The Future of Wind Power in Europe Cost-benefit Analysis of Wind Energy Integration into the European Power Market

The Department of Economics and Business Master Thesis, June 2011

Academic advisor: Baran Siyahhan

Author: Michal Babinski

Table of Contents I. Preface ....................................................................................................................................................... 1 II. Problem Formulation................................................................................................................................ 2 III. Delimitations ........................................................................................................................................... 2 IV. Audience ................................................................................................................................................. 2 V. Methodology ............................................................................................................................................ 3 VI. Literature of Criticism ............................................................................................................................ 3 VII. Introduction ........................................................................................................................................... 3 Chapter 1 – The role of wind power in electricity generation ...................................................................... 5 1.1 The relationship between GDP and energy use .................................................................................. 5 1.2 Projections for total primary energy consumption 2007-2035............................................................ 6 1.3 Electricity generation by fuel .............................................................................................................. 7 1.4 Projections for total electricity generation 2007-2035 ........................................................................ 8 1.5 Projections for net electricity generation by fuel 2007-2035 ............................................................ 10 1.6 Electricity Prices ............................................................................................................................... 12 1.7 Feed-in tariffs .................................................................................................................................... 14 Chapter 2 – A closer look at the wind power market ................................................................................. 17 2.1 Market value of wind power in renewable energy sector ................................................................ 17 2.2 Advantages and disadvantages of wind power ................................................................................ 18 2.3 How do wind turbines work? ............................................................................................................ 20 2.4 Wind Power Capacity Installations ................................................................................................... 21 2.5 Wind energy investments in the EU up to 2030 ............................................................................... 23 Chapter 3 – The cost of electricity generation from wind power............................................................... 26 3.1 Literature overview of wind power effect on electricity price ......................................................... 26 3.2 The cost of wind power .................................................................................................................... 27 3.3 How does wind power influence the power price on the spot market? .......................................... 30 3.4 Supply and demand curve in power market ..................................................................................... 31 3.5 Future projections of wind power electricity cost compared to gas and coal ................................. 33 3.6 Price of wind energy ......................................................................................................................... 34 3.7 The cost of power generation from wind energy in comparison to other power plants ................. 39 3.7.1 Overnight construction costs ...................................................................................................... 40

3.7.2 Levelized Cost of Energy ........................................................................................................... 41 3.7.3 Comparison of the cost of electricity generation from nuclear, gas, coal, wind and solar energy in Germany.......................................................................................................................................... 43 Chapter 4 – Power grid and system integration ......................................................................................... 46 4.1 A brief look at power network .......................................................................................................... 46 4.2 Large-scale wind power integration ................................................................................................. 46 4.3 Costs of grid infrastructure ............................................................................................................... 47 4.4 Hints for greater wind power integration ......................................................................................... 49 Chapter 5 – Carbon Trading ........................................................................................................................ 50 5.1 What is a carbon credit? ................................................................................................................... 50 5.2 How buying carbon credits attempts to reduce emissions? ............................................................ 51 5.3 Trading European CO2 Allowances ................................................................................................... 53 5.3.1 The value of CO2 futures contracts ........................................................................................... 56 5.4 Price Movements of CO2 allowances ............................................................................................... 57 Chapter 6 – Wind power vs. conventional power plants as seen from valuation perspective .................. 60 6.1 Impact of risk-adjusted factors on the choice of energy development projects.............................. 61 7.0 Conclusion ............................................................................................................................................. 64 8.0 List of literature..................................................................................................................................... 66 9.0 List of endnotes..................................................................................................................................... 67

I. Preface This report presents an assessment of the outlook for wind energy market with future projections reaching up to 2035. The report was done regarding the European Union member states excluding the first chapter where several paragraphs consider the OECD Europe countries instead (unfortunately it was not possible to obtain data of future projections for energy and fuelspecific consumption and generation trends for the EU). The paper starts with an analysis of the European trends in energy demand and draws a graph representing the relationship of GDP to energy and electricity consumption. Moreover, accompanying the Reference case projections, Low Economic Growth Case and High Economic Growth Case were included in order to show the effects of lower or higher economic growth based on the economic behavior considered in the Reference Case. The section discusses the current electricity prices and applicability of feed-in tariffs for wind power. Advantages and disadvantages of wind power, current market value and future investment into wind energy are found in chapter 2. Chapter 3 evaluates the cost of electricity generation from wind power in comparison to conventional thermal, nuclear and other renewables plants, and discusses wind power’s impact on electricity spot prices and merit-order effect of wind power. Chapter 4 provides assessment of the grid infrastructure costs and large-scale integration of wind energy into the power network. Chapter 5 provides a discussion of the carbon market trading, the effect of CO2 allowances on lesser emissions of greenhouse gases which results in promotion of renewables, here wind power. Chapter 6 gives an example of what risk-adjusted factors should be considered for evaluation of an energy project. Appendix A contains summary tables for Reference case, High and Low Economic Growth case projections of energy consumption in Europe, future projection of electricity generation by fuel, average electricity prices for household and industrial consumers and feed-in tariffs in the EU. Appendix B presents a table on the cost of power generation from wind energy in comparison to other renewables plants.

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II. Problem Formulation Today’s European energy market is undergoing serious changes. The increasing need for electricity requires countries to search for carbon-free fuels that could fulfill consumer demand. The recent data shows that renewables will become the future fuel of power generation with wind energy prioritized as the most promising natural resource for electricity production. Nevertheless, why is the focus on wind power increasing so rapidly whereas so far the most widely used nuclear and coal energy is slightly decreasing? Why would Europe decide to generate power at a higher cost with wind power rather than with less expensive coal and nuclear energy? And how wind power can be fully integrated into electricity networks since the power generation from wind energy is still relatively high in comparison to the conventional power plants and its share in the electricity market is fairly small in Europe?

III. Delimitations The scope of the research was limited to wind energy as it has become a priority fuel for power generation in many European countries. The study explores its rapidly growing position on the electricity market in Europe, compares the costs of power generation with regards to conventional thermal, nuclear and renewable plants. Further, the analysis investigates the costs and benefits of integrating wind farm installations into grid infrastructure and the impact of wind-generated power on the electricity spot price.

