Support Race against the European RES Target

Transcription

1 Support Race against the European RES Target Stephanie Ropenus a*, Stine Grenaa Jensen b a Risø National Laboratory for Sustainable Energy, Technical University of Denmark, P.O. Box 49, DK-4000 Roskilde, Denmark b Danish Energy Association, Rosenoerns Allé 9, DK-1970 Frederiksberg, Denmark. Abstract The new Directive 2009/28/EC stipulates an ambitious, legally binding target of a 20 per cent renewable energy share in overall energy consumption in the European Union by In addition to national support schemes, Member States may implement measures of cooperation, such as statistical transfers, joint or coordinated support mechanisms, and joint projects. National support schemes constitute crucial determinants for the investment decision of renewable electricity producers and can hence no longer be seen in isolation. With the newly adopted Directive and the possibility of measures for cooperation, the interesting question emerges how this will impact the choice and design of national support schemes, i.e., if there will be a convergence or divergence in support scheme design in the race towards the 2020 target. This paper seeks to investigate to what extent we can already observe convergence or divergence in national support scheme design for meeting the renewable energy targets. The analysis consists of two steps: firstly, based on a case study on the support for wind energy in Denmark, Germany and the United Kingdom, the historical evolution of support legislation will be examined to find out if any trends in support scheme design have already materialized. Secondly, a quantitative analysis will discuss the difference in the allocation of risk among investors and the state for the predominant support schemes in place. From this, conclusions will be drawn for future policy implications. Keywords: Support Schemes; Renewable Energy; Feed-in Tariffs; Quota Systems. 1 Introduction An increased deployment of renewable energy sources contributes to the mitigation of climate change while enhancing security of supply, technological innovation and regional development opportunities. Based on these rationales, the new Directive 2009/28/EC on the promotion of the use of energy from renewable energy sources (OJ L 140/16-62) stipulates an ambitious mandatory target of a 20 percent renewable energy share in overall energy consumption in the European Union by For the fulfilment of this Community target, the Directive lays down differentiated national targets to be met by the individual Member States. For the previous objective of achieving a 12 percent share of the European Union s renewable energy in gross domestic energy consumption by 2010 (cf. CEC, 1997), the national targets for renewable electricity (OJ L 283/33-40) were only indicative 1. By contrast, the 2020 overall national targets are legally binding. Notably, Directive 2009/28/EC introduces a new means to facilitate achieving this end: in addition to the implementation of national support schemes, Member States may enter srop@risoe.dtu.dk (Stephanie Ropenus); sgj@danskenergi.dk (Stine Grenaa Jensen). 1 Note that Directive 2001/77/EC (OJ L 283/33-40) lays down indicative national targets to achieve a 22 percent share of electricity produced from renewable energy sources to accomplish the 12 percent share in gross domestic energy consumption by The national targets stipulated by the new Directive 2009/28/EC cover all renewable energy sources, and not only electricity. 1

2 measures of cooperation. The latter comprise statistical transfers 2, joint or partly coordinated support schemes and joint projects. Until now, the choice of support schemes has been to the discretion of Member States in line with Art. 4 of the previous Directive 2001/77/EC (OJ L 283/33-40), and also continues to be so under the new Directive (Art. 3 (3), OJ L 140/16-62). Despite the progressive implementation of an internal market for electricity since 1999 (EU, 2009), there currently exists no common support scheme at the European level. As a result, promotion of renewable electricity generation predominantly constitutes a national affair. With the newly adopted Directive and the possibility of measures for cooperation, the interesting question emerges how this will impact the choice and design of national support schemes. The slow progress in renewable deployment so far can, inter alia, be attributed to the merely indicative nature of the 2010 national targets and the uncertain investment environment provided by the initial European legal framework on renewable energy sources (cf. CEC, 2006; CEC, 2009a). This has been the impetus for the creation of a new, more rigorous framework (cf. CEC, 2009a) by means of the new Directive. Based on the assumption of Member States striving for a stringent fulfilment of their national 2020 targets either on their own or through joint measures, this may lead to increased competition between Member States for creating favourable support schemes so as to attract renewable energy producers. When choosing a site for new generation capacity, investors have an incentive to deploy renewable electricity production in Member States with attractive investment conditions, i.e., where the level of national support is high and where there is investment certainty. This could result in investors cherry-picking among support schemes applied in the different countries. For the race towards the 2020 target, two effects may be induced: on the one hand, national support schemes may converge as their attractiveness will become the driver for the deployment of renewable energy in Europe. The implementation of joint or coordinated promotion schemes can further reinforce this process. On the other hand, there might be a divergence in support levels and design if the instrument of statistical transfers is increasingly used. This paper seeks to investigate to what extent we can already observe convergence or divergence in national support scheme design for meeting the renewable energy targets. The analysis is based on a case study on the evolution of support for wind energy in three Member States, i.e., Denmark, Germany and the United Kingdom. Wind energy seemed a natural candidate for this analysis as the European Union (EU) considers it one of the most promising renewable energy technologies (cf. CEC, 2009b). Cumulative wind power capacity increased on average by 32 percent per year between 1995 and 2005 (ibid). Furthermore, the focus of this study is on Denmark, Germany and the United Kingdom since these Member States have adopted three different types of the most prominent support schemes: price-premium, the classical feed-in tariff, and a quota system with tradable green certificates. The analysis of this paper proceeds in two steps: firstly, there is a qualitative analysis on the choice and design of support in the three country cases. Secondly, a quantitative analysis on support levels examines the allocation of risk among the state and wind project investors. The remainder of this paper is organized as follows: Section 2 describes the theory of support schemes and investor incentives as the theoretical background for the analysis. Section 3 contains the qualitative analysis consisting of the case study on the evolution of support for wind energy in the three selected countries. Section 4 investigates quantitatively the interrelation of uncertainty 2 The measure of statistical transfers allows Member States to enter arrangements for the statistical transfer of a specified amount of electricity based on renewable energy sources from one country to another (Art. 6, Dir. 2009/28/EC). 2

