1 DISCUSSION PAPER 3 The Impact of PV on the German Power Market Or Why the Debate on PV Feed-In Tariffs Needs to be Reopened Hamburg, August 21 Sven Bode and Helmuth-M. Groscurth arrhenius Institute for Energy and Climate Policy Parkstraße 1a, 2265 Hamburg, Germany
2 Contact Information Dr. Sven Bode Dr. Helmuth Groscurth arrhenius Institute for Energy and Climate Policy / arrhenius consult GmbH Parkstrasse 1a, 2265 Hamburg, Germany Internet: Fax: The information contained in this publication has been thoroughly researched by arrhenius and compiled to the best of its knowledge and belief. The information contained herein does not constitute a recommended form of action and should not be used as the basis for decisions and for the taking or non-taking of measures. The statements and conclusions contained in the publication are solely the opinion of the employees of arrhenius at the time of publication. Hamburg, April 21
3 The Impact of PV on the German Power Market 1 CONTENT Executive Summary PV in Germany Important market Policy discussion since Over-subsidisation... 5 Additional cost to consumers The impact of PV on liberalised power markets The functioning of liberalised power markets Total average costs of electricity production Static analysis of production quantity, electricity price, and revenues Dynamic analysis of production quantity, electricity price and revenues The impact of additional PV capacity on power prices Qualitative impact of new production capacities on wholesale power prices Qualitative impact on revenues of conventional plants Quantitative analysis of different scenarios for the PV development The electricity market model Results Excursus: Nuclear energy policy and its analogy to PV Implications for policy makers and stakeholders Letting the rapid build-up continue Slowing down the build-up of PV capacity Conclusions Appendices Abbreviations Assumptions on Model Data References... 3 Table of Tables Table of Figures... 32
5 The Impact of PV on the German Power Market 3 EXECUTIVE SUMMARY During the last months, the discussion on feed-in tariffs (FiT) for photovoltaic (PV) installations in Germany has gained new momentum. On the one hand, the issue of oversubsidisation due to the fact that module prices have been decreasing faster than feed-in tariffs was discussed. On the other hand, increasing costs to the consumers of power were put on the agenda after the unprecedented increase in new PV capacity in Germany in 29. After the general election in September 29, this discussion lead to different proposals for adjusting the FiT scheme. On March 23, 21 the parliamentary groups of the governing parties CDU/CSU and FDP presented a new bill. In April, the top lobbying association of the PV industry in Germany addressed Chancellor Merkel, all parliamentarians and others in full page advertisements in major newspapers to reconsider their plans. Both, in the discussion and in the draft bill, an important aspect has been neglected so far: the impact of the massively increasing PV capacities on the economics of conventional power plants. The regulatory impact assessment of the draft bill, for example, only considers costs for the public budget, for the business sector (device manufacturers and operators as well as industrial power consumers) and for the citizens (private households). Utilities and electricity companies are not mentioned. The present study fills this gap. In the first part, it is qualitatively shown how the power price and the equilibrium quantity on the power exchange change with increasing PV capacities. These findings can be directly translated into shrinking revenues for operators of conventional power plants. In the second part, a quantitative analysis of the German power market is provided. Based on a fundamental model analysing 8,76 hours per year with real plant data, the impact of six scenarios for the build-up of PV capacities, ranging from an immediate stop of new PV installations to an additional 5 GW of PV until 22, are studied. The effects of different PV scenarios on the wholesale power price and the total revenues (i.e., price multiplied by quantity) of all conventional power plants are calculated. For an incumbent operator of a coal-fired power plant, the contribution margin may decrease by more than 25% and for a new, yet to build gas-fired combined cycle power plant it may drop by more than 3%. One reason for this massive impact is the fact that PV installations produce power around noon when load and, thus, power prices as well as revenues are usually the highest in Germany. In this respect PV differs considerably from other renewable energies. The study does not make specific recommendations for policy makers, but advocates paying more attention to the so far neglected impact on the power market. It concludes that the PV support scheme can be understood as the accelerator pedal for the structural change in the German power sector. Implementing the changes in the feed-in tariffs as presented in the draft bill would require more and faster changes in the overall design of the power market to provide sufficient incentives for backup capacities when the sun is not shining. It would also be accompanied by additional acceleration costs. Absolute caps on the added capacity, rather than further cuts in the tariffs, could buy some time for a careful redesign of the market and may reduce resistance from incumbent operators. This is all the more true since PV build-up will not stop in 22, the year analysed in this study, but will rather continue and amplify the effects described above. That being said, we expect the discussion on the PV feed-in tariffs to be reopened again.