IV. Audience This study is aimed at professionals who work in the energy and environmental field such as risk management consultants, energy project coordinators and energy investors. The report mostly deals with the cost-benefit analysis of greater wind power penetration into the electricity market; however, it is also slightly technical in nature. Therefore, other parties who should consider the report as a didactic aid are government energy agencies and environmental and public policy interest organizations that are interested in development of sustainable energy.

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V. Methodology The sources of the materials used for the research over thesis were extracted from the Internet database, energy agencies’ reports available on their web sites, books and newspaper articles available in the university library. Macro- and microeconomic graphs were used to analyze future projection for energy consumption and strengthening role of wind energy in electricity generation.

VI. Literature of Criticism  The data in points 1.2, 1.4, 1.5 was provided for future projections of energy and fuel consumption for OECD Europe as the information for the EU was incoherent, vague and inaccurate. However, since twenty-one out of twenty-seven EU’s countries (EU-15, Estonia, Hungary, Poland, Slovakia, Slovenia and the Czech Republic) are OECD members the analysis was done concerning them. It should be noted, however, that the countries included here are Iceland, Norway, Switzerland and Lichtenstein that belong to EFTA I and Turkey which is a candidate to join the European Union.  Various energy reports were used in the research and therefore the data used in the study might differ from report to report.

VII. Introduction In the years 1990-2005 the electricity demand in the European Union had grown by roughly 1.7% per annum 1 due to increasing consumption of power in commercial and residential sectors 3% and 2.1% respectively. On the other hand electricity consumption in the industry sector recorded a lower but steadier growth of 0.95% per year during the same period of time. The projections for 2010-2035 show that the demand for electricity in Europe will grow approximately 1.1% per year which is by 0.6% lower than during 1990-2005. Electricity consumption in commercial and residential sector is anticipated to increase by 1.5% and 1.3% per annum respectively. The industrial sector is expected to have lowest growth of all 0.7% annually. Increasing number of households, expanding office space and an inclination to outsource heavy industry abroad explains electricity demand growth in particular sectors. I

European Free Trade Association

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Macroeconomic projections show that wind energy will become the fastest growing renewable resource for power generation and its use will be increasing by 6.5% per year during 2010-2035. On the other hand other coal is expected to be decreasing consistently until 2030 whereas natural gas and nuclear are projected to be increasing steadily over the same period of time. In 2010 there was 9,918 MW2 of additional wind power installed in Europe with the contribution of the European Union member states totaling 9,295 MW out of which 883 MW were offshore wind installations. Wind industry experienced capital investments in the EU wind farms of €12.7 billion of which €2.6 billion was allocated to offshore wind farms. Wind power installations made up 16.8% of new capacity installations and the total installed wind capacity in the EU equaled 84,278 MW which translates to a 9.6% share in the power market. Moreover, over the last 15 years wind energy grew an annual average of 17.6% - from 814 MW in 1995 to 9,295 MW in 2010. Interestingly in 2000, 85% of additional wind power installations were attributed to Denmark, Germany and Spain the major players in wind industry, and in 2010 their share has been reduced to 36% which shows that wind energy sector is also seriously considered in other European countries. All EU countries have signed the Kyoto Protocol under which conditions they are bound to reduce greenhouse gas emissions and develop more environment friendly energy market. Furthermore the European Union has introduced its own environmental regulatory frameworks that encourage member states to reduce carbon dioxide emissions and promote electricity generation from renewable fuels. The European Union intends to increase capacity of electricity generation from renewable fuels up to 20% of total energy share by 2020. That is the reason why in order to fulfill the task the EU has set for itself, renewables and especially wind energy have become the future fuel for power generation. Unfortunately, energy-crippled with very scarce natural gas and oil reserves Europe has to manage the system security of its power market and at the same time diversify its energy portfolio in a way that decreases the dependency on fossil fuels and leads to uniform and balanced environment.

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Chapter 1 – The role of wind power in electricity generation 1.1 The relationship between GDP and energy use The production function relates the output of a business to the amount of inputs, typically capital and labor. Therefore it can be simply measured as a function of GDP (Figure 1.1). In the equation below capital (K), labor (L) and energy (E) are the variables that define the production function of GDP. In order to find the formula for energy use the equation is converted. The final result produces energy function which is root square γ of GDP divided by capital and labor. Obviously, when GDP increases so does the energy use and when GDP decreases so does the energy use. Figure 1.1: Production function

GDP = f ( K , L, E ) GDP = K α Lβ E γ GDP γ α β = E K L 1

 GDP  γ E = α β  K L 

Source: Author Figure 1.2 gives a handsome overview on the relationship of energy and electricity use to GDP. Energy demand and economic growth have a bond, however the strenght of that bond varies among regions. In the EU countries economic growth surpasses greatly the growth in energy demand. Developed economies with high living standards have relatively high energy consumption per capita however, their total energy demand increases slowly and is rather stable whereas developing economies tend to have higher energy intensity. Lower energy use is due to the replacement old equipment with newer technology that is less energy intensive. Nevertheless, as it can be seen on the graph, although energy demand is lagging behind the economic growth the electricity demand keeps in tow with GDP growth. High penetration rate of modern appliences and growing office space have a significant impact on electricity demand.

