Harmonisation of generator tariffs in the Nordics and the EU

Public ISBN nr. 978-82-93150-69-5 Harmonisation of generator tariffs in the Nordics and the EU Commissioned by Fortum, Skellefteå Kraft, Statkraft and Vattenfall January 2015 THEMA Report 2014-43

About the project About the report Project number: SVE-14-01 Report name: Harmonisation of generator tariffs in the Nordics and the EU Project name: Client: Tariffharmonisering i Norden og Europa Fortum Skellefteå Kraft Statkraft Vattenfall Report number: 2014-43 ISBN-number: 978-82-93150-69-5 Project leader: Åsmund Jenssen Availability: Public Project participants: Kaja Fredriksen Roger Grøndahl Berit Tennbakk Completed: 27 January 2015 About Øvre Vollgate 6 0158 Oslo, Norway Company no: NO 895 144 932 is a Norwegian consulting firm focused on Nordic and European energy issues, and specializing in market analysis, market design and business strategy. Standard disclaimer: AS (THEMA) does not accept any responsibility for any omission or misstatement in this Report. The findings, analysis, and recommendations are based on publicly available information and commercial reports. Certain statements may be statements of future expectations that are based on THEMAs current view, modelling and assumptions and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in such statements. THEMA expressly disclaims any liability whatsoever to any third party. Page ii

CONTENT 1 INTRODUCTION... 5 1.1 Background... 5 1.2 Aim of the study... 5 2 EFFICIENT TRANSMISSION TARIFFS... 7 2.1 Conditions for efficiency... 7 2.2 Optimal cost allocation between generators and consumers... 8 2.3 Energy versus capacity-based G charges... 8 2.4 Attributes of an efficient tariff structure... 9 3 TARIFF STRUCTURE: TODAY S STATE OF PLAY... 10 3.1 Tariffs in Sweden compared to other countries... 10 3.1.1 The tariff structure in Sweden... 10 3.1.2 The Swedish G component in a comparative perspective... 10 3.2 Theoretical assessment of Swedish G component... 14 3.3 Case illustrations... 15 3.3.1 Investment in a new wind power plant... 15 3.3.2 Capacity increase in hydropower plant and pumped storage... 16 3.3.3 Choice of subscribed capacity in existing power plant... 16 4 CONSEQUENCES OF TARIFF HARMONISATION... 18 4.1 Future tariff scenarios... 18 4.1.1 Today s situation continues... 18 4.1.2 Substantially higher Swedish G component than in other countries... 18 4.1.3 Lower Swedish G component in line with European average... 20 4.2 Implications for the competitiveness of Swedish generation... 20 4.2.1 Long-run marginal cost... 20 4.2.2 Prices and trade 2025... 21 4.3 Case illustrations 2025... 23 5 LONG-RUN IMPACT OF SWEDISH GENERATOR TARIFFS... 24 5.1 Energy and capacity balance... 24 5.2 Climate and renewables targets... 24 5.3 Implications for Swedish generator tariff regulation... 25 REFERENCES... 26 APPENDIX 1: DESCRIPTION OF THEMA S POWER MARKET MODEL... 27

SUMMARY AND CONCLUSIONS Background An efficient tariff structure is a prerequisite in order to achieve optimal use and investment in the power grid. This applies to both tariffs that are intended to give price signals and tariffs that are designed to ensure cost recovery for network companies. The latter type of charge for generators is commonly referred to as the G component. Currently, EU regulations limit the size of the G component (Regulation 838/2010). However, important differences in the regulation of grid tariffs remain both in Europe and among the Nordic countries. Further harmonisation of grid tariffs is currently discussed in Europe, particularly with respect to the level of the G component. The actual design of such a harmonised tariff structure is yet unclear. A more harmonised regulation, if adopted by the Swedish authorities, could bring about substantial changes in the Swedish tariff structure and levels, particularly with regard to the G component. The level of the G component ( effektavgiften ) is currently set at a higher level than in most other European countries. A core question that the Swedish regulatory authorities will then face is: What are the economic consequences of more harmonised generator tariffs (G component) between Sweden/the Nordic countries and the rest of Europe, and what are the consequences of potentially increased differences? In order to answer this, one must both examine what is an optimal tariff structure and the consequences for a country of practising a different tariff structure. Tariffs should be based on economic efficiency criteria The electricity grid constitutes a natural monopoly. This has implications for how efficient tariffs are designed. From economic theory, network tariffs should reflect short-run marginal costs/losses to the extent possible. Such tariffs send the correct price signals and minimise the need for cost recovery. In addition, efficient long-run signals can be sent through customer-specific connection charges. Cost recovery should be ensured through residual tariffs, which should be as neutral as possible with regard to short-run trade and long-run investments. In a closed economy with homogenous agents, it does not matter for the economic outcome where the initial tariff burden is placed. When the domestic market is not homogeneous (agents have different price sensitivities), or in an open economy, residual tariffs should be placed on the agents with the lowest price sensitivity. In an integrated international electricity market, generators are subject to competition across borders. A lack of harmonisation may lead to distortions with regard to both trade and investments, depending on the tariff design. For commercial agents such as generators it is also important that tariffs are set in a manner which is as predictable and transparent as possible, in order to limit any perception of regulatory risk. With regard to the G component, energy tariffs based on historical generation (lump-sum tariffs) are in any case preferable over capacity-based tariffs, particularly in power systems that relies heavily on renewable energy sources. The current Swedish tariff system for generators is not efficient The current Swedish tariff system has several weaknesses from a theoretical and empirical perspective, particularly in the long run. Concentrating on the G component, we find that the fact that tariffs are capacity-based creates distortions between generation technologies and runs the risk of reducing the investment incentives for renewable energy. The fact that the capacity-based tariff is based on subscribed capacity with penalties if the generator injects more into the grid, creates incentives to underutilise generation capacity and possibly also to shortages in the grid in peak load hours. Finally, economically efficient investments in pumped storage and hydropower upgrades may become unprofitable. Page 2