6 4 arrhenius Discussion Paper No. 3 1 PV IN GERMANY Germany is perceived as a frontrunner in power production from renewable energies (RE). The structure of the support scheme is considered one of most important elements in this success story. Under the feed-in tariff (FiT) scheme (Erneuerbare-Energien-Gesetz, EEG) producers receive a fixed remuneration for each kilowatt-hour fed into the grid. The level of support depends on, among other factors, the technology, the size, the site and the age of a specific installation. The FiT rewarded to new installations is reduced every year in order to acknowledge the continuous decrease in production costs. 1.1 Important market For a long time photovoltaics (PV) played a minor role with regard to power generation from renewable energies in Germany. However, the picture has changed significantly in recent years. For the first ten years (199-2) of the EEG (which was then called Stromeinspeisegesetz ), PV capacity was negligible. As can be seen in Figure 1, in 21 the share of PV capacity for the first time surpassed 1% of the total renewable energy capacity in Germany [BMU 21]. Since then, PV has seen an unprecedented growth both in absolute terms and as a share of the total capacity. In 29, PV capacity amounted to almost 9 gigawatt (9 GW = 9, MW) while total renewable energy capacity was 45 GW. Figure 1 shows the annual growth of PV in Germany over the last 2 years. In 29 alone, installations of new capacity added up to 3 GW, triggering investments of almost 1 billion euros. For the last three years, annual market growth has been over 15%. Altogether, Germany is one of the most important PV markets in the world, if not the most important. 1 9 Installed capacity (MW) PV share (%) 25% Capacity (GW) % 15% 1% 5% 1 % Share of PV of total installed RE capacity Figure 1: Development of PV Capacity in Germany [BMU 21].
7 The Impact of PV on the German Power Market Policy discussion since 29 Though the development was appreciated for different reasons such as environmental aspects, changing market structures (breaking the oligopoly), decentralised generation etc., recently the costs of this success have shifted into the focus of the political discussion. Two aspects need to be distinguished here: 1. over-subsidisation, 2. additional costs to the power consumers. Even though the first aspect is related to the second, it needs to be discussed separately. Over-subsidisation As early as 27, reports indicated that PV prices had started to drop faster than the feed-in tariff [RWI 27]. It was argued that operators of large solar fields and big retail companies were exploiting the situation by buying cheaper modules while selling the complete installation at more or less unchanged prices. Thus, they generated extra profits. This was possible, since consumers would base their investment decision on the unchanged FiT. In addition, it was claimed that, since Chinese modules had become the cheapest ones, German producers were no longer benefitting from the PV capacity build-up in Germany. Finally, since the FiT was once calculated to make PV installations possible in the areas of the lowest solar radiation and is not dependent on the geographical position, PV owners in Southern Germany, where the overall radiation is generally higher than in the rest of the country, were also accused of making unreasonable extra profits. Consequently, researchers and the Federal Consumer Protection Association argued for cuts in the FiT of 3% or more. 1 A recent report confirms these findings [IE & ZSW 21]. However, such cuts would mainly stop PV over-subsidisation and would, thus, have to be considered as a distributional issue. If prices really went down, growth could still continue although the more expensive (German) producers would most likely lose further market share. Additional cost to consumers Even if over-subsidisation was prevented by proper setting of the PV FiT, debate would continue on the question whether power production from PV should be supported to the current extent in the first place, since it is much more expensive than other options. This is an allocative question rather than a distributional one. The driving force behind this discussion is the fact that power consumers, who have to pay for the budget of the total FiT scheme, started to realise that their energy bills are increased due to the support of renewable energy and, more importantly, PV. Energy experts anticipated this development. The official Lead Study Renewable Energies, commissioned by the federal research ministry, for example, depicted the additional costs from PV in 27 [BMU 27, Figure 2]. What was not anticipated, however, were the dynamics of the PV market. The Lead Study 27, for example, foresaw a total PV capacity of 4.9 GW for the end of 21 a figure that was already 1 See for example: Solarsubventionen sprengen Prognosen (Solar subsidies exceed prognoses), in: Financial Times Deutschland, 24 August 29.