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Index, 2007 = 100

Figure 1.2: The relationship of energy and electricity use to GDP 170 160 150 140 130 120 110 100 90

GDP Electricity Energy

2007

2015

2020

2025

2030

2035

Source: EIA, ‘International Energy Outlook 2010’

1.2 Projections for total primary energy consumption 2007-2035 Figure 1.3 shows economic growth projections for energy consumption for the OECD Europe. From the macroeconomic point of view it is essential to study uncertainties related to economic growth trends. As it can be read from the figure 1.3 there is a reference case and two alternative economic growth cases for the total primary energy consumption II. As it was proved earlier energy consumption follows the GDP growth. The reference case scenario is assumed to be the most probable trend for energy consumption and is used here as more of a benchmark for the two other cases. “In high economic growth case, 0.5% was added to the assumed growth rate for each country in the reference case. In the low economic growth case, 0.5% was substracted from the reference case growth rate.”3 The average annual growth rate in the reference case is 0.2%. The total energy consumption in 2007 was 87,991 petajoules, in 2015 it is projected to slightly decrease by 317 petajoules and in 2035 it should amount to 93,227 petajoules. In the high economic growth case OECD Europe energy consumption in 2015 is expected to be 87,731 petajoules and in 2035 reach a total of 100,204 petajoules which is 6,976 petajoules more than in the reference case. The average annual growth rate in the high economic growth case is 0.5%. On the other hand, in the low economic growth case energy consumption in 2015 decreases by 1,585 petajoules than in the reference case. Moreover in 2035 it is projected to be 86,991 petajoules which is lower by 6,236 petajoules than in the reference case. The average annual growth rate in the low economic II

Total primary energy consumption includes: liquids, natural gas, coal, nuclear and renewables.

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growth case is 0.0%. Therefore the range of uncertainty for 2035 in low and high macroeconomic growth case equals to nearly 13,213 petajoules or roughly 3.663 trillion kWh. Figure 1.3: Reference case - Total primary energy consumption, 101.000 99.000 97.000 95.000 93.000 91.000 89.000 87.000 85.000

Reference case High Economic Growth Case Low Economic Growth Case 2007

2015

2020

2025

2030

2035

Source: EIA, ‘International Energy Outlook 2010’

1.3 Electricity generation by fuel Figure 1.4 represents a model of electricity generation with regards to the type of a power plant that produces electricity in a given time period of the day. The model, however, only assumes the most probable electricity generation by fuel and at what levels of electricity consumption power plants operate. Because of the unavailability of such sophisticated data the model has been made solely for the purpose of this analysis and in order to portray a deeper understanding of electricity generation by fuel and a crucial role each fuel plays in it. Figure 1.4: An assumption model of daily electricity consumption with respect to fuel

Source: Author

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Base load operation (markerd on the figure as number 1) correspnds generally to coal-fired, nuclear and hydro power plants. Interstingly, once those power plants have been commissioned they are set to generate electricity at a fixed level III. Moreover, coal-fired and nuclear plants, especially the latter, have lower than gas-fired plants production cost per kWh production (Table 3.3 page 42). The estimated lifetime of a coal-fired and a nuclear plant is approximately 40-60 years. As the model shows coal-fired, nuclear and hydro power plants generate electricity at the consumption level between 8pm and 10am. It seems unreasonable to produce more electricity at the higher hours of conumption as it means greater loss of unused electricity. Electricity cannot be stored. Middle load (marked on the figure as number 2) applies mainly to gas-fired and other renewables (i.e. wind or solar) power plants. In order to reduce electricity losses to as little as possible there has arisen a need to generate electricity with those power plants whose opertional capacity can be easily regulated. Gas-fired plants are becoming the most dominant source of power generation thanks to low marginal costs in spite of high price for the fuel. The model shows that between 10am and 8pm when the electricity consumption is the most intensive they can be conveniently adjusted to end-user’s needs. Peak load (marked on the figure as number 3) concerns liquid-fired electricity generation. Due to the extremely high fuel expenses this type of power plants is mainly used in the period of the highest consumption. The model shows that liquid-fired plants are at operational capacity between 1pm and 3pm. However, the electricity generation from liquids has been decreasing recently and the future projections maintain this tendency because of very high marginal costs. Nevertheless, as the demand for electricity increases all base, middle and peak load scenarios shift up.

1.4 Projections for total electricity generation 2007-2035 OECD Europe electricity generation increases by 35% from 2007 to 2035 in the Reference case. IV Figure 1.5 shows electricity generation in the OECD Europe with an average increase of III

Energy reports state that it takes a lot of time and it is expensive to readjust the operational level of coal-fired, nuclear and hydro power plants. In case of nuclear energy it is highly dangerous due to sensitive and radioactive fuels and toxic waste. IV Reference case scenario refers to the study prepared by Energy Information Administration that was released in its annual energy report “International Energy Outlook” which can be found at http://www.eia.doe.gov/oiaf/ieo/

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1.1% per year. In 2007, 3,398 billion kWh were produced, in 2015 it will be roughly 3,651 billion kWh and it is projected to reach 4,595 billion kWh in 2035. As it was shown in Figure 1.2, electricity has gained a major share in total energy demand surpassing growth among liquid fuels, natural gas and coal in all-end use sectors but transportation. The recent economic recession slowed down the growth in electricity generation as demand slightly decreased, nevertheless projections in Reference case point out that the growth in electricity use will return to its pre-recession trend. Figure 1.5: Total net electricity generation 2007-2035, (billion kilowatt-hours) 5.000 4.000 3.000 2.000 1.000 2007

2015 2020 2025 Average annual change 1.1%

2030

2035

Source: EIA, ‘International Energy Outlook 2010’ Industrial sector was the most affected by the economic downturn and as a result it has experienced the highest decrease in electricity consumption. Interestingly, the impact of the economic recession on residential and commercial sector didn’t induce loss on electricity demand as the consumers need power for water and space heating, air conditioning, cooking, refrigeration and lightning regardless of the economy’s condition. The electricity markets in OECD Europe are rather well-established and in contrast to nonOECD countries they don’t forecast dramatically increasing energy consumption. However, some countries in OECD Europe (Spain, France and Turkey) project a higher growth in electricity consumption due to steadily increasing population that surpasses the OECD’s average. On the other hand Eastern European countries such as Hungary, Poland or the Czech Republic are experiencing rapid growth in industrial and service sector due to greater inflow of foreign direct investment that has been coming in from the Western European countries and not only.