Differences in tariffs between geographical areas could become distortive if the levels differ greatly. In Sweden, the geographical differences in tariffs between the north and south of the country adds to existing differences stemming from different pricing areas and the loss-based energy charge. The disincentive effect of current Swedish generator tariffs is increased if generators decide to connect to the regional grid (mainly the case of smaller power utilities and especially for wind energy) since the charge for this connection would then come in addition. A lack of harmonisation can have significant economic costs We have looked at three possible ways forward for the Swedish G component. Currently, in Sweden the average G component is 0.64 euro per MWh (around 0.58 øre/kwh). Price forecasts in 2025 taking into account the expansion plans abroad publish by the Swedish TSO show a much stronger correlation between Sweden and Norway and Sweden and Finland, than with other European countries. Going forward it is therefore particularly important for the Swedish regulator to monitor the level of the G component in Norway and Finland, although the competition with Continental Europe and the Baltic states is increasingly important. In a first scenario, today s situation remains unchanged. This maintains the weaknesses in the current system with regard to investments. In a second scenario, the Swedish G component diverges further from the European average. Given the Swedish TSO s plans for grid expansion, and thus a need for higher income, even an unchanged distribution between consumers and generators will translate into higher generator charges in the future. In our calculations, we have assumed that the real 2025 capacity charge base is twice the 2015 level. To this, we have added the assumption that the G component increases to 50 per cent from today s level of 30 per cent. The effective tariff cost may increase to more than 5 øre/kwh in Northern Sweden for a wind power plant. We also find that this increases the long run marginal cost for a typical wind power plant increases by 1.3 øre/kwh with a 0.5 per cent increase in the real before-tax cost of capital. The adverse effects on investment are likely to be more significant, and capacity subscriptions may also be affected to a larger degree. In a third scenario, we look at the consequences of increased harmonisation with the rest of Europe. This time, the effect on the long run supply curve of electricity generation in Sweden is likely to be positive, particularly if one moves to a uniform lump-sum energy charge instead of a capacity charge. An inefficient tariff system has wider repercussions The current Swedish G component model has long run implications beyond the consequences outlined above. First, less predictable and more unstable generation due to a higher share of renewables leads to a higher need for flexible generation and demand in order to balance the system. In addition, a higher degree of interconnection with power systems and increasing price volatility leads to more changes in the power flows and an increased need for capacity to balance the Swedish system. On this background, it is inefficient to maintain a tariff system that puts an excess burden on generation in general and on capacity with a low load factor and/or high regulating ability in particular. Increasing the burden on generation and/or capacity exacerbates the weaknesses of the current Swedish tariff system, and leads to higher overall system costs as more expensive capacity options must be taken into use. Capacity in existing power plants are especially important, as this capacity is practically free once it has been built (sunk cost). It is also clear that the cost of building renewable energy is low in Sweden compared to most other countries. By providing disincentives for investments in Sweden Sweden, a higher generator tariff in Sweden will lead to a less cost-efficient expansion of renewable energy in Europe and a costlier climate policy. Page 3

The Swedish tariff system can be improved We conclude with the following recommendations for the future G component in Sweden, which would contribute towards increased economic efficiency: Consider making generator tariffs uniform regardless of grid and handle the necessary price signals through connection charges, area prices and energy charges based on marginal losses. In this regard, it is also important to ensure that the energy charges are calculated in an efficient manner. We have not considered this issue here. Consider moving from a capacity-based generator charge to a lump-sum energy charge, for instance based on historical generation. Regardless of the tariff model, avoid geographical price signals in the G component. Monitor tariff levels in neighbouring countries, particularly Norway, and avoid increasing generator tariffs above the levels of the most important trade partners. Page 4