8 6 arrhenius Discussion Paper No. 3 surpassed by 28. Other studies from the same time also completely underestimated the development [EPIA 26]. 12 Price path C Additional costs (billion (22)/yr Total without PV Total Incl. PV Figure 2: Anticipated additional costs from PV in 27 [BMU 27]. The discussion on the PV FiT gained momentum in context of the 29 elections. Both the Christian Democrats (CDU/CSU) and the Liberals (FDP), who were expected to clearly win the elections, stated, that they wanted to adjust the PV FiT. In December 29, the new environmental minister Norbert Röttgen (CDU) also announced for first time the need for a new kind of mechanism. 2 The current status of the regulatory process is based on a proposal by the governing parties CDU/CSU and the Liberals that stipulates the following FiT for PV installations: 2 See Müller and Strathmann 29: Röttgen setzt bei Solarstrom den Rotstift an (Röttgen cuts support for solar electricity), in: Handelsblatt, 11 December 29.
9 The Impact of PV on the German Power Market 7 Table 1: Draft PV feed-in tariffs as currently discussed (as of March 23 21, Source: Bundestag 21). Performance class and feed-in tariff in euro-cent per kilowatt-hour Start of operation up to 3 kw up to 1 kw from 1 kw from 1 kw conversion sites other free sites from January 1 st from July 1 st from January 1 st 211 (degression 11% )* *) 11% degression is the sum of the general degression of 9% plus an extra degression as a function of performance class (here: 2%). The draft bill explicitly mentions a desired target for the annual increase of PV of about 3 GW. This will be supported by a corridor between 2.5 and 3.5 GW for which there is no additional cut (degression) in feed-in tariff if the new capacity in the previous year is within this corridor. If the new capacity is below 2.5 GW then scheduled cuts will be reduced by 2.5 percentage points for each 5 MW below the target. If, however, the new capacity exceeds 3.5 GW additional cuts will apply. For each 1, MW above the upper target the degression will increase by 2 percentage points in 211 and by 3 percentage points in 212. An upper threshold is set at 6.5 GW. Thus, for example, the maximum additional cuts will be 8% in 211 if PV capacity increases by 6.5 GW or more in Whether investments in new PV devices are economically attractive, thus, strongly depends on the cumulative new capacity in the previous year and the development of the module costs. Therefore, the exact new PV capacity for the years to come cannot be derived from the proposed regulation. In addition, it has to be mentioned that there is a loophole in the current proposal. If the power produced is consumed by the producer himself, different rules apply that are much more attractive. The threshold for self-supply is increased from 3 kw to 8 kw installations. Still, the final decision has not been made yet. The solar industry seems to have been successful in lobbying for a new discussion. Both timing and size of the cuts are under negotiation again. The issue now regularly enters even newspapers and TV-documentaries. The impact of additional costs arising from the FiT on poorer people like retired persons or single mothers and fathers is focused on by the news coverage. Interestingly enough, the discussion has so far neglected one important fact: The impact of PV on the power market. 3 The exact calculation depends on a reference period between June 1 and September 3.