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1.5 Projections for net electricity generation by fuel 2007-2035 In the upcoming twenty-five years member states of the OECD group will face a steadily increasing demand for electricity in order to meet their energy needs. OECD Europe net electricity generation increases an average of 1.1% per annum from 2007 to 2035 in Reference Case scenario. Only recently, natural gas was expected to be the fastest growing fuel for energy generation. In 2007 approximately 22% of total electricity was generated from gas-fired power plants (Table 1.1). It was forecasted that by 2030 natural gas would become the most dominant fuel for electricity generation with a total of nearly 1,863 billion kWh4 and would surpass presently main electricity generation fuels; coal and nuclear. The attractiveness of natural gas speaks for it fuel efficiency, operating flexibility, relatively short construction times and lower capital investment costs in comparison to the other technologies. In 2030 natural gas was expected to contribute nearly 40% of electricity generation which would almost double its amount from 2007. The most recent study shows that the estimated electricity generation from natural gas will have much smaller contribution in energy sector with a projected share of 22.5% in 2030 and 23.5% in 2035. The difference in projections is due to adjusted growth in nuclear power and a staggering increase in renewables. Table 1.1: Net electricity generation by fuel

Source: EIA, ‘International Energy Outlook 2010’ The contribution of liquid-fired power plants is rapidly decreasing with an annual average of 1.0%. Liquids-fired power plants have the highest marginal cost and therefore are only used in peak loads or in some remote areas i.e. small islands. In 2007 only 70 billion kWh were produced (2.0% of net total electricity), in 2015 it is projected to decrease to 65 billion kWh

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(1.8% of total electricity generation) and in 2030 it will probably drop down to 56 billion kWh (1.3% of total electricity generation). Obviously, unstable oil markets with fluctuating prices are a great discouragement for this fuel. In 2007 coal-fired power plants accounted to 29% of OECD Europe’s net electricity generation. It is forecasted that by 2015 coal-fired and nuclear power plants will be the most dominant sources of electricity generation with a total of roughly 935 billion kWh each. The times when coal-fired power plants were the main electricity producers are fading away. Coal is still widely used fuel for power generation, however, international agreements (Kyoto Protocol) and the European Union’s internal environmental policies aim at reducing greenhouse gas emissions. Since coal is highly carbon dioxide intensive it was decided to limit its use in favor of more environment friendly fuels. In the period of 2007-2035 coal slightly decreases by 0.3% per annum and eventually falls behind nuclear, natural gas and renewable energy. Nevertheless, for some European countries i.e. Poland or the Czech Republic, it will still remain a primary energy resource in electricity generation. High investments costs in renewable technologies and strong dependence on coal-fired power plants hinders the transformation of the energy market in developing economies that has already taken place in economically stable and strong Western European countries. In the Reference case (IEO 2010) it is estimated that in 2015 nearly 25% of total net electricity is generated from coal-fired power plants, a four percentage drop in comparison to 2007. By 2030 coal-fired power plants hit the lowest ever net electricity generation at 878 billion kWh (20%). Nuclear power, next to renewables and natural gas, appears to be the most favorite option of electricity generation. Thanks to its low fuel costs and high efficiency it is economically competitive to liquid-fired, gas-fired and coal-fired power plants in spite of quite high capital investment and operations and maintenance (O&M) costs. Since 2007 nuclear power records an average annual increase of 0.8% in electricity generation from 879 billion kWh to projected 935 billion kWh in 2015 and 1,084 billion kWh in 2035. In Europe there have been lengthy debates about the future of nuclear energy and the countries that were previously against nuclear power or intended to abandon it have reevaluated their standpoints. Germany, Italy and Sweden decided to cancel their decommissioning programs and Belgium has put off its nuclear phase-out by 10 years. For France nuclear power is a significant source of electricity generation (75% of total power generation) and it will not phase out any of its nuclear potential. Furthermore, after 2020

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power generation from nuclear plants is projected to increase vividly due to opening new nuclear plants in other countries i.e. Poland or increasing the present potential i.e. Slovakia, Finland. V Moreover, since natural gas and renewables will not produce enough power to cover the loss incurred from reduction of coal generated electricity, nuclear energy is chosen due to being carbon dioxide free. Renewable energy is the fastest growing electricity generation source and is projected to have an annual average growth rate of 2.6% in the Reference case. The majority of the increase comes from the investments in wind power that has been prioritized in many European countries as the most significant resource for future electricity generation. In 2007, 710 billion kWh was generated from renewable energy with wind power’s 14% share. So far the hydroelectric power plants were the largest producer of green energy, however, recent trends point into the direction of wind turbines as the main resource of power generation. Wind power is expected to increase with an annual average of 6.5% and it is projected to produce 284 billion kWh by 2015 (28% of power generation from renewables) and by 2035 it is expected to capture nearly 40% of electricity generation from renewables, just five percentage points shy of hydropower. There is a significant increase in wind electricity generation with seven out of ten biggest markets in Europe (Germany, Spain, Denmark, Ireland, France, the United Kingdom, and Portugal)5. For European countries reducing greenhouse gas emissions is a crucial incline towards greater investments into renewable energy especially for its environment friendly reasons. The European Union issued in December 2008 ‘climate and energy policy’ which sets a biding target to produce at least 20% of electricity from renewables by 20206. Even though governments’ policies and feed-in tariffs encourage the use of renewable energy it still remains an expensive capital investment in contrast to coal and gas-fired power plants. It is worth noting that roughly 21% of the electricity in the OECD Europe was produced from renewables.