1 INTRODUCTION 1.1 Background Today, power generators in Sweden are subject to a capacity charge ( effektavgiften ) when injecting electricity into the grid. The capacity charge is similar to what is often termed the G component, i.e., a tariff designed to contribute to cost recovery for the grid gomponent. Depending on the design the G component may affect the power supply curve (also referred to as the merit order curve), both in the short run and in the long run. In addition to the G component, generators pay an energy charge based on the cost of losses. While EU regulations limit the size of the G component (Regulation 838/2010), important differences in the regulation of grid tariffs remain both in Europe and among the Nordic countries. Further harmonisation of grid tariffs is currently discussed in Europe, particularly with respect to the level of the G component. The actual design of such a harmonised tariff structure is yet unclear. A more harmonised regulation, if adopted by the Swedish authorities, could bring about substantial changes in the Swedish tariff structure and levels, particularly with regard to the G component. The level of the G component is currently set at a higher level than in most other European countries. Hence, the key question which we analyse in this report is: What are the economic consequences of more harmonised generator tariffs (G component) between Sweden/the Nordic countries and the rest of Europe, and what are the consequences of potentially increased differences? In order to answer this, one must both examine what is an optimal tariff structure and the consequences for a country of practising a different tariff structure. While we make a clear distinction between these two questions, the regulator must obviously see them in conjunction. Optimal tariff structure is a goal in itself, while a harmonised tariff structure is not. Harmonisation of regulation can have large benefits, but there is also a trade of between harmonising and optimising with regard to efficiency in one country. Also, there is the question of how to harmonise if neighbouring markets have different tariffs (i.e. which market should one harmonise towards). The value of harmonisation depends on whether the markets in question are truly integrated, and whether the harmonisation moves the tariff closer to an optimal level and structure. 1.2 Aim of the study In this report we analyse the consequences of harmonising versus not harmonising Swedish grid tariff structure with other Nordic and European countries. We focus particularly on the level of the G- component, but we also discuss other elements of the tariff structure in order to retain a holistic approach to grid tariffs, which is also the approach the regulator must have. In chapter 2, we discuss the criteria for optimal transmission tariffs, particularly given the grid s special feature as a natural monopoly, and define the attributes of an optimal grid tariff structure. In chapter 3, we look at current generator tariffs in Sweden compared to the regulation in other countries, notably Norway, and pinpoint sources of potential inefficiencies. We also illustrate the link between the level of tariffs and the actual decisions made by power generators. Important questions that we seek to shed light on are: The difference between tariffs that mainly send price signals and tariffs that mainly contribute to cost recovery. Optimal allocation of grid tariffs between power consumers and power generators. Capacity-based versus energy-based tariffs. Secondly, we address the question of harmonisation of tariff structure. In chapter 4, we look at three different cases. Each case illustrates a potential way forward for Swedish generator tariffs in light of the ongoing discussions at the European level. We use the THEMA power market model to simulate the effects until 2025 of different levels of the G component in Sweden. Our analysis includes both Page 5

short-term and long-term economic efficiency of the power market. By short-term economic efficiency, we mean cost-efficient operational decisions and by long-term efficiency we mean costefficient investments. In the context of investment decisions, we also touch on the topic of regulatory risk. Chapter 5 opens up the discussion and looks at the long-run consequences, including how tariff harmonisation fits into the European climate policy agenda. Page 6

2 EFFICIENT TRANSMISSION TARIFFS In this part of the report we discuss optimal tariff structure in the central grid from the generator s perspective. Tariffs for transmission and distribution of electricity play an important role as price signal for both consumers and generators. The tariff structure influences both decisions to invest in power generation and the electricity quantity demanded. The tariff structure also has distributional effects between different groups. We first discuss the conditions for optimal pricing in a natural monopoly. We then address the specific question of who should bear the residual tariff and whether it should be energy- or capacity-based. We end the first part of the report by defining what we consider to be ideal features of a grid tariff structure. 2.1 Conditions for efficiency Network tariffs should be designed with the concept of economic efficiency in mind. Economic efficiency, or optimal resource allocation, embodies both optimal utilisation of the grid and optimal investments in the grid, power generastion, power consumption, and use of alternatives to electricity. Under given conditions, which economists refer to as absence of market failure, prices that are equal to short-term marginal costs are a perfect signal of resource scarcity. However, the electricity grid is what economists refer to as a natural monopoly. A natural monopoly is a market where the cost structure is such that it is most efficient to have only one generator. In a natural monopoly, fixed costs constitute a very large share of the total costs, which means that the cost of producing one additional unit is very small once a generation infrastructure has been build. The fact that a market is a natural monopoly has a number of implications, among which are: The regulator must intervene to prevent the monopolist from exploiting his advantage over consumers. The solution is sometimes, but not necessarily, public ownership. At least some regulation of the monopolist s income and market prices is necessary. Prices equal to short-term marginal costs will not cover all generation costs. The third implication for the level of prices is the starting point for the analysis in this report. Grid tariffs that equal the short-term marginal cost will create insufficient income for network companies in the longer run. This is because the optimality condition of price equal to short-term marginal cost refers only to variable costs and, being natural monopoly, the grid is characterised by high fixed (sunk) cost 1 and low variable costs. Thus, tariffs must also include a cost recovery element, hereby referred to as a residual element. In the following discussion, we assume that the appropriate short- and long-run price signals are given through tariffs that reflect marginal losses in the grid, congestion (for instance through area prices) and connection charges based on the individual cost of connecting new generation to the grid. Thus, we discuss residual tariffs from the perspective that they should be as neutral as possible. The size of this residual element depends on the total cost of the grid as well as the income from tariffs that give optimal short- and long-term price signals, i.e. tariffs that equal marginal cost. The income from the tariff element equal to the marginal cost depends again on the capacity situation and the losses in the grid and can therefore vary significantly from year to year. There are several pricing methods to recover the residual element. It can be done through 1) fiscal revenues, 2) a two-part tariff where a fixed component and an energy/effect component are weighted in some way or 3) so-called Ramsey pricing. A discussion of the optimality of the various ways of designing residual tariffs is outside the scope of this report. We would however like to point out that using fiscal revenues in the case of the grid is however unrealistic since grid infrastructure is 1 Fixed costs (including operating costs which are fixed in the short to medium term) may constitute as much as 85-90 per cent of total costs in the short run according to Econ Pöyry (2008). Page 7