3 for financing and receiving support and volatile power prices for the different support schemes. Based on these results, Section 5 discusses the implications of the future evolution of support schemes and investment uncertainty under the different regimes in the light of EU policy for the attainment of the 2020 target. 2 Theoretical Background The effectiveness of support for future target compliance is dependent on the implementation of measures of cooperation, as well as on the existence of current support schemes and associated investor incentives. Converging support schemes may allow for easier coordination of support and, eventually, the implementation of a joint mechanism, whereas diverging support levels and design may encourage statistical transfers. This Section introduces the theoretical background on support schemes and investor incentives for the subsequent discussion. 2.1 Joint vs. National Target Compliance In a perfectly functioning market without restrictions, the price for renewable electricity is based on the level of marginal cost of the most costly renewable generation unit that has to be deployed to meet the target. The support required for renewable electricity compared to conventional electricity production technologies is determined from the difference between the cost of renewable electricity generation and the power price. In an idealistic, perfectly competitive setting, feed-in tariffs, price premiums and quota systems with tradable green certificates can achieve an equivalent market outcome, i.e., all three promotion schemes can induce the same amount of renewable electricity deployment at the same price level. Their distinguishing feature lies in the composition of support. Under a classical feedin tariff, qualified generators obtain a pre-set price per kilowatt-hour for their renewable electricity, fixed at a level above the market price. The price premium constitutes a more marketbased variant of this scheme: renewable power producers sell their electricity at the market price and receive a fixed premium in addition. Quota systems with tradable green certificates represent the most market-based system of the three: in contrast to a feed-in tariff scheme, here the quantity is pre-set in the form of a quota of renewable electricity in total electricity generation or consumption. Entitled producers obtain for their green electricity the market price for electricity and a corresponding number of green certificates. The latter can be sold in a separate financial green certificate market and thereby realize an additional income (cf. Jensen and Skytte, 2003). In an ideal quota system with tradable green certificates, the price of a certificate corresponds to the difference between the power price and the cost of the marginal renewable generation unit (Figure 1). For an equivalent outcome under a feed-in tariff scheme, the feed-in tariff would have to be set at the level equal to the power price plus the certificate price. As for the price premium, when the premium equals the certificate price, the same market outcome is realized. The following elaboration on target fulfilment by means of quota systems can hence straightforwardly be extended to the application of feed-in tariffs and price premiums. If a technology generates renewable power at a lower cost level than the electricity market price, the producer earns a producer surplus both from the electricity market and from the support scheme (Figure 1). By contrast, renewable electricity producers incurring higher costs than the electricity price will only obtain a surplus from the support scheme 3. 3 Note that this distribution of producer surplus inherently assumes marginal bid pricing. Under this approach, all producers get paid the price of the marginal bid; this encompasses also those producers that would be willing to supply green electricity for a lower price, and they hence obtain an extra surplus. By contrast, in a pay-as-bid auction, producers would receive the price they bid (cf. Boisseleau, 2004, p. 83). 3

4 Figure 1: Renewable electricity target fulfilment in a quota scheme. QR: renewable energy production. The difference between purely national support and harmonized support schemes can be illustrated with two representative countries A and B, which have different renewable resource endowments and resulting cost curves as well as different national targets (Figure 2). Figure 2: Target compliance with national and common support schemes for the two countries. P: price, C: fixed cost, Target: renewable energy target, QR: renewable energy production, A: country A, B: country B. In the case of national target compliance, each country adopts a support scheme that ensures the fulfilment of its national target level for renewable electricity, i.e., green electricity producers in the two countries receive different levels of support according to their respective national target and their marginal cost curves, C A and C B. In the example, Country A has a higher target as well as a higher price for support than Country B. National target compliance does not maximize social welfare since each country sub-optimizes its production of renewable electricity. As a result, society experiences a welfare loss caused by excess production by Country A and undersupply by Country B in meeting the aggregate renewable target (target A+B ). 4