1.6 Electricity Prices Electricity prices in the European Union vary from country to country. Prices are highly influenced by the taxes and overall total costs of producing one kWh of electricity. Tables 4 and 5 in Appendix A show prices set per one kilowatt-hour for households and industry. The recent data presents prices as of January 2011. V

http://www.euronuclear.org/info/encyclopedia/n/nuclear-power-plant-europe.htm

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Table 4 in Appendix A shows average price in euro per one kilowatt-hour of electricity for household consumers, including energy taxes & VAT. It is worth noting that the level of price depends on the amount of electricity consumed per annum, here there are two benchmarks 3,500 kWh and 7,500 kWh. Interestingly, higher electricity consumption per year reflects lower electricity prices for almost all of the countries except Italy, the Netherlands, Sweden and Slovakia. Italy and the Netherlands experience very high price increase of 0.07 €/kWh and 0.056 €/kWh respectively, because a significant portion of electricity generated in both countries comes from gas-fired power plants. Since gas-fired power plants carry the second highest fuel costs of all available energy resources (after liquid-fired power plants) the greater the power consumption the more fuel is needed to generate electricity which increases power generation costs and eventually results in higher prices. For Sweden and Slovakia the price increase is very small and bears a minor impact on the final price result. Bulgaria is the only reported country that has a price of electricity slightly below 0.1 €/kWh. On the other hand Denmark reports the highest price for one kilowatt-hour in the European Union that is 0.2632 € and can be explained by the fact that roughly 53% of the price is tax. Germany has the second most expensive electricity in the EU that equals 0.2455 €/kWh. The majority of Germany’s electricity is generated from carbon intensive power plants such as coal and natural gas that carry additional costs in form of CO2 allowance which leads to increased costs per kWh that are borne by the consumers. Table 5 in Appendix A shows average price in euro per one kilowatt-hour of electricity for industrial consumers, including energy taxes & VAT. Here too, the level of price depends on the amount of electricity consumed per annum and there are also two benchmarks of power consumption 2,000 MWh and 24,000 MWh. The price paid by industrial consumers is clearly much lower than for household consumers with an average price decline from 40% to 50%. Obviously, higher power consumption results in significantly lower prices. Even if we compare the lower benchmarks for household and industrial end-users that are 3,500 kWh and 2,000 MWh respectively, the difference in consumption is great, hence the price disparity. The lowest price of electricity at 2,000 MWh consumption per annum is for France with 0.652 €/kWh. France generates about 75% of power from nuclear energy whose electricity generation costs are very low. However, at an annual consumption of 24,000 MWh Estonia offers the lowest price of 0.048 €/kWh and is trailed behind by Bulgaria and France with 0.0554 €/kWh and 0.0559 €/kWh

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respectively. Approximately, 85% of electricity in Estonia VI is produced from oil-shale power plants that carry relatively low costs and in Bulgaria the bulk of power is generated from coalfired power plants that still have very low marginal costs. Interestingly, Denmark reports the largest price disparity for the electricity price between household and industrial consumers that amounts to as high as 0.16 €/kWh. As it was mentioned before prices depend on the amount of taxes and total costs incurred during electricity generation.

1.7 Feed-in tariffs National governments all around the world have been introducing a variety of environmental schemes to promote broader use of electricity generated from sustainable energy. Utilities generating electricity from renewable resources can now depend on secure financial support which is distributed as a subsidy per kW of installed capacity or a payment per kWh generated and sold. There are two main regulatory schemes; feed-in tariff and a fixed premium. A fixed premium mandates that governmental institutions or power suppliers have to pay for renewable electricity in addition to the electricity price that they purchase from legit power producers. However, there is one drawback to the premium scheme; an owner of a renewable power plant receives a payment which is not as stable as under feed-in tariff because the price of electricity is volatile. In Europe the fixed premium has been initiated so far in Denmark, Germany and Spain where the scheme is financed with additional fee imposed on the electricity bill that pertains to all of the power consumers in the given region. Feed-in tariffs have been more popular with renewable energy produces as they are payments for kWh of electricity generated from renewable resource. FITs have grown to be the most successful incentive for businesses and land owners to grasp the opportunity of making stable and reliable earnings and at the same time contributing to greater development of renewable energy. For instance, many farmers have decided to lease their land to wind power generators and in return they receive stable annual income. In contrast to growing crops farmers don’t have to rely on favorable weather conditions or worry about natural disasters such as floods or bushfires which could destroy the crops and undoubtedly decrease their profits from sales of

VI

http://www.geni.org/globalenergy/library/national_energy_grid/estonia/EnergyOverviewofEstonia.shtml

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goods . Even pastures used for grazing cattle are safe for wind farm installations as they pose no harm to farm animals. Feed-in tariffs are also used in order to determine the location of a future wind farm and the amount of installed generating capacity added. A great advantage of feed-in tariffs is that government-regulated price on the electricity from renewable energy enables wind power producers to sell their power to the grid. Therefore power generators are secured with a positive return on the wind power investment which in return contributes to the eligibility of sustainable energy project to receive financing such as bank loans to cover the investment costs of the project. Wind farm involves installing many wind turbines on large areas of land or sea so that high enough amount of electricity is generated to deliver it to the grid. Wind farm installations have been erected the world over in great numbers recently due to enforcing energy laws favoring renewables and also feed-in tariffs, especially popular in Europe. Since the government feed-in tariffs regulate the long-term price on electricity wind farm operators can sell it to the power supplier as they are assured of promised return on the project. Although wind power is dependent on governmental regulations to compete successfully with conventional technologies the cost of electricity generated from wind farms is decreasing every year. Coal-fired and gas-fired power plants incur lower capital investment costs than wind farm installations as measured in the cost per kWh, however due to the use of fossil fuel input whose price is unpredictable and carbon levy in form of CO2 allowance, wind power is likely to continue to grow and increase its power market share significantly. Among the European countries that have been implementing feed-in tariffs with success are Denmark, Germany and Spain. Denmark is the number one country in the world where wind-generated electricity contributes to more than 20% of total power consumption – in 2010 it was 24%. The latest legislation on feedin tariffs was introduced in 2003 titled ‘Act on Energy Supply’ and since it has been implemented successfully. As seen from the Table 6 (Appendix A) the feed-in tariff for onshore produced wind power equals 0.035 €/kWh and is the lowest in the European Union. Denmark’s large share of wind energy in the power market could be contributed to Vestas, a global leader in