commonly financed by users and not by general tax revenues. Regardless of which option the regulator of the power system chooses, he or she must decide on two crucial parameters, both of which are central to the discussions in the following chapters of the report: How to divide the residual element between generators and consumers? How to weigh between energy and capacity pricing? 2.2 Optimal cost allocation between generators and consumers Given that price signals primarily pass through other tariffs (tariffs based on marginal losses, area pricing and connection fees), residual tariffs should be designed to have as little impact as possible on grid users incentives, both in the short- and long-term. A tariff that does not affect agents behaviour is said to be neutral. Economic theory gives some insights into how to design neutral taxes and tariffs. In an economy that is both homogeneous (i.e., all consumers are the same and all generators are the same) and closed (i.e. no interaction with the rest of the world), tariff structure in the regulation does not matter. The tariff cost is then passed through to consumers either through a shift in the demand curve (with a consumer tariff) or the supply curve (with a generator tariff). Regardless of the initial conditions, the economic outcome of introducing a tax or tariff will be the same. However, the Swedish electricity market is neither fully homogeneous nor fully closed which means that the tariff structure will have consequences for efficiency. In such a case, it is efficient to place the burden on the least price sensitive consumers and generators, or what is commonly referred to as immobile tax bases. The least price sensitive agents are typically households and other small end-users in the distribution grid according to previous studies. 2 Power-intensive industries and generators are at the other end due to the exposure to international competidion. Taxing immobile tax bases avoids an additional deadweight loss from reduced investments in national power generation (as generators may relocate abroad), as well as a reduction in the national power intensive industry (which may be outcompeted or also move abroad). One could argue that for an integrated market as a whole, there would be no additional deadweight loss since one country s loss in another country s gain. However, by having non-harmonised tariff structures, one still runs the risk of creating inefficiencies by distorting investment decisions. Harmonisation of tariff structures between countries will bring the open economy case similar to that of the closed economy case, but is not an end by itself. The tariff structure one chooses to harmonise for all should also be optimal (see 2.4), and the benefit from harmonisation is greater the more integrated national markets are. 2.3 Energy versus capacity-based G charges Where generators contribute to cost recovery through a positive G component, two calculation methods are available in practice: Energy-based and capacity-based generator charges. Energy-based generator charges mean that the generator pays a cost according to the total volume of electricity that is injected into the grid. The two main problems with energy pricing are that it affects both the short-term marginal cost curve, and therefore trade, as well as the long run merit order curve. If the regulator uses historical data to calculate the energy volume injected into the grid, the adverse effect is smaller. On a positive note, energy pricing does not entail significant distortions between generation technologies, as the tax per kwh is the same. However, it is important to distinguish between continuous energy pricing of each unit produced and a lump-sum energy tariff based on some parameter such as generation volumes in the past. A lump-sum energy tariff could for instance be based on average historical generation (see ACER, 2014). The latter is more efficient as the impact on short-run marginal cost is smaller and can even be eradicated if the basis for the tariff is completely independent of actual generation. 2 See for instance Econ Pöyry (2008) and the references therein. Page 8