10 8 arrhenius Discussion Paper No. 3 2 THE IMPACT OF PV ON LIBERALISED POWER MARKETS The liberalisation of energy markets in Europe was initiated at the end of the last century by the EU directive concerning the internal market in electricity. 4 There were many motivating factors; Paragraph 4 of the directive provides an overview: Whereas establishment of the internal market in electricity is particularly important in order to increase efficiency in the production, transmission and distribution of this product, while reinforcing security of supply and the competitiveness of the European economy and respecting environmental protection (...). As can be seen, various objectives were considered, that potentially contradict each other. At least with regard to efficiency, the Commission concludes that liberalisation has been successful: 5 By opening up these markets to international competition, consumers can now choose from a number of alternative service providers and products. Opening up these markets to competition has also allowed consumers to benefit from lower prices and new services which are usually more efficient and consumer-friendly than before. This helps to make our economy more competitive. The initial decrease in prices was mainly due to the fact that in the context of liberalisation the former regional monopolies were dismissed. As customers were now able to choose their supplier, the latter had to adopt their pricing strategy to the rules of competitive markets, i.e. most importantly to offer electricity at marginal costs of production. In part, however, the price decrease was triggered by the expansion of electricity production from renewable energies. This will be demonstrated in more detail below, after the principle functioning of the market has been explained. 2.1 The functioning of liberalised power markets Before discussing the effect of increasing PV capacities on prices and revenues, it is important to fully understand the functioning of liberalised power markets. Most importantly, the difference of total average costs (that also form the basis for FiTs) and marginal costs needs to be fully understood Total average costs of electricity production The total average electricity production costs of a power plant consist of a variable part, which is (typically) proportional to the quantity of electricity produced, and of a fixed part, which exists whether or not the plant is generating electricity. In order to simplify the analysis, it is assumed that there are only three cost factors for the production of electricity: 4 5 Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in electricity, OJ 1996 L 27. DG Com, Competition policy and the consumer, 24, available on the Internet at: ec.europa.eu/competition/publications/consumer_en.pdf (last accessed on 7 May 29).
11 The Impact of PV on the German Power Market 9 capital costs, fuel costs, and environmental costs in the form of CO 2 emission allowances. Capital costs are typically fixed costs whereas the other two categories represent variable costs. According to experience, other expenses such as fixed and variable operating and maintenance costs are small compared to the three aforementioned factors and are, thus, not considered for the basic analysis here (cf. Figure 3) Total average costs = Costs / quantity Marginal costs = additional costs for producing an additional unit / MWh(el) Hard coal PP Natural gas CCGT Wind farm Hard coal PP Natural gas CCGT Wind farm Production costs Variable costs Capital cost O & M costs (fix) O & M costs (var) Fuel costs CO2 cost Figure 3: Electricity production costs of various power plants (schematic representation). To be able to add the variable and fixed costs of the electricity production in euros per megawatt-hour ( /MWh), the fixed costs must be related to the amount of electricity generated. Therefore, the total investment sum for the power installation is distributed across the individual years of the targeted amortisation period using the annuity method. Dividing the so derived annual fixed costs of the investment by the corresponding electricity production, yields the specific capital costs of the power plant. They strongly depend on the amount of electricity that is produced. Fuel and CO 2 costs are, in contrast, variable and proportional to the amount of electricity produced. They depend on the fuel price, the efficiency of the power plant, the specific CO 2 emissions of the fuel, and the CO 2 price (see Figure 3).