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wind turbine production thanks to which efforts wind power was an early entrant in the country’s power market. Germany’s share of wind power in the total energy consumption was 9.4% in 2010. Germany was also the second largest country with added wind power installed capacity in 2010 of 1,493 MW7. The latest legislation on feed-in tariffs was accepted in 2000 and is known as ‘Erneuerbare-Energien-Gesetz’ or ‘Renewable Energy Law’ and it has been the main active policy controlling the economic and financial support to the wind power sector. The feed-in tariff for onshore wind-generated power oscillates between 0.05 €/kWh and 0.09 €/kWh. On the contrary feed-in tariff for offshore wind installation is higher in range of 0.13 €/kWh and 0.15 €/kWh which can be explained by higher capital investment costs required for offshore wind installation and also several percentage point share in total power generation from wind energy. During 2010, 1,516 MW of installed wind generating capacity was added to Spain’s wind power sector – the largest amount in the European Union. In 2005 Spain accepted “Plano de Energías Renovables” or “The Plan for Renewable Energies” that set the capacity targets of wind power energy in 2010 to reach 20,155 MW. In 2010 the total installed wind capacity was 20,676 MW which exceeded the projected estimate by 521 MW. The share of wind-produced electricity in total power consumption was 14.4% in 2010. The feed-in tariff for onshore and offshore windgenerated electricity is 0.073 €/kWh and is projected to decrease with greater share of wind power in electricity generation. Moreover, “Plano de Energías Renovables” offers low-interest loans that cover up to 80% of capital investment cost for sustainable technologies. Other countries where wind power has also experienced high growth rate are Portugal and Ireland. The former has the second largest wind energy penetration in the power market (after Denmark), nearly 14.8% and the latter places fourth with 10.4% wind power share in total power consumption. Both countries also offer low feed-in tariffs that are 0.074 €/kWh and 0.059 €/kWh for both onshore and offshore wind farm installations, respectively. On the other hand, Italy and the United Kingdom offer very high feed-in tariffs even though they recorded an increased amount of investment in wind power in 2010 which was roughly 10% each of the EU’s total installed wind capacity (9,295 MW). An interesting country is France where onshore feed-in tariffs are low 0.082 €/kWh as opposed to offshore feed-in tariffs that are very high and range from 0.31 €/kWh to 0.58 €/kWh.

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Chapter 2 – A closer look at the wind power market 2.1 Market value of wind power in renewable energy sector The global renewable energy market was valued roughly at €170 billion VII in 2010 and it is projected to increase by nearly 47% (CAGR VIII of 8.1%) in a five-year span reaching market value of almost €250 billion in 2015.8 Wind energy, which has become the largest and the fastest developing segment of the market, was valued at €49 billion in 2010 and is expected to grow in its value up to €65.5 billion by 2015 which gives an increase of 33.7% (CAGR of 6%). Hydroelectric energy, that for many years has been a driving force in generating power from sustainable resources, has been overtaken by wind power and is currently placed as the second largest sector. Its estimated value in 2010 was at €46.8 billion and in the upcoming 5 years it is projected to grow by 19.4% (CAGR of 3.5%) to reach roughly €55.8 billion in 2015. Even though the amount of electricity produced from solar energy is much behind that of hydroelectric or wind power it is projected that this segment will record the highest growth rate. The 2010 value of solar energy segment was estimated at slightly over €33 billion and it is expected to increase by 120% (CAGR of 17.1%) in the next five years – €73 billion in 2015. The geothermal energy segment 2010 value was assessed at €4.5 billion and it is projected to increase by approximately 47% (CAGR of 8%) to reach €6.6 billion in 2015. Energy generated from ocean tides or waves represents the smallest segment of market for renewables whose value in 2010 was close to €1.8 billion; however, it is expected to grow by nearly 83% (CAGR of 12%) to reach a value of €3.3 billion in 2015. With the years to come as the technology becomes more advanced and the cost of power generation from various renewable fuels decreases price competition will arise among energy suppliers. If the price of fossil fuels such as natural gas and coal will record price decline, it will become a daunting task for wind power producers to lower the electricity costs even though as the future projections show most of the investment will be sent to more capital-intensive offshore wind installations. Therefore, it is essential that the pursuit of greater power generation from renewables is not limited to only wind power but it is also focused on utilization of other

VII VIII

The value was converted from USD to Euro at the average annual exchange rate in 2010 of 0.7547 €/$. Compund annual growth rate

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renewable resources such as solar, hydro, geothermal or ocean tides. As long as the renewable energy sector is given support from governments in form of financial aid and environmental policies mandating countries to wider use of ‘green energy’, renewables will find a way to obtain a larger share of power market contributing to cleaner environment and eventually lower electricity prices.

2.2 Advantages and disadvantages of wind power Advantages: •

Wind turbines have become a revolutionary solution to capturing the enormous potential of wind power one of the most abundant and infinite resources of energy on the earth. Wind is inexhaustible and it is produced by atmospheric temperature variations, the rotation of the earth, land and sea effects, and pressure differentials between weather systems. Wind turbines generate power through a solely mechanical process that requires no chemicals or fuel combustion, hence it is pollution free.

•

Wind farms have the advantage over fuel powered plants that they require no fuel. There is no need to construct pipelines that deliver natural gas, mines that extract coal or deal with radioactive toxic waste that is left from nuclear plants.

•

Currently, most of the wind power in Europe comes from wind farms installed onshore. The strongest and most incessant winds (with speed above 7.5m/s) can be found at sea, making it a very favorable location for wind farms installations. However, offshore wind farms involve higher capital investment and O&M costs and thus are more expensive. Nevertheless, European countries are making a push towards increasing wind power generation capacity in order to meet the demands of GHG reduction through more extensive and efficient use of renewable energy.

•

A typical wind farm consists of a few dozens of windmills whose tall structures and wide rotors need a lot of space between one another and that is the reason why wind farms are installed on large geographical areas. Interestingly, the unoccupied land on a wind farm can still be used for farming or livestock grazing. For instance American farmers can enter into a lease agreement with wind energy operator and receive additional annual

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income of around €100 IX per hectare or between €2,500 and €4,500 for every MW installed.9 Leasing land to wind energy operators can be seen as a new way for farmers to raise more revenue as it appears to be more stable than that from agriculture especially in the periods of economy’s boom-and-bust cycles. •

The growth of wind energy industry has been tremendous and recent research done by the European Wind Energy Association (EWEA) shows that for every megawatt of installed wind power capacity approximately 15 to 20 jobs are created directly or indirectly.10

•

Investment in wind energy increases the contribution of renewable resources of a country’s power generation forces and by this diversification decreases dependence on fossil fuel such as coal or natural gas.