Capacity-based generator charges can be designed in several ways. For instance, the generator may pay a tariff based on the maximum amount of electricity injected into the grid at any point in time. This will affect the marginal cost of generating in peak load. Other capacity-based charges have no impact on the short run marginal cost curve, such as a subscribed capacity or maximum capacity in reference hours that cannot be predicted by the generator. However, similar to energybased lump-sum charges, capacity-based charges can have an adverse effect on the long run merit curve due to the increase in long run marginal cost from the tariff. Additionally, investment incentives are distorted between technologies as the effective charge per kwh is greater the lower the load factor. This favours baseload/thermal generation with a high load factor and creates a disadvantage for wind power and hydropower. If the tariff impact cannot be recovered through higher market prices, the result may be underinvestment in renewable wind power and hydropower (and technologies with similar characteristics), compared to the economically efficient level. Overall system costs will in addition then be too high. It should be noted that the Norwegian G component was changed from a capacity-based to a lumpsum energy-based tariff in 2001, due to the negative effect on capacity investments (Statnett, 2002). 2.4 Attributes of an efficient tariff structure Based on the discussion above, we see the following list as desired attributes of grid tariffs: Tariffs should reflect short-run marginal costs/losses to the extent possible. Such tariffs send the correct price signal and minimise the need for cost recovery. With regard to cost recovery paid by generators, energy tariffs based on historical generation (lump-sum tariffs) are preferable over capacity-based tariffs, particularly in power systems that relies heavily on renewable energy sources, which is likely where we are heading in the future. In a closed economy with homogenous agents, it does not matter for the economic outcome where the initial tariff burden is placed. When the domestic market is not homogeneous (agents have different price sensitivities), or in an open economy, residual tariffs should be placed on the agents with the lowest price sensitivity. Determining which agents is the least price sensitive is an empirical question not addressed in this report. Previous studies conclude that households and other small consumers in the distribution grid are typically least price sensitive customers in the grid. Finally, for commercial agents such as generators it is important that tariffs are set in a manner which is as predictable and transparent as possible, in order to limit any perception of regulatory risk. Page 9

3 TARIFF STRUCTURE: TODAY S STATE OF PLAY In this part of the report, we assess today s tariff structure in Sweden. We conclude that there are several sources of inefficiencies in the regulation of tariffs today, of which a high G component by international standards is important one. The capacity-based charge with geographical differentiation is another important factor that causes inefficiencies. The result may be underinvestment in capacity in Sweden and distorted investment incentives between generation technologies. 3.1 Tariffs in Sweden compared to other countries Here, we map out the current grid tariff structure in Sweden. We specifically address the question of the generator tariff in Sweden in comparison with other countries as this will serve as a starting point for our case illustrations in part 3.3. 3.1.1 The tariff structure in Sweden Generators in Sweden pay an energy charge per kwh injected into the grid and a capacity charge. Both the capacity charge and the energy charge are calculated at each point of connection. The capacity charge is based on subscribed capacity with a penalty charge if the subscribed amount is exceede. The energy charge is based on the price of losses purchased (per price area), a loss coefficient and a correction coefficient. The residual cost of the grid comes in addition to these charges and is in Sweden divided between generators and consumers using a 30-70 guideline. More precisely, 68 per cent of the residual cost of the grid is paid by the consumers and the remaining 32 percent by the generators. These 32 per cent constitute the G component and has increased since 2012. The average G component is today 0.64 euro per MWh according to ACER statistics or around 0.58 øre/kwh (volume-weighted average). In addition comes a tariff for connections to the regional grid, at least in some grid areas (Sweco, 2012). Plants with less than 100 MW installed capacity are normally connected to the regional grid. A special feature of the Swedish tariff structure is that the G component has been set deliberately different in the northern parts and southern parts of the country, with a lower level in the southern parts. The regulator s aim with this practice has been to stimulate generation investments in the south of Sweden. Finally, Sweden is divided into 4 price areas since 2012, which means that generators receive a different wholesale electricity price if there is congestion in the transmission grid (high price in a deficit area with lower generation than consumption, lower prices in surplus areas). This will tend to yield higher prices in the south of Sweden, although the impact has been limited thus far. 3.1.2 The Swedish G component in a comparative perspective Swedish generator tariffs are higher than in most other countries, see the table below. In fact, in many countries the generators pay no G component tariffs at all. Page 10

Table 3.1 Generator tariffs in selected countries. SEK Country G component Comment Sweden 22-51 øre/kw Varies between price areas Denmark Finland 0.4 øre/kwh 0.8 øre/kwh DKK 0.3øre/kWh. Windpower and local CHP subject to purchase obligation are exempt. 0.9 EUR/MWh (2015, up from 0.7 in 2013 and 0.85 in 2014) Norway 1.0 øre/kwh Additional system tariff of NOK 0.2 øre/kwh and energy charges based on marginal losses and area price Germany 0 Poland 0 Estonia 0 Latvia 0 Lithuania 0 Source: TSO websites, ENTSO-E. However, the difference in G component is only interesting insofar as the Swedish power market is integrated with these other countries. If that is the case, a higher level of generator tariffs can have adverse effects for Sweden. This is why we need to supplement the observations on tariff levels with data showing the international integration of the Swedish power market. For this, it is relevant to look at both the transmission patterns and the similarity of price levels. The figure below shows the transmission capacity in the Nordic power market. The Nordic transmission grid is part of the transmission network in northwestern Europe and it ties practically the whole Nordic region into one synchronous power system. Interconnectors also link the Nordic market to Germany, Poland, Estonia and Russia and the Netherlands. Eastern Denmark is synchronous with the Nordic grid while western Denmark is synchronous with the continental Europe. Sweden is well connected to its Nordic neighbours. In total Sweden have almost 4000 MW of transmission capacity towards Norway, followed by 2700 MW towards Finland and 2000 MW towards Denmark. Page 11