12 1 arrhenius Discussion Paper No Static analysis of production quantity, electricity price, and revenues The revenue of a power plant is the product of the electricity quantity sold in one hour and the electricity price for this hour. As we will see, whether or not an individual power plant will be among those producing electricity depends on the market price. Consequently, not only the price, but also the quantity of electricity, which is produced and sold during its economic serviceable life, is important for the investment calculation. In the following, it is assumed that perfect competition prevails. This market form is also the objective of the European Commission in order... to make sure that companies compete with each other and, in order to sell their products, innovate and offer good prices to consumers. 6 According to cost theory, in such a competitive market producers offer goods at the marginal costs of production, that is, the costs that are incurred with the production of an additional unit of their product. Capital costs are no longer relevant in this case. For power plants, the marginal costs primarily result from the sum of the specific fuel costs and the specific CO 2 costs (see Figure 3). In order to describe the pricing on the power exchange, only the so-called spot market will be considered in the following. 7 This is the closest to the actual physical activity. The intersection of the aggregated supply with the total demand curve results in an equilibrium price for each hour of the day. The product of this price and the demand represents the revenues for the power plants in operation (see Figure 4). These revenues have to cover the marginal costs and in order to be economically viable in the long-term the capital costs. Only when the revenues exceed the sum of costs, can profits be earned. The aggregated supply curve, which consists of the individual supply curves of the specific power plants, is also referred to as merit-order curve in energy economics. Figure 4 shows the price finding mechanism for one individual hour. However, both, the merit-order as well as the demand curve undergo constant change on different time scales. Thus, calculations have to be carried out on an hourly basis rather than using annual averages for prices and quantities. The timing of the electricity production is important as electricity can only be stored on a small scale at high costs and must, thus, in general be utilised immediately. 6 7 Jonathan Todd, Commission competition spokesperson; transcript from an interview on BBC World, September 27, Source: ec.europa.eu/competition/consumers/index_en.html. More information on EU competition policy is also available on this site. In addition to the spot market, there is also the forward market, at which standardised products are traded, i.e. a defined amount of power over a fixed time period (year, quarter, month). However, prices at these markets are always based on expectations of future spot market prices.
13 The Impact of PV on the German Power Market 11 Costs / Price (Euro / MWh) Demand Supply = based on marginal costs of production Equilibrium * price p Nuclear Lignite Coal Gas Oil renewable energies Equilibrium quantity Energy (MWh) Figure 4: Pricing on the electricity exchange in one hour. In such a market setting, it is difficult to create incentives for investments in new power plants since the relatively high capital costs are difficult to recover with revenues based on marginal costs of production plus technical limitations for new entrants to reduce their marginal costs [for more detail see Bode & Groscurth 29a+b]. Attention was called to this problem several years ago [Weber 22, BCG 23]. Up until now, the issue has not entered the public energy policy debate in a meaningful way. Nevertheless, it is of utmost relevance for the future electricity supply and it is significantly exacerbated by the rapid build-up of PV capacity Dynamic analysis of production quantity, electricity price and revenues The analysis in the previous section was static in the sense that it showed an individual hour with a fixed demand and a given mix of available power plants. Obviously, both these characteristics fluctuate on different time scales. Electricity demand is varying both over the day and over the year. Demand is generally lowest in the night and has typically two peaks during daytime, one at noon and another one in the late afternoon. In Germany, demand tends to be higher in winter and lower in summer. Consequently, prices on the power exchange are constantly moving up and down over the day and over the year. This mechanism is shown in the form of monthly averages for a 24-hour period in Figure 5. If the load is low, the demand curve intersects the supply curve more to the left hand side, and the respective equilibrium price is rather low. As load increases (over the day) the point of intersection moves to the right. As a consequence, the price increases. It is important to remember at this point, that for each hour there is only one market price for all plants. This single price for an hour equals the revenue per kilowatt-
14 12 arrhenius Discussion Paper No. 3 hour for each plant producing. Thus, the revenue changes in line with the load. The difference between the equilibrium price and the marginal cost of production equals the contribution margin of an individual power plant for that hour. If load and prices change over the day the contribution margin must change over the day, too (see Figure 6). The total contribution margin for a year has to be calculated based on the 8,76 individual margins for each hour of a year. Multiplying the average annual wholesale power price by the amount of electricity produced over the year may be grossly misleading. Costs, WTP, price (Euro / MWh) Demand (e.g. in the night) Demand (peak load) Nuclear en. Lignite Hard coal Gas Oil Energy (MWh) Renewable energies Figure 5: Load curves and derived power prices at different hours of a day (schematic representation). Costs, WTP, price (Euro / MWh) Demand (in the night) Demand (peak load) Profit margin at day time Profit margin at night time Nuclear en. Lignite Hard coal Gas Oil Energy (MWh) Renewable energies Figure 6: Contribution margin at different hours of the day.