5 By contrast, under joint target compliance by the two countries, optimal production levels and a common price for renewable support can be realized. The common renewable electricity supply curve (RES-supply A+B ) is obtained by the horizontal summation of the marginal cost curves of Country A and B; the common market price is then P A+B. In markets with physical trade restrictions, such as electricity markets, equal prices cannot always be realized due to transmission constraints. However, as for most promotion schemes, renewable support is a purely financial commodity; hence, common prices are obtainable. Nevertheless, it is important to mention that even financial power markets and support schemes are still linked to the physical commodity electricity. Consequently, the interaction between physical and financial markets would influence the optimal solution of the illustrated setup above in a more complex, realistic setting (cf. OPTRES, 2007). Notably, the above results aim at welfare optimization and not necessarily at minimizing consumer cost, i.e., the product of total price and quantity. This is because in welfare economics, social surplus is equal to the unweighted sum of producer and consumer surplus. 2.2 Investor incentives The deployment of renewable electricity generation technologies constitutes a long-term investment decision. This kind of decision is based on expectations with respect to the long-term evolution of electricity prices, prices on resource markets, duration and design of support schemes, the regulatory framework (e.g., network regulation and access charges), as well as market conditions. In more general categories, investors face regulatory risk, market risk and technological risk. Inherently, at the early stages of the technological development process, i.e., during the pioneer and the introduction phase, technological risk dominates regulatory and market risk (or, broadly, systemic risk). A reversal in the risk structure occurs at later stages of market penetration, that is, once a technology has entered the market and become commercially viable. Then, regulatory and subsequently market risk will prevail. In an analysis on risk for renewable energy technologies carried out by the research project OPTRES (OPTRES, 2007), a questionnaire for investors investigated their ranking of selected risk parameters. Notably, financial change of support system, conditions on access to the grid, and planning and permit risk were perceived as the three highest risk parameters. The results of this study indicate that traditional risk parameters, such as investment cost and production insecurity, do not get attached as a high weight as political and regulatory risk. The domination of the latter type of risk implies that investors tend to choose a risk mitigation strategy accounting for these factors in their investment decision. 3 Convergence or Divergence of Support In order to investigate whether there is a convergence of support mechanisms for the three selected Member States in our case study, i.e., Denmark, Germany and the United Kingdom, we take two consecutive steps: firstly, we examine how the choice and qualitative design of the mechanisms in each country have historically developed and been readjusted over time. This qualitative part of the analysis serves to shed light on whether support scheme design has converged or diverged in the past 20 years. The review of national support legislation begins with the classical feed-in tariff in Germany, followed by the price premium in Denmark, and, finally, the quota system with tradable green certificates applied in the United Kingdom. Subsequently, there will be a discussion drawing conclusions on the overall evolution of support scheme design in the three Member States. 5

6 3.1 Germany: The Classical Feed-in Tariff Germany has a long tradition of the classical feed-in tariff scheme. The precursor to current legislation on support for renewable energy sources was adopted in 1990: from 1991, the Energy Feed-In Law (Stromeinspeisegesetz, 1990) imposed an obligation on electric utilities to purchase electricity produced by renewable energy sources in their service area and to compensate the suppliers of this electricity in accordance with the tariff provisions laid down by the law. The level of support was determined as a fixed percentage of the average revenue per kilowatt-hour (kwh) for the provision of electricity by the electric utilities to end consumers, i.e., support was coupled to retail prices. The next major stepping stone in legislation on renewable support occurred ten years later in 2000 with the adoption of The Act on Granting Priority to Renewable Energy Sources (Gesetz für den Vorrang erneuerbarer Energien, (EEG, 2000)). The linking of feed-in tariff levels to historical retail prices was abolished. Instead, investment security was provided through a fixed payment per kwh of green electricity produced, with differentiated tariff rates for the different technologies. These feed-in payments were guaranteed for a (maximum) period of 20 years. The EEG (2000) imposed an obligation on grid operators to connect renewable electricity generation installations to their grids, to purchase electricity from these installations as a priority and to compensate green producers with feed-in payments as stipulated by the law. Wind installations obtained different rates on the basis of a technology-neutral yield reference model. More specifically, wind installations (except offshore) should receive at least 9.1 ct/kwh as an initial tariff for the first five years. Thereafter, they were entitled to a tariff of at least 6.19 ct/kwh. Installations that had not achieved 150 percent of the reference yield received a prolongation of the initial tariff by two months for every 0.75 per cent which their yield stayed below 150 per cent of the reference yield 4. Using the yield as a calculation basis led to lower promotion levels at sites with very good wind conditions and to higher support levels under less advantageous wind conditions (cf. Ragwitz and Huber, 2005). For offshore plants that had been online before 31st of December 2006, the initial tariff period was longer than for onshore wind and amounted to nine years. Furthermore, the EEG (2000) stipulated a degression of tariffs: the feed-in payments had to be reduced annually by 1.5 per cent for new wind installations commissioned after the beginning of In 2001, at the European level Directive 2001/77/EC was adopted. Subsequent to a review of the EEG (2000) (cf. Begründung EEG 2004, p. 6), a revised version of the Renewable Energy Sources Act entered into force in 2004 (EEG, 2004). In the meantime, the capacity of wind installations had more than doubled from 2000 to 2003, with a capacity of 14,000 MW at the end of Electricity generation cost from wind energy had been more than halved compared to cost levels at the beginning of the 1990s (Begründung EEG 2004, p. 6). Hence, the revised EEG (2004) introduced a downward adjustment of the feed-in tariff for onshore wind installations to 5.5 ct/kwh and an initial tariff of at least 8.7 ct/kwh 5. For plants commissioned after 1st of January 2005 the annual reduction of the feed-in tariff was increased to 2 per cent (before: 1.5 per cent). The feed-in tariff level for offshore wind plants of 6.19 ct/kwh was maintained. However, the time period of the initial feed-in tariff level of 9.1 ct/kwh was increased to twelve years for offshore plants online no later than 31st of December Moreover, the degression in feed-in 4 For existing installations, the date of commissioning should be 1 st of April The initial tariff period was reduced by half of the operating life of an installation as of 1 st of April ( 7(2), EEG (2000)), though, it has to amount to at least four years from 1 st of April 2000 (ibid). 5 For wind installations that did not achieve 150 per cent of the reference yield during these initial five years, this period could be prolonged in the same fashion as laid down by the EEG (2000) ( 10(1), EEG (2004)). 6