Figure 3.1 Transmission capacity in the Nordic power market Source: Entso-E/Nord Pool Spot. The connections towards Germany and Poland are somewhat smaller, see the table below, but they may be increased in the future. According to the Swedish TSO Svenska Kraftnät s long-term development plan «Perspektivplan 2025», two new interconnectors are being planned. The NorBalt cable towards Lithuania will come online in 2015/2016 with a capacity of 700 MW. There are also plans to build a second cable to Germany, but this is still in the early planning phase. According to Svenska Kraftnät, a cable to Germany can come online sometime between 2018 and 2025. The connection towards Denmark will also be expanded without adding new capacity. Table 3.2 Transmission capacity between Sweden and other countries From Sweden (MW) To Sweden (MW) Norway 3995 3695 Denmark 1980 2440 Finland 2700 2300 Poland 600 600 Germany 615 615 Source: Nordic TSOs. Although all the Nordic countries are well interconnected, there are price differences in the Nordic market. The maps below clearly illustrate these differences, even with the countries the scores the highest on transmission capacity with Sweden. The dark blue coloured areas denote which areas Page 12

that had the equal prices in 2013. The top left corner shows that Finland and the four Swedish price areas had a common price (no congestion) for 78 per cent of the time in 2013. The middle and north of Norway had a common price with SE1 and SE2 for 83 per cent of the time. Norway and Sweden had equal prices 38 percent of the time. In 2014, congestion increased between Sweden and Finland as the percentage of hours with equal prices dropped to 51 per cent. Central and Northern Norway had similar prices as SE1 and SE2 during most of the time both in 2013 and 2014. Figure 3.2: Percentage share (dark blue) of the number of hours with equal price in 2013 and 2014 Source: Nordel Nordic Market Report 2014 (http://www.nordicenergyregulators.org/wp-content/uploads/2014/06/nordic- Market-Report-2014.pdf), Montel, Nord Pool Spot. Page 13

Price differences occur when the available transmission capacity between two bidding areas is limited. The limited capacity may be due to fundamental differences in generation and demand structures as well as seasonal or daily fluctuations in demand and generation. Congestion may also be due to maintenance work or failure in the transmission network that temporarily reduces capacity. There was a common Nordic price for 23.4 percent of the hours in 2013. This share has fallen from 25.1 percent in 2012 and 26.2 percent in 2011. In more than 50 percent of the hours in 2013, there were only two different prices in the Nordic electricity market. It is also important to keep in mind that the average G component can be quite unrepresentative for parts of the country. As for Norway and many other countries, the G component in Sweden varies between different pricing areas. The variation in Sweden is however larger compared to most other countries, see the table below, because of the previously described politics of discriminating between the north and south of Sweden. Table 3.3: Effective generator tariffs 2015 for different types of generation per price area. 2015 SEK Full load hours Price area 3000 5000 7000 SE1 1.6 1.0 0.7 SE2 1.3 0.8 0.6 SE3 1.0 0.6 0.4 SE4 0.8 0.5 0.3 Source: Svenska Kraftnät. THEMA analysis. 3.2 Theoretical assessment of Swedish G component We will now address the question of whether today s G component level and structure are efficient according to the criteria previously defined in 2.4. As we stated in the introductory part of this report, similar G component across countries, even between those with highly integrated markets, should not be the only aim of the regulator. The overall ambition should be to move towards a tariff structure that is economically efficient. In order to assess the efficiency of the G component, we also need to comment more broadly on the current Swedish tariff design (although we do not pretend to make an exhaustive analysis of the subject here): The G component is set at a higher level than in other countries, with the possible exception of Norway. Whether this is a problem is one of the core questions of this report, and will be addressed in part 3.3. The fact that tariffs are capacity-based creates distortions between generation technologies and runs the risk of reducing the development of renewable energy. The fact that the capacity-based tariff is based on subscribed capacity with penalties if the generator injects more into the grid, creates incentives to underutilise generation capacity and possibly also to shortages in the grid in peak load hours. Differences in tariffs between geographical areas could become distortive if they are very large. In Sweden, the particularity of geographical differences in tariffs between the north and south of the country adds to existing differences stemming from different pricing areas. The disincentive effect of current Swedish generator tariffs is increased if generators decide to connect to the regional grid (mainly the case of smaller power utilities and especially for wind energy) since the charge for this connection would then come in addition. In addition to the above-mentioned considerations, it is also important to be aware of possible regulatory risk on the economic impact of the generator tariffs. As for any sector of the economy, Page 14