Disadvantages: •

Wind is a natural resource that cannot be fully controlled and as a result windmills are totally dependent on its speed. If the wind is too weak the turbine will not operate and if it is too strong the turbines will be turned off in order to avoid getting damaged. It has been shown that creating interconnectivity between wind farms helps reduce such problems and results in more even energy flow and production.

•

As it was mentioned before power generation from windmills is strongly related to wind speed. It has already been proved that wind turbines are set at an operational mode roughly 65% to 80% of the time. Moreover, a typical capacity factor ranges between 20% and 40% reaching the upper limits at favorable conditions in strong wind sites.11 For instance, a 2 MW wind turbine should usually produce 17,520 MWh X (2 MW * 24h * 365 days), however, considering a capacity factor of 30% this amount changes to 5,256 MWh (2 MW * 0.3 * 24h * 365 days).

•

Unfortunately, as of today wind power still remains more costly in comparison to other conventional power sources. Windmills are tall structures that reach an average height of 130 meters including the rotor blades. To provide strength and reliability expensive and sophisticated materials have to be used; tower is made of reinforcing steel, rotors of carbon fiber and the turbine is comprised of nearly 4,000 components.12

IX X

The value was converted from USD to Euro at the average annual exchange rate in 2010 of 0.7547 €/$. http://www.ceere.org/rerl/about_wind/RERL_Fact_Sheet_2a_Capacity_Factor.pdf

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•

Many of the locations for wind farms can be found in remote, windy areas far away from cities or towns. An additional expense is incurred as transmission lines are stretched which influences negatively the cost of the project.

•

Before a location is found suitable for a wind farm installation an extensive study must be done in order to assess wind speed and the amount of power output that can be obtained from it. In Europe the five top countries with the highest investment in wind power are Germany, Spain, Ireland, Denmark and Great Britain.13

•

Arguments have been raised that windmills are a dangers to birds or bats that sporadically are caught in the rotor blades. Some studies show that the number of birds killed by wind turbine blades is lower than that of number of birds died from crashing into windows, building or planes. One research presents that roughly 1 in 30,000 bird deaths are caused by windmills.14

•

In the past communities complained about the level of noise produced by wind turbines. Over the years the technology has been improved and currently wind turbines operate quietly and produce noise comparable to a kitchen refrigerator or a freezer. Another problem was inconvenience due to shadow cast by windmills closely located to buildings. Placing windmills can have also a negative effect on land’s value as lease agreement are often signed for 30 years and longer during which time the lessor mustn’t breach the contract. Other people regard windmills to be spoiling the landscape and protest against constructing wind farms in their communities. The only solution to this disapproval seems to be locating wind farms in unpopulated areas in the vicinity of towns and cities.

2.3 How do wind turbines work? We all have seen those creaky old windmills on farms and although they might seem to be about as low-tech as they can get those old windmills are the predecessors of the new modern wind turbines that generate electricity. The same wind that used to pump water for cattle is now turning giant wind turbines to power cities and homes. Today’s wind turbines are much more complicated machines than old prier windmills. But the principle is the same, both capture the wind energy. First, a wind turbine blade works sort of like an airplane wing. Blowing air passes around both sides of the blade, the shape of the blade causes the air pressure to be uneven, higher

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on one side of the blade, lower on the other and that's what makes it spin. The uneven pressure causes the blade spin around the center of the turbine. On the top there is a weather vane that is connected to the computer. To keep the turbine turned into the wind so that it captures the most of energy. The blades are attached to the shaft which turns only about 18 rpm. And that is not merely to generate electricity by itself. Therefore the rotor shaft spins a series of gears that increase the spinning to about 1800 rpm and at that speed the generator can produce a lot of electricity. So, why are wind turbines so tall? The higher up you go the windier it is. More wind naturally means more electricity and in many cases larger turbines can also capture wind energy more efficiently. The blades can sweep a circle in the sky as long as a football field (roughly 100 meters). Now what is really interesting, even a small wind farm can generate enough electricity to power more than nine-thousand homes and much larger wind farms can provide much more clean energy for homes and businesses. Figure 2.1: Diagram of a wind

Source: Wind Power: How Wind Turbines Work, www.digtheheat.com/Wind/how_windpower_works.html

2.4 Wind Power Capacity Installations In 2010, 52,855 MW15 of new installed capacity was added of which 17.6% is contributed to wind power installations. During that year 9,296 MW of wind power was installed in the European Union which was an 8.5% decrease in comparison with the previous year. The majority of wind installations were onshore projects with power capacity of 8,413 MW and 883

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MW offshore. Last year was not so favorable towards wind energy because it was overrun by natural gas and solar photovoltaic project installations. Natural gas and solar photovoltaic recorded an addition of over 28,000 MW and 12,000 MW of power capacity or roughly 51% and 21.7%, respectively.

Figure 2.2: The EU market share for new capacity installed in 2010. Total 9,058 MW.

Source: EWEA, ”Wind in Power, 2010 European Statistics”, February 2011. Looking from the financial point of view the wind market experienced significant investments that totaled nearly €12.7 billion in 2010 of which €10.1 was credited to onshore wind farms and €2.6 billion was attracted by the offshore wind farms. As seen from Figure 2.2, Spain was the biggest market in terms of wind power installations that reached 1,516 MW and is followed by Germany with 1,493 MW of recently added wind power capacity. France, the United Kingdom and Italy are the only countries that managed to increase wind power capacity by more than 10% which in power terms is shown as 1,086 MW, 962 MW and 948 MW respectively. Other countries that performed exceptionally well are Sweden and recently joined EU member state Romania who added 604 MW and 448 MW of wind power capacity, respectively. It is also worth noting that Poland is the only country of EU-12 that is listed among the largest wind power markets with annual wind capacity installation of 382 MW.