7 payments for offshore wind installations was suspended until the beginning of 2008 and amounted thereafter also to an annual tariff reduction by 2 per cent. The most recent revision of the EEG (EEG, 2009) takes the promotion of electricity from renewable energy sources one step further to the market on a voluntary basis. Producers can choose between direct selling of their electricity to the market and obtaining the regular feed-in tariff scheme. Direct selling allows installation operators to sell their electricity directly to third parties on a calendar-monthly basis if they have reported this to the grid system operator before the start of the previous calendar month. During the month in which they choose direct selling, they are not entitled to the regular feed-in tariff payments, and this applies to total electricity produced in the installation. Alternatively, installation operators may opt for only selling a certain percentage of their electricity produced in the installation and claim the tariff for the remaining share of electricity. If installation operators wish to switch from direct selling in one calendar month to receiving the feed-in tariff in the following calendar month, they are free to do so provided they report this to the obligated grid system operator before the start of the previous calendar month. As for the feed-in tariff levels, under the new EEG (2009), onshore wind installations are entitled to a fixed payment of 5.02 ct/kwh. The initial tariff level during the first five years amounts to 9.2 ct/kwh and is hence set to a level above those of the two previous versions of the EEG. Additionally, a new element for the remuneration of wind has been introduced by means of a system services bonus (Systemdienstleistungs-Bonus). The latter is paid on top of the initial tariff for five years to installations that fulfill specific requirements laid down by the law. For installations commissioned before 2014, this bonus amounts to 0.5 ct/kwh, and for plants commissioned after 31st December 2001 and prior to 1st January 2009 to 0.7 ct/kwh. The degression of both the tariff and boni for wind is set to 1 per cent. The duration of support is maintained with 20 calendar years. For wind offshore, the feed-in tariff has been set to 3.5 ct/kwh, and the initial tariff paid during the first twelve years amounts to 13ct/kWh 6. Until 2014, there is no degression of the tariff for offshore plants, but from 2015, a degression of 5 per cent is introduced. EEG 2004 Wind onshore Wind offshore EEG 2009 Wind onshore Wind offshore Table 1: Support levels according to recent German legislation Level of Support [ct/kwh] Degression Remarks 8.7 (initial tariff) (initial tariff) (initial tariff) (initial tariff) 3.5 2% 2% (from 2008) 1% 0% (until 2014) 5% (from 2015) Initial tariff at least 5 years, prolongation up to 20 years dependent on reference yield. Initial tariff for 12 years for plants commissioned before 2011; prolongation up to 20 years dependent on reference yield. Initial tariff at least 5 years, prolongation up to 20 years dependent on reference yield. Initial tariff for 12 years. 6 Installations commissioned prior to 1st January 2016, receive a 2.0 ct/kwh higher initial tariff. 7

8 3.2 Denmark: From Feed-in Tariff to Price Premium In Denmark, support for electricity production is financed as a public service obligation paid by all Danish electricity consumers. The cost to consumers is specified in a memo on PSO-expenses, and is administered by the state-owned Danish transmission system operator Energinet.dk. Prior to the electricity reform in 1999, a support scheme in the form of a fixed feed-in tariff was applied to Danish wind power producers. The electricity reform implemented liberalization of the Danish electricity market and also included a redesign of the support to wind power producers from a pre-reform high feed-in tariff uniform to all wind power installations to different tariffs distinguishing between old/new and onshore/offshore wind power installations. The redesigned tariffs aimed at eliminating or reducing the support to wind power over a transition period leading to an integrated Nord Pool electricity market. The electricity reform maintained feed-in tariffs, but the tariffs were only applied for a restricted period of time. The new tariff was lowered to 5.8 ct/kwh from 8 ct/kwh with a production limit of full load hours 7. Thereafter, the owner received a premium of 1.6 ct/kwh on top of the market price (including compensation for balancing costs of 0.3 ct/kwh) until the wind turbine had reached an age of 20 years. In 2002 the level of support was adjusted because from January 2003 wind producers had to sell electricity on the Nord Pool spot market 8 : the support was changed from a fixed feed-in to a premium system valid for turbines connected to the grid after January On top of the market price, a general subsidy of 1.6 ct/kwh (including compensation for balancing costs of 0.3 ct/kwh) was offered for a 20-year period. If the spot price plus the premium exceeded 4.8 ct/kwh the premium was lowered. This upper income limit was removed in January 2005 (Munksgaard and Morthorst, 2008). Specific tariff levels applied for wind turbines commissioned before Differentiated according to their date of commissioning, these earlier installed wind turbines were additionally guaranteed a certain minimum price, i.e., a minimum level of support consisting of the premium plus the electricity price. The development of offshore wind power in Denmark was founded on a tendering procedure, and a strong planning process was initiated before the electricity reform. During 2003, four specific offshore areas were selected as relevant sites for tendering. By applying a tendering procedure, the government calls for competition among bidders in order to ensure a cost-effective windpower development. In 2007, a plan for offshore sites laid down recommendations for future offshore planning (DEA, 2007a), including Djursland-Anholt, Horns Rev, Jammerbugten, Store Middelgrund, Kriegers Flak and Rønne Banke. In previous settlements, most of the existing Danish offshore capacity had been established in accordance with an agreement between the Danish Government and the power companies, e.g., for the offshore farms Horns Rev I and Nysted I. These two wind farms are guaranteed a feed-in tariff of 6.1 ct/kwh (including compensation for balancing of 0.3 ct/kwh) up to a limit of 42,000 full-load hours. Additional electricity production will be traded according to the following tariff: market spot price plus a premium of 1.3 ct/kwh, plus a balancing compensation of 0.3 ct/kwh, until the wind farm has been in operation for 20 years. Thereafter, only the spot price will be paid for power production from these wind farms. At the beginning of 2007, the Danish Government presented a new long-term energy strategy (DEA, 2007b). In December 2008 a new, self-contained law on renewable energy (Lov om fremme af vedvarende energi, VE 1392) was passed to remove the support provisions for renewable energy technologies from the Danish electricity law (Elforsyningslov, 1999) and to 7 Full load hours: Maximum capacity use for 1 h of production, i.e. when wind speed is optimal a 600kW wind turbine produces 600 kwh in one full-load hour. 8 Note that the Nord Pool spot market is a day-ahead market in order to clarify terminology. 8