investments in energy generation requires financing and investors are very perceptive to risk. Increased risk, for instance because of uncertainty surrounding the future regulatory framework, is likely to lead to less investment or higher interest rate requirements (higher cost of capital). This would again either reduce the profitability of power companies or result in higher power prices if the cost is ultimately passed through to the consumers. This effect is well known from regulated infrastructure businesses such as electricity networks. 3 Note that we have not discussed the Swedish energy charge based on marginal losses. While this has a theoretical justification as a short-run price signal, the methodology for setting the charge should be reviewed further (including the type of model for estimating loss percentages, the price of losses and the time resolution). This fall outside the scope of this report. 3.3 Case illustrations In order to illustrate the theoretical analysis above, we now turn to a set of practical examples of how the Swedish tariff system influences the economic decisions of power generators in the medium to long run. We analyse the following cases: 1. Investment in a new wind power plant. 2. Capacity increase in an existing hydro power plant and pumped storage. 3. Choice of subscribed capacity in an existing power plant. 3.3.1 Investment in a new wind power plant We consider the profitability of a hypothetical wind power plant under different assumptions about the geographical location, i.e. different levels of the capacity charge. The general assumptions for the project are as follows: Installed capacity: 100 MW Full load hours: 3000h Annual energy generation: 300 GWh Investment cost SEK 12 million per MW, total investment cost SEK 1200 million Asset lifetime 20 years Real discount rate before tax of 8 per cent For simplicity, we disregard operating costs including the energy charge. We consider two different locations, A and B, with the following capacity charges: A: G component is equal to 47.7 SEK/kW (unweighted average SE1) B: G component is equal to 23.6 SEK/kW (unweighted average SE4) With these assumptions, the annual capacity charge faced by potential investors amounts to: A: 1.6 øre/kwh, SEK 4.77 million annually, net present value SEK 46.8 million B: 0.8 øre/kwh, SEK 2.36 million annually, net present value SEK 23.2 million All else equal, the example project can have a higher investment cost by SEK 23.6 million in SE4 and be equally profitable as the SE1 project, in addition to any difference in market value due to different area prices. 4 All else equal, investors will therefore favour location B. If the difference in the capacity charge does not reflect network costs, there will be too much investment in location B and too little in location A. The difference in tariffs has in this case distorted private incentives leading to 3 See inter alia Alexander et al. (1998), Bazelon (2011) and Solchaga Recio & Asociados (2011). 4 46.8 minus 23.6 million, the difference in net present value of the capacity charge. Page 15

inefficient investments in generation over time. Using the same above, we also note a tariff difference of 1 SEK/kW, which is the cap on the level of generator tariffs according to European legislation, corresponds to a cost of 0.03 øre/kwh and a net present value of almost SEK 1 million for a 100 MW wind power project. An illustration of the practical relevance of this case is Blaiken Vindpark in Northern Sweden, which was put into operation in 2014 with 60 turbines at a capacity of 2.5 MW each. An additional 30 turbines will be put into operation in 2015, giving a total capacity of 225 MW. The expected annual generation is 651 GWh, corresponding to approximately 2900 full load hours. At the point of connection to the central transmission grid, the capacity charge is 45 SEK/kW, which gives a total annual capacity charge of SEK 8.9 million or 1.56 øre/kwh. This is actually well above the cap on the G component in Regulation 838/2010 (1.2 EUR/MWh or around 1 øre/kwh) and represents a difference in LRMC of 0.8 øre/kwh compared to the lowest possible level for a generator given the current capacity charge levels in Sweden. Assuming that connection costs, congestion, and the impact on marginal losses is reflected in connection charges, area prices and energy charges, the difference in capacity charge represents a tax on Blaiken which is hard to justify on the grounds of network costs. 3.3.2 Capacity increase in hydropower plant and pumped storage In this case, we assume that it is possible to increase the capacity of an existing hydropower plant. This could take the form of installing a new and more efficient turbine or adding a second generator unit. The economic rationale behind such a move is to produce a higher share of the available inflows during hours with high prices. If the benefit from doing this is sufficient to cover the investment cost (including any network investments), it is optimal to increase the capacity. However, the capacity charge may make the investment unprofitable for the generator, leading to an inefficient outcome. The extreme case would be a capacity increase without increased energy generation. If the upgrade is part of a reinvestment (i.e. the turbine is in any case due for replacement in the near future), the effective marginal cost of increasing the capacity can be very low. As a replacement is in any case going to be carried out, the net economic cost of increasing the capacity is equal to the cost of the new, more efficient turbine minus the alternative cost of just replacing the old turbine. Assuming that any network costs arising from the capacity increase are recovered through other tariffs and charges, the capacity charge will reduce the profitability without being cost-reflective and may lead to an inefficient outcome. Investments in pumped storage has many similarities with the capacity increase example. With pumped storage, the economic incentive stems from the possibility to use electricity during low-price periods to increase generation during high-price periods. For instance, water could be pumped from a reservoir at a low altitude to a reservoir at a higher level during the night and be used for generation during the day. Seasonal pumping is also possible. The exact possibilities for pumping (seasonal or daily) depend on the specific project under consideration. Again, the capacity charge functions as a tax on capacity and makes pumped storage less profitable. A relevant case which illustrates the incentive effects of the current system, is the Juktan hydropower plant in Västerbotten in Northern Sweden. 5 The power station was brought into operation in 1979 as a pumped storage plant. Water was pumped at night and during weekends and could be used for increasing generation in several hydropower plants in the same river system. The plant was refurbished in 1996 and converted to a conventional plant, motivated by the capacity charges for generators, which were then being introduced by Svenska Kraftnät. 3.3.3 Choice of subscribed capacity in existing power plant In this case, we consider the choice of subscribed capacity in an existing power plant. In this case, we consider the choice of subscribed capacity in an existing power plant. In operational decisions, a 5 The description of the Juktan case is based on information provided by Vattenfall. Page 16