15 The Impact of PV on the German Power Market 13 While Figure 6 showed the formation of prices over a single day, the relative distribution of load over the year is presented in Figure 7. As discussed earlier, prices are generally high when the load is high (red cells) and are low when the load is low (green cells). The red oval schematically shows where PV is producing (see also Figure 8). Hour of a day Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec PV produces here Figure 7: Average daily load curves for different month (load in MW) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 8: Power production from PV over the day and over the year (green = minimum (zero); red = maximum (depending on installed capacity), based on average figures.
16 14 arrhenius Discussion Paper No The impact of additional PV capacity on power prices After discussing the formation of the equilibrium price on a power exchange and the resulting contribution margin, the following section describes the effect of a changing supply curve, namely the introduction of new capacities Qualitative impact of new production capacities on wholesale power prices If additional electricity from renewable energies enters the market, for example, due to investment triggered by a FiT, the supply curve in Figure 9 is shifted to the right. This is especially true for PV and wind energy, which play the most important role among all renewable energies, at least in Germany. Since their marginal costs of production are almost zero, they align at the left end of the merit-order curve. Costs / Price (Euro / MWh) Demand Supply (reference) Supply (additional RE) * p * p RE Wholesale price decreases nuclear lignite Coal Gas Oil additional renewable energies Equilibrium Energy (MWh) Figure 9: Effect of additional RE capacities on equilibrium prices. As a consequence, the equilibrium price decreases. This was first described by Bode & Groscurth in 26. In the following, this so-called merit-order effect has been repeatedly cited and analysed, because a decrease in wholesale power prices may lead to a reduction of consumers energy bills. Until that point, it had been argued that the support of renewable energies through a FiT scheme always leads to higher costs for the consumers as, at the end of the day, the additional costs of production from renewable energy installations need to be financed. To determine, which of the two effects predominates, one has to compare the renewable energy mark-up paid by the consumers with the reduced wholesale power price. For the past, it has been shown that the overall price effect may indeed be negative [Bode &
17 The Impact of PV on the German Power Market 15 Groscurth 26, Sensfuß et al. 28, de Meira et al. 28 for Spain]. However, at least for Germany, one has to acknowledge that there are so many different rules and exemptions governing the mark-up (e.g. hardship clauses), that a general assessment is difficult. It is important to note, that the effect on the wholesale price is not technology specific whereas the additional costs from the support scheme do depend on the technology (see Figure 1). In other words, the merit-order effect can be diluted or strengthened by the choice of technology. Costs/ price p * p RE PV additional RE mark-up to be paid by power consumers Wind Demand Supply (reference) Supply (additional RE) Total average cost lignite Coal Gas Oil additional renewable energies Equilibrium Energy (MWh) Figure 1: Power prices and RE mark-up under German FiT Qualitative impact on revenues of conventional plants As shown in Sec. 2.1, power prices change over the day and so does the production from PV devices. On average, their production peaks around noon and is inevitably zero during the night. Given that production from PV peaks at noon, the reduction of wholesale price will be the largest at noon, too. As has also been shown above, contribution margins are highest at noon, both in relative terms (i.e. in /kwh) and in absolute terms (i.e. in ( /kwh)*kwh = ). The effect is shown as price difference Delta 1 in Figure 11. Due to the price reduction caused by PV at noon, market turnover is reduced significantly. Consequently, the revenues of conventional plants are diminished significantly by the simultaneous reduction of market price and remaining demand around noon. The price effect is smaller during the night time (cf. price difference Delta 2 in Figure 11). Consequently, market turnover and profitability of conventional plants are likely to be less affected by wind turbines compared to PV devices as the former have a more constant diurnal production profile.