9 create investment incentives for meeting the 2020 target. The level of support was increased for electricity produced from biomass, biogas and wind turbines (VE 1392, 2008). For onshore wind the price premium is set to 3.4 ct/kwh for the first 22,000 full load hours produced. Thereafter, electricity is only sold through the power exchange. There is an additional support on 0.3 ct/kwh for balancing during the entire lifetime of a wind turbine. For offshore turbines, subsidies are still determined via public tendering, and hence, the support is to be settled by a call for tenders on the concession. A new tender for 400 Megawatt wind turbines at sea near Anholt is open for bids (DEA, 2008). It is worth mentioning, though, that a new restriction has been imposed on the tender at Anholt, which limits the support to hours where the spot market price is positive 9. Table 2: Support levels according to recent Danish legislation Level of Support System Bonus Remarks [ct/kwh] [ct/kwh] Electricity Law (2003) Wind onshore Wind offshore 1.3 (premium) (fixed feed-in) (Horns Rev II, 200 MW) VE 1392 (Renewable Energy Law of 2008) Wind onshore Wind offshore 3.4 (premium) (fixed feed-in) (Roedsand II, 200 MW) Duration 20 years. Maximum on the spot price plus the premium at 4.8 ct/kwh. - Duration for 50,000 full load hours. - Duration for 22,000 full load hours, no degression in subsidy. Duration for 50,000 full load hours, no degression in subsidy. 3.3 United Kingdom: Market-Based Quota System The United Kingdom applies a market based support scheme in the form of a quota system with tradable green certificates, called the Renewables Obligation (RO). Precursor to the RO was the Non-Fossil-Fuel Obligation (NFFO) adopted in 1990, encompassing technology-specific bands for support and subject to several revisions (cf. Mitchell and Connor, 2004, for a detailed overview). In April 2002, the first Renewables Obligation Order (RO, 2002) for England and Wales came into force. The RO (2002) was subject to review various times, i.e., in 2004, 2005, 2006 and, most recently, in 2009 (RO, 2009). The RO imposes an obligation on designated electricity suppliers in England and Wales to submit for each megawatt hour of electricity a certain amount of Renewables Obligation Certificates (ROCs) to the Authority to comply with the percentage requirement stipulated by the Renewables Obligation Order (RO, 2009). A ROC is a certificate issued to accredited generators for their qualified renewable power generation under the RO (Art. 34, RO (2009)). Hence, the RO is a downstream certificate system, i.e., generators represent the sellers on the certificate market, and electricity suppliers constitute certificate demand. Electricity suppliers have the possibility of banking certificates: they may discharge up to 25 per cent of their renewables obligation by submitting ROCs obtained in the directly preceding obligation period. For the period from 1 st April 2009 to 31 st March 2010, the renewables obligation amounts to ROCs per MWh of electricity supplied in Great Britain. This percentage requirement is successively increased to a quota of for the period of 9 The tender states that: A price supplement shall not be paid for production during hours in which the spot price is not positive. This, however, shall only apply for a maximum of 300 hours per year. (DEA, 2009) 9