power generator will initially weigh the capacity charge and other generation costs against the income from the power generation. Furthermore, since generators subscribe in advance to a certain amount of electricity injection, and are fined if they inject more, they must make additional decisions as their generation approaches the subscribed amount. These decisions include the fine as a generation cost. How the capacity charge affects the choice of subscribed capacity will differ between types of generation technologies. For a plant with a high load factor, a capacity-based tariff has little impact on the choice of subscribed capacity compared to a lump-sum energy-based tariff. For wind power plants and run-of-river hydropower plants, a lower subscribed capacity will lead to a loss of energy generation, and it is highly unlikely that it will be efficient to subscribe to less than the installed capacity level. For hydro plants with reservoir capacity, the situation may be different. In principle, it may be possible to reduce the subscribed capacity without losing expected energy generation (although at the expense of increased risk of lost generation in periods with high inflows). The capacity charge functions as a tax on capacity. The tax must be covered by the opportunity to raise extra revenue from a more efficient generation profile, i.e. more generation in hours with high prices. If a 1 MW extra capacity subscription costs 47 700 SEK (average 2015 tariff in SE1), the extra revenue must cover that cost. If the extra capacity does not increase energy generation, the revenue must come from a more efficient hourly generation profile (lower load factor). From an economic perspective it is inefficient if there is capacity in the system that is not necessarily available in the market (neither the day-ahead spot market nor balancing markets), as the capacity is essentially free given that it has already been built (sunk cost). Alternatively, the capacity will be available in the market, but at a higher marginal cost than the economically efficient level in order to cover the penalty for exceeding the subscribed capacity level. The capacity charge will lead to higher prices and in a worst case scenario a higher risk of not being able to clear the market, for instance in periods with high loads and little available capacity from wind power and run-of-river hydro. Even though the full capacity may still be used, excess capacity use will incur a penalty, and it will only be profitable for the generator to exceed the subscribed capacity level if the penalty is less than the benefit. Clearly, the economic loss due to unavailable capacity is linked to the underlying price structure and demand for capacity, and the loss may be small in practice. Page 17

4 CONSEQUENCES OF TARIFF HARMONISATION In this chapter, we analyse the consequences of increased harmonisation of generator tariffs with Europe, as well as the consequences of even less harmonisation than today. Today, European legislation (EU 838/2010) limits the annual average transmission charges payable by generators. As the future regulation of generator transmission tariffs is still in development, we have analysed the consequences for Sweden of various scenarios of harmonisation/non-harmonisation with EU regulation. We describe three scenarios for the Swedish generator tariffs in 2025 and quantify the possible effects for Swedish power generation. We find that short-term consequences are limited, but in a longer timeperspective, the investment incentives are adversely affected by higher generator tariffs, particularly if Swedish generators pay higher tariffs than their Nordic counterparts do. 4.1 Future tariff scenarios Here, we describe three possible outcomes for the Swedish generator tariff compared to other countries in 2025. In the first scenario, we assume that today s situation in Sweden continues. In the other countries, we have assumed unchanged tariffs from today s level in real terms which implies a G component of zero in Germany and the other Continental countries with interconnectors to the Nordic region, with the exception of the UK. In the second scenario, we suppose divergence between the Swedish G component compared to other countries in 2025, whereas in the third scenario we suppose convergence of the level of the Swedish G component to levels observed in other European countries today. 4.1.1 Today s situation continues In this scenario, we assume unchanged capacity charge levels equal to 2015 in real terms. Since the hypothesis in this case is no change in the Swedish system, any effects on the merit order must come because of other countries changing their tariff structure. This can happen both as a result of an unilateral initiative in a given country, or an initiative at the European level. Assuming unchanged relative tariff levels and structures, the inefficiencies in the current system are maintained in this scenario. 4.1.2 Substantially higher Swedish G component than in other countries This case can materialise both if Swedish authorities decide to increase the level of the G component in Sweden, and/or if other European countries reduce their tariffs. Short run and long run effects are likely to be similar in principle to case 1, only with stronger adverse effects because the differences to the rest of Europe are larger. Again, the transmission capacity in the grid is a determining factor, and the most important for Swedish authorities is to focus on the differences in tariff structure between Norway and Sweden. An increased tariff difference and a lack of harmonisation may lead to a market perception that the regulation is biased against generators and lead to a perception of increased regulatory risk. If this is the case, adverse effects are likely to be greater due to higher regulatory risk. For the further quantitative analysis, we assume that the 2025 capacity charge base (Svenska Kraftnät s revenue cap minus revenue from the energy charges and congestion rent on interconnectors) is twice the 2015 level in real terms, and that the generator s share of residual tariffs increases to 50 per cent. This gives estimated tariff levels as shown in the table below (2015 levels are included for comparison): Page 18