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2.5 Wind energy investments in the EU up to 2030 In the past 25 years Europe has experienced large amounts of capital investment being allocated to the wind energy sector. Introduction of newer technologies with larger turbines and rotor spans, grouping wind mills in larger numbers to construct more efficient wind farms, wider integration of renewables into the national power grids and governmental aid have all influenced positively the economic evolution and cost-effectiveness of wind power. Figure 2.3: Investments into wind energy 2000-2030 (€ million)

Source: EWEA, “The Economics of Wind Energy”, March 2009 In the last decade there was very little investment in offshore wind turbines with an annual average of roughly 1% in years 2000-2007. However, after 2008 offshore investments have gained momentum and in 2010 approximately 9.5% (883 MW) was supplied to offshore wind farms. Northern European countries, based around the North Sea and the Baltic Sea, are the most significant participants in developing new projects for offshore wind farms. Figure 2.3 presents projected annual investments into wind energy from 2010 to 2030. Until 2015 yearly investments of €10 billion are expected to steadily flow into the wind market. It is estimated that by 2020 annual market for wind exceeds well over €15 billion with approximately 50% of the investments allocated to offshore projects. Interestingly, during the following ten years up to 2030 offshore investments are projected with a steadily increasing share of the wind market whereas onshore investments experience a rather even level of investment. In 2030 approximately €20 billion is invested in the EU with 60% annual wind market share of investment in offshore turbines. Nevertheless, the projections are prone to changes due to unforeseen economic events such as global financial crisis from 2008-2009 or issuing new directives on renewable energy regulatory framework where European countries are bound to

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generate a mandatory percentage of electricity from renewable resources in order to decrease dependence on fossil fuels and reduce greenhouse gas emissions. The reason why offshore turbines have been shown little interest is because of higher installation costs which exceed by nearly 50% than those of onshore sites. However, there are great benefits of offshore wind farms such as higher wind speeds, no complaints on the noise or visual obstruction of larger wind mills and lots of area to explore. Therefore, Germany, Denmark, Great Britain and several other European countries are very determined to reach the goals regarding the share of wind in power mix. All things being equal, the higher investment cost of offshore wind farms is compensated with higher capacity for electricity generation as coastal sites generally record higher wind speeds. As it will be discussed further in the paper the average annual number of full load hours is usually from 2,000 to 2,500 for onshore wind farms whereas for an offshore installation there can be as much as 4,000 full load hours within a year considering the site. Figure 2.4: Wind investments compared with life time avoided fuel and CO2 costs (Oil – $90/barrel; CO2 – €25/t)

Source: EWEA, “The Economics of Wind Energy”, March 2009

The graph in Figure 2.4 represents lifetime CO2 and fuel costs avoided during operational lifetime of a wind turbine for each of the given years from 2008 to 2030. The generating capacity lifetime for onshore and offshore wind turbines has been considered to be 20 and 25 years respectively. For the purpose of preparing this study it has been assumed that the average price of CO2 allowance is €25 per metric tonne of CO2, the efficiency of wind energy reduces greenhouse gas emissions on average by 690g CO2/kWh produced and the fuel cost of €42

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million is avoided for each TWh of wind electricity generated. An oil price of $90 is assumed in the study16. As it can be read from Figure 2.4 approximately €12.7 billion was invested into wind power in 2010 which leads to lifetime savings of around €19 billion worth of fuel and €6 billion worth of CO2 allowance. By the year 2020 combined lifetime cost avoided for CO2 and fuel reaches almost €60 billion and annual investment in wind power market amounts to approximately €18 billion. Apparently, a 50% increase in wind investments brings about a 300% increase in CO2 and fuel costs avoided. It is projected that after the year 2020 annual wind investments are on average €20 billion which leads to lifetime cost avoided of roughly €47 billion and €20 billion for fuel and CO2, respectively. A simple calculation shows that for every €1 billion invested into wind power after 2020 approximately €3.3 billion is avoided in CO2 and fuel costs. From year 2010 to 2030 wind market experiences approximately €340 billion of investments that will avoid roughly €780 billion worth of fuel and €320 billion in CO2 allowance. Of course, these projections are bound to change due to constantly fluctuating oil price which at the time of writing this paper is 112.6 US$/bbl XI and also CO2 allowance that has been set at €25 CO2/t for this analysis.

XI

http://energy.eu/ Accessed on 9 May 2011.

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Chapter 3 – The cost of electricity generation from wind power 3.1 Literature overview of wind power effect on electricity price In recent years the share of renewables in electricity generation in Europe has been growing considerably. Discussion and intensive debates on applicability of feed-in tariff systems have been an important factor with regards to benefits of increasing investment in renewables to generate more and more electricity from non-fossil fuels. The following section analyzes meritorder effect (MOE) the impact of adding wind into the power mix on the electricity price. Estimating the appropriate value of the merit-order effect is a very difficult job because electricity demand and generation of electricity from renewables fluctuates every day on an hourly level. Thus, in order to replicate hourly spot market prices a sensitivity study is done considering different computational agents affecting the electricity market such as consumers, renewable factors, government incentives, grid and market operators. The following section reviews several studies that assess the contribution of wind in power market, its influence over spot electricity prices and investigates the overall result on power plants, load and renewable electricity generation. Figure 3.1: Price effect on wind capacity penetration – literature review

Source: EWEA, “Wind energy and electricity prices”, April 2010 The studies that are used here discuss a variety of factors concerning the price and merit-order effect of wind power penetration in European countries. Even though authors investigate different hypotheses in their respective papers, their conclusions produce alike results. •

As it has already been said the only way of reducing the greenhouse gas emissions is by investment in green technologies such as wind power. Not only do the papers analyze the

26

effects of wind technology’s impact on merit-order effect by replacing electricity generation from fossil fuels but also assess the stance of wind power in merit-order curve. •

In the reviewed countries the majority