10 1 st April to 31 st March 2016, and subsequently maintained at this level until 31 st March In the previous RO Orders, all technologies got issued one ROC corresponding to one Megawatt. Differentiation according to technologies has been introduced by the new RO (2009) by means of banding: e.g., electricity from co-firing of biomass obtains a ROC corresponding to 2 MWh of production, hydro-power 1 MWh, and solar-photovoltaic ½ MWh. Onshore wind is entitled to a ROC for 1 MWh, and offshore wind to a ROC for 2/3 MWh. If electricity suppliers do not submit the required amount of ROCs by the 1 st September in the settlement period, they can fulfil their obligation by paying a so-called buy-out price for a ROC to the Authority. Notably, electricity suppliers can also opt for surrendering ROCs to meet part of their obligation and to pay the buyout price for the remainder. The buy-out price for the period commencing on 1 st April 2009 is set to and adjusted to changes in the retail price index for subsequent periods. If the buy-out fund exceeds the payments to be made into the Consolidated Fund and to the Northern Ireland authority according to the provisions in Art. 45 (RO, 2009), then the Authority must pay the balance of the buyout to United Kingdom suppliers in proportion of their submitted ROCs by the 1 st of November in the settlement period as stipulated by Art. 47 (RO, 2009). Similar provisions apply to the late payment fund (cf. Art. 46f., RO (2009)). The value of a ROC hence consists of the buy-out price plus the money recycled from the buy-out funds (IEA, 2009). Table 3 provides an overview of the value of a ROC to a supplier for the compliance periods from 2004 to The second column depicts the buy-out paid per ROC produced, which includes the sums redistributed from the buy-out and late payment funds. The third column indicates the buy-out price. Eventually, the fourth column consists of the sum of the latter two columns, i.e., the sum of the buy-out price plus redistribution from the buy-out and late payment funds accruing to suppliers (the buy-out price being the price suppliers avoid paying by presenting ROCs). Obligation Period Table 3 : Value of ROC to a supplier Buy-out paid per ROC produced Buy-out price What a ROC was worth to a supplier Source: OFGEM (2009) 3.4 Overall Evolution of Support from a Qualitative Design Perspective The review of national support schemes reveals that we can observe convergence in qualitative support scheme design, with a clear predominance of technology-differentiated support (Figure 3). The two price-based systems have moved from a traditional feed-in tariff scheme to the implementation of more market-based design features. In Germany there has been a long tradition of a feed-in tariff regime with individual financial support levels for qualified technologies and even for accounting of the specific conditions within one technology, such as differentiated tariff levels and duration of support for wind onshore and offshore. The recent adoption of the possibility of direct selling constitutes a step towards voluntary market participation. Denmark has moved from the traditional feed-in tariff system to the more marketbased variant of a price premium. Initially, the implementation of the price premium was still accompanied by price limits in support and guaranteed minimum support levels for earlier commissioned wind turbines. This check on maximum and minimum levels of support for wind 10 The precise mathematical determination of the renewables obligation for one obligation period in terms of megawatt hours of renewable electricity supplied is laid down by Art (RO, 2009) based on the comparison of three calculations using estimates of total amount of electricity supplied to consumers in Great Britain and estimates on the total amount of renewable electricity supplied in the United Kingdom. 10

11 has subsequently been removed with increasing commercial viability of the technology. By contrast, in the United Kingdom, after the existence of technology bands under the Non-Fossil Fuel Obligation, the Renewables Obligation was adopted as a technology-neutral support mechanism; that is, one ROC represented one megawatt hour of qualified renewable electricity generation (cf. Art. 5 (4c), RO (2002)) irrespective of the technology deployed. The most recent revision of legislation in 2009 (RO, 2009) re-introduced banding by assigning weighted entitlements to ROCs differentiated according to technologies. Technology-neutral support, such as earlier versions of the Renewables Obligation, introduces inter-technology competition: the underlying rational is that it provides a strong incentive for investors across all technologies to decrease cost as they face both inter- and intra-technology competition, and only the most cost efficient technologies will be able to sustain in the market. Inherently, one drawback of the implementation of this feature is that emerging, currently immature technologies, which may have a potential to become cost-effective in the future due to learning effects, may not be able to enter the market and be abandoned at an early stage. Based on this reasoning, technology-differentiated support accounts for the differences in technology development and typically provides higher support levels to those technologies that are in earlier stages of the learning curve. As a technology becomes more mature, support levels are adjusted accordingly. Based on this reasoning, technology differentiation has become a major characteristic of support scheme design in the three selected countries. Figure 3 depicts the evolution and convergence of support schemes. Quota system UK NFFO (1990) UK RO (2002, 2004, 2005, 2006) UK RO (2009) Banding DK Feed-In GER Feed-In Law (1991) DK El. Law (1999) Time Limited FIT GER DK Premium (2003) GER EEG (2000) EEG (2004) DK Law 1392 (2008) GER EEG (2009) Direct selling Pre-Liberalization Feed-in tariff Post-Liberalization Figure 3: Convergence of support schemes in Denmark, Germany and the United Kingdom 11