18 16 arrhenius Discussion Paper No. 3 Costs / WTP / Price (Euro / MWh) Demand (night) Demand (day time) Supply * p * p with _ RE Delta 1 (in revenues) * p * p with _ RE Delta 2 (in revenues) Energy (MWh) additional renewable energies Figure 11: Changes of prices (and contribution margin) at different hours of a day. 2.3 Quantitative analysis of different scenarios for the PV development In this section, we provide a quantitative analysis of the German power market with respect to different paths for the PV capacity build-up The electricity market model The analysis is carried out using a fundamental electricity market model that calculates equilibrium quantity and price for each of the 8,76 hours of a year. The target year is 22. For the sake of simplicity, the total electricity demand is assumed to be constant at 565 TWh per year as one may find arguments for both a decrease in total consumption caused, e.g. by improved energy efficiency, or an increase triggered, e.g. by e-mobility. The shape of the load curves is assumed to be the same as in 26. Potential effects from smart metering etc. will probably still be small in 22 and are, thus, not considered. On the supply side, all major power plants in Germany are taken into account. The life time for existing plants is set according to DENA 21. Information on other parameters such as fuel prices is provided in the annex. Nuclear phase out in Germany is, for the moment, considered as foreseen by the existing law. Thus, by 22, almost all nuclear plants will have gone off-line. New capacity
19 The Impact of PV on the German Power Market 17 for lignite and coal fired power plants is limited to those plants whose construction has already begun [see BUND 21]. Planned plants are disregarded as many projects have lately been given up. In order to allow for a secure supply at any time, additional new capacities of gas turbines and gas-fired combined cycle power plants are foreseen. (In anticipation of the results, it remains to be seen if any private investor will be willing to build such new capacity). These capacities are constant and not dependent on the PV capacities: Residual load needs to be satisfied in all hours, i.e. also when PV is not producing as, for example, at night or in the winter time. Non-PV renewable capacities are set as in the BMU Lead Study [BMU 29]. The following scenarios for PV capacities in 22 are considered: Table 2: Status and scenarios of possible developments of the PV capacity in Germany. PV capacity as of Jan 1st 21 (GW) Additional capacity by Jan. 1st 22 compared to Jan. 1st 21 (GW) Total PV capacity as of Jan. 1st 22 (GW) Rationale for the scenario 9. Emergency braking Spanish case (.5 GW per year) 14.3 *) 23.2 BMU Lead Study 29 ~ 9. ***) BEE Road Map **) 42. PV Bill (draft) March 23, Business-as-usual (BAU): costs reduction for PV faster than FiT adjustment *) Figure provided for December 31, 22 **) Figure presumable provided for December 31, 22 (11 yrs à 3 GW) ***) Source: BMU 21 As an extreme scenario, the immediate stop of all PV support is considered ( Emergency breaking ). This is more done to support estimating the size of the quantitative effects rather than being a realistic policy perspective. The second scenario is a cap on the added PV capacity of.5 GW per year as is already in place in Spain. Third, there is the path foreseen by the BMU Lead Study [BMU 29]. Fourth, the more ambitious road map outlined by the renewable industry association BEE is taken into account [BEE 21]. The current draft of the new FiT scheme for PV would allow for an even higher PV capacity in 22 and at the same time gives an estimate of what is to be expected if the FiT remains unchanged ( BAU ).
20 18 arrhenius Discussion Paper No Results The impact of the different PV capacities on the power market can be described in two steps. First, the change of the residual load that needs to be met by conventional sources can be determined. This gives a general idea of the effect from increasing PV capacities without making any assumptions on fossil fuel price etc. This is exemplarily shown for an installed PV capacity of 42 GW in Figure 12. Comparing this with Figure 7 one can clearly see how the red load peaks around noon time vanish. In summer time, the residual load at noon may even drop below the load at midnight. Hour of a day Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Figure 12: Change of residual load for a total PV capacity of 42 GW over the day and over the year. Second, the residual load can be transferred into power prices. Based on the market model and the assumptions described above, we get the following results: Figure 13 shows the average annual wholesale price for the different scenarios. Due to the assumed increase in fossil fuel prices, the absolute level increases for all scenarios in 22 compared to 21. Within the scenarios for 22, however, one can see the expected reduction of the power price as a function of PV capacity.
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