisation of marketingconcepts including participation in balancing markets.Meanwhile, the benefits of a greater demand orientationof RES feed-in remain limited when considering the ex-tent to which load shifting is incentivised. As a result ofthe sharp cuts in the reference prices for bioenergy inthe EEG 2014, the recently introduced extended flexibili-sation requirements for biogas plants are likely to berelevant for only a small number of new installations.Whether incentives for existing installations will be suffi-cient in the long term to encourage load shifts beyondthe supply of negative balancing energy remains to beinvestigated. For intermittent RES, incentives to encour-age a change in feed-in behaviour are only effective intimes of negative electricity prices when voluntary cur-tailment is encouraged. However, this simultaneouslyleads to a reduction in urgently needed flexibilisationsignals to conventional power plants and other electri-city market players, not least to the demand side or stor-age concepts. This problem is exacerbated by the EEG2014’s cuts in remuneration during prolonged negativeelectricity prices. Meanwhile the fundamental problemof the market integration of intermittent RES with near-zero marginal costs - the fact that an increase in feed-inamounts is associated with a decrease in market value -remains unsolved.Development trends in the market structure of direct

marketing service providers towards few large playerswho can benefit from exploiting economies of scale andtendering broad RES portfolios on the spot market alsoshow that direct marketing provides few structuralchanges compared to marketing through TSOs, at leastin the case of intermittent RES. While the exploitationof economies of scale is linked to reductions in transac-tion costs and so can improve marketing efficiency, anoligopolisation in the direct marketers’ market wouldrepresent a problematic development: insufficient com-petition between direct marketers would in particularweaken the bargaining position of intermittent RES op-erators, whose marketing is associated with higher costscompared to dispatchable renewables. This could have anegative impact on investment incentives.So far, Germany’s experiences with the market pre-

mium and direct marketing suggest that, for the furtherdevelopment of mechanisms to support greater marketproximity, differentiating between the various RES ac-cording to their ability to respond to electricity price sig-nals can prove advantageous [1,19,20]. Given theexperience gained to date, it seems doubtful whether anincrease in short-term electricity price risks can increasethe efficiency of supply of intermittent RES, rather thanjust leading to higher risk premiums or reluctance to

Purkus et al. Energy, Sustainability and Society (2015) 5:12 Page 11 of 13

invest. Under these conditions, it has been suggestedthat rather than making direct marketing obligatory, itmay be advantageous to allow intermittent RES pro-ducers a (non-reversible) choice between central market-ing in combination with a low-risk but also low-profitmargin feed-in tariff and direct marketing in combin-ation with an instrument that promotes market integra-tion more comprehensively than an administered slidingfeed-in premium but compensates price risks with achance of higher returns [19]. Candidates for such an in-strument could be competitively determined feed-in orcapacity premiums, the latter having the advantage ofnot distorting spot market price signals [12,19,57]. Thecontinued marketing of intermittent RES by TSOs, onthe other hand, would require improved access to pro-duction data and incentives to optimise central market-ing of RES electricity. For dispatchable RES such asbioenergy, meanwhile, refinancing models which have astronger competitive element in the determination of re-muneration than the market premium could provide apromising option to encourage operators to design site-optimised installation concepts, which also exploit heatmarketing opportunities [19]. When designing supportfor new installations, it should, however, be taken intoaccount that growing competition for cheap feedstockscould endanger the supply of raw materials and the prof-itability of existing plants [58].Regarding the transition to competitive bidding pro-

cesses as promoted in the EU energy aid guidelines, it isnecessary to critically discuss the question of how astronger integration of different RES in existing electri-city markets can actually contribute to improving secur-ity of supply, reducing the costs of RES expansion andtransforming the electricity system. The case study ofthe German market premium clearly points out thatthese targets cannot be reached through market integra-tion efforts on the part of RES alone. Rather, electricitymarket conditions must also be adapted to the require-ments of RES, and flexibilisation incentives are neededfor other participants in the electricity market [41,59].Considering the uncertainties and country-specific con-ditions that have to be taken into account in a combinedreform of the design of the electricity market and RESsupport mechanisms, competition between systems withdifferent approaches in the different member statescould have advantages over a one-size-fits-all approachas formulated in the EU guidelines on state aid [60].

EndnotesaCalculated according to [33,34] in conjunction with EEG

2012 Annex 4 and the Management Premium Ordinance(MaPrV) 2012 [35]. The exact value is determined by theshare of intermittent RES installations that were eligible to

claim the higher management premium rate for installa-tions with remote control capability.

bWood gasifiers, which are still in an infant stage anddo not play a significant role in the stock of biogas in-stallations, are excluded from the assessment since theydo not participate in direct marketing.

Competing interestsThe authors declare that they have no competing interests.

Authors’ contributionsSeveral authors drafted the different parts of the first version of thismanuscript. All authors contributed to revising and finalising this article.All authors read and approved the final manuscript.

AcknowledgementsJoint research on this paper has been undertaken in the context of theIntegrated Key Topic ‘Regulation, Instruments, Governance’ of the AllianceENERGY-TRANS established by the Helmholtz Association of GermanResearch Centres. Further information can be found at www.energy-trans.de.Furthermore, we would like to thank two anonymous reviewers for helpfulcomments.

Author details1Department of Economics, Helmholtz Centre for Environmental Research - UFZ,Permoser Str. 15, Leipzig 04318, Germany. 2Institute for Infrastructure andResources Management, University of Leipzig, Grimmaische Str. 12, Leipzig 04109,Germany. 3Department of Systems Analysis and Technology Assessment, Instituteof Engineering Thermodynamics, German Aerospace Center (DLR), Wankelstr. 5,Stuttgart 70563, Germany. 4Stuttgart Research Center for Interdisciplinary Risk andInnovation Studies (ZIRIUS), University of Stuttgart, Seidenstr. 36, Stuttgart 70174,Germany.

Received: 5 December 2014 Accepted: 6 March 2015

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