12 4 Risk Exposure and Support The different degrees of exposure to the volatility of market prices depend on the type of support scheme in place. The choice of support scheme can hence be regarded as a matter of risk allocation among investors/generators and the state/consumers for financing a technology. This Section seeks to investigate the implications of risk for investors and the state in financing the support. 4.1 Theoretical Background to Analysis The profits of investors and/or operators of wind turbines are composed of the revenue obtained through electricity sales minus the cost incurred for investment and variable cost for operation and maintenance (O&M) of the turbine. Disregarding the potentially different cost conditions for individual wind sites, we assume that operators of wind turbines face identical costs in all three countries. Furthermore, they are price takers, i.e., in market-based systems they do not exert any influence on the market price, but take it as given. Ceteris paribus, a wind operator s investment decision for an individual country will hinge on the expected revenue, which in turn depends on the type and level of national support. Based on the assumption of identical cost, we can hence apply a revenue calculation instead of computing the return on investment for comparing the investor attractiveness of the different support schemes in our case study. Notably, feed-in tariffs, price premiums and green certificate systems differ to the extent to which wind operators are exposed to the volatility of market prices (cf. Ropenus et al., 2009). Mathematically, we can express the profit of a wind operator as π ( q) = R( q) C( q), (1) where q denotes the electricity output produced by wind energy, π denotes profit, R the revenue, and C the cost. In the following, a simplified analytical representation of three support schemes will be given so as to illustrate the different degrees of exposure to price volatility 11. Under the traditional feed-in tariff scheme, as applied in Germany, wind operators receive a fixed tariff completely independent of fluctuations in the market price. The revenue of the wind operator is then given by R ( q) = Tq. (2) For the investor, the feed-in tariff T constitutes a completely exogenous variable, only subject to a pre-determined yearly degression if so stipulated by law 12. By contrast, in the case of a price premium, as implemented in Denmark, wind operators obtain the market price for electricity p and a fixed premium p in addition to the market price: E R ( q) = peq+ pq. (3) Finally, as for the quota system with tradable green certificates, wind investors earn revenue from selling electricity at the market price p and by obtaining the certificate price p : E C 11 The following elaboration in this subsection is inspired by the D3 IMPROGRES Deliverable (Ropenus et al., 2009). 12 In our subsequent analysis, we abstract from the provision of system services and additional revenue stemming from a system bonus. 12

13 R ( q) = peq+ pcq, (4) where both prices are determined on the market, i.e., wind operators are exposed to the highest degree of price volatility of the three schemes. 4.2 Assumptions For the subsequent analysis, feed-in tariffs are compared to a price premium scheme in order to illustrate the impact of the volatility of power prices (quota systems have been excluded from this part of the analysis as the immediate effect can more easily be demonstrated for the case in which only one price, i.e., the power price, is subject to changes). The following results have been derived based on a Monte Carlo simulation. We assume an average power price of 50 /MWh (E(p E )=50 /MWh), with a standard deviation of 10 per cent, corresponding to 5 /MWh. As for the comparison of a price premium to a fixed feed-in tariff scheme, the following parameters have been chosen: the fixed feed-in tariff is set to a level of 84 /MWh, while the price premium amounts to 34 /MWh. This way, the expected average income for the wind turbine investor and the expected average expenditure for the state is equivalent under the fixed feed-in tariff and the premium system. Support [ /MWh] is granted for a duration of 22,000 full load hours. Production takes place 2000 hours/year/mw, and the discount rate is 6 per cent. Figure 4 illustrates the correlation between the adopted support scheme and the power price. The opposite uncertainty impact of different power price levels on wind turbine investors and the state can clearly be seen: under a fixed feed-in tariff scheme, the turbine investor obtains a rather fixed level of support, while the amount of support to be financed by the state drops with increasing power price levels. This is because the state has to pay the entire feed-in tariff and has to compensate for the gap between the power price and the pre-set tariff. This gap decreases as the power price rises. By contrast, under a premium scheme, state expenditure is fixed irrespective of the power price, whereas the turbine investor s income increases when the power price rises. In fact, under a premium system, the state has no risk exposure in its financing of support. Independently of the actual power price, the state pays on average 19 /MWh for the wind power production over a 20 years lifetime (Figure 5). Note that the average expenditure of the state corresponds to 19 /MWh spread over the 20 years since support is only granted for the initial 22,000 full load hours /MWh Power Price ( /MWh) Turbine income-fixed Turbine income-premium State expenditure-fixed State expenditure-premium Figure 4: Correlation of support scheme and power price 13

14 The wind turbine investor receives revenue composed of the premium and the power market price. On average, this revenue equals the fixed feed-in tariff; however, due to the inclusion of uncertainty in power prices, wind turbine owners experience an uncertainty with a standard deviation at 3.42 in their total income (Figure 5). Figure 5: Support financed by state and investor income under price premium For a fixed feed-in tariff scheme, we obtain quite the opposite uncertainty distribution: the fixed amount the wind turbine investor obtains from the state over the 20 years lifetime of the turbine equals on average the income in the case of the premium at 19 /MWh. In contrast to the premium system, here the state is exposed to a higher degree of uncertainty in financing the tariff, with a standard deviation of That is, in 50 percent of the cases the support lies between 16 and 21 /MWh (Figure 6). As opposed to the state, under a traditional feed-in tariff regime, for the wind turbine investor the income is not particularly sensitive towards changes in the power price. Note that the slight dispersion in income results from the duration of fixed support being limited to 22,000 full load hours. Thereafter, the turbine investor has to sell electricity on the power market. The exposition to power prices leads to a slight uncertainty in income with a standard deviation of 0.64, i.e., the income lies between 52 and 54 in 50 percent of the cases (Figure 6). Figure 6 Support financed by state and investor income under fixed feed-in tariff 14

15 5 Discussion and Conclusions From the above analyses, several conclusions with implications for the race towards the 2020 target can be drawn. Firstly, in qualitative terms, we can observe a convergence of support scheme design for wind energy in Denmark, Germany and the United Kingdom. Secondly, the quantitative analysis revealed that the uncertainty in expenditure for financing support is higher for the state under a feed-in tariff scheme as compared to a price premium, while the opposite is true for the uncertainty in revenue of wind turbine investors. As illustrated by Table 4, great importance accrues to the level of the power price: under a fixed feed-in tariff, the income of turbine investors is almost constant, whereas the state incurs high expenditure if the power price is low. State expenditure Turbine income Power Price Premium Fixed Premium Fixed Low Constant High Low Almost constant 13 Medium (50) Medium (19) Medium (19) Medium (53) Medium (53) High Constant Low High Almost constant Table 4: Effect of the power price for state expenditure and turbine income for 20 years lifetime. In the case of a premium, the state faces constant expenditure for financing support, while the turbine investors are fully exposed to the volatility of the power price. The uncertainty for state expenditure and income of turbine investors is also reflected by the respective standard deviations under the different systems, as indicated by Table 5. Support State Turbine Premium Fixed Table 5: Standard deviation for state expenditure on support and turbine income for 20 years lifetime in the two cases: fixed feed-in and premium feed-in. Regarding the future evolution of national support, three aspects should be highlighted in this final discussion. Firstly, investors decisions are dependent on their risk-attitudes, i.e., whether they exhibit risk-averse, risk-neutral or risk-seeking behaviour. This in turn is reflected by the value they attach to the risk premium and the risk-free return in their expected return on investment. When choosing a country in which to deploy a renewable energy project, investors take the systemic risk into account in their investment decisions. E.g., the implementation of quota systems has by far failed to produce results in renewable electricity capacity growth comparable to those of feed-in tariff schemes and implied higher costs; this reflects the higher risks for operators of generation facilities and the potential profit-taking effects (Böhme and Dürrschmidt, 2007). By contrast, the investment security under feed-in tariff schemes becomes particularly evident in Germany and Spain, where wind energy output rose by 700 percent and 2266 percent, respectively, between 1993 and 1999 (Ecotec, 2001) subsequent to the implementation of support. 13 The income is not totally constant as the duration of the support is 22,000 full load hours. 15

16 Secondly, the decision maker on the design of support mechanisms is the state (or associated authorities). In its decision on support scheme design, the state has to counterbalance the objective of providing sufficient investment security for the achievement of the national 2020 target on the one hand, and the impact on state expenditure (budget) on the other hand. Thirdly, in terms of risk, there exist two natural ways in which random outcomes can be compared: according to the level of returns and according to the dispersion of returns (cf. Mas- Colell et al., 1995, pp. 194ff.). The quantitative analysis was based on the assumption of an average state expenditure of 19 /MWh under both the premium and the traditional feed-in tariff to illustrate the implication of power price fluctuations for the two schemes. Hence, the quantitative analysis focused on the latter way of comparison of random outcomes, i.e., the dispersion of expenses/returns with a mean-preserving spread. However, the average level of state expenses under the two different schemes may additionally diverge if the overall distribution of power prices exhibits a long-term upward or downward trend. The results from Table 4 elaborated on above provide some indication on the implications for state expenditure and investors income under each support scheme in the case of changing long-term price trends. On the whole, a future convergence or divergence of national support schemes depends on the incentives of states for nationally reaching their legally binding 2020 targets and their preference on the allocation of risk among themselves and investors. The possibility of statistical transfers may create an incentive for some Member States to implement more market-based schemes implying higher uncertainty for investors, and potentially also higher uncertainty for the achievement of the 2020 renewable target at a national level. This may lead to a divergence of national support scheme design if the latter receive statistical transfers from Member States applying less market-based systems. On the other hand, statistical transfers may prove to facilitate the transition period to a convergence of support schemes during which promotion schemes with different degrees of exposure to market prices are in place. Furthermore, combined with the implementation of joint or coordinated support schemes, the application of statistical transfers may indeed contribute to a more cost efficient attainment of the common 2020 target. Various studies have quantified potential gains of coordinated action and trading in reaching the 2020 target in their estimations. E.g., a study conducted by Eurelectric and Econ Poyry (Eurelectric, 2008) estimates that allowing EU Member States full flexibility to meet their renewable energy targets by trading certificates could save 17 billion per year by At present, it is difficult to conclude if the presently observed convergence of support schemes in the three selected countries of our case study will materialize across the entire European Union and, notably, over which period of time. In order to create equitable conditions for investors from a support scheme point of view, a harmonization across the EU seems a prerequisite. However, even subsequent to the implementation of a full harmonization of support, there will still be differences in national regulation (e.g., network regulation), administrative requirements and, notably, resource endowments that affect the investment decision. Hence, there exists a trade-off between the creation of a level playing field in renewable energy promotion and accounting for specific national circumstances in other areas that may have an effect on renewable deployment as well. For the long term, the question arises if and when harmonization of support will occur and which type of common support scheme will be implemented then. Ideally, a convergence of national support mechanisms and measures of coordination would facilitate this process. Then, a common and smooth transition to more market-based support could be introduced as renewable electricity generation technologies become increasingly mature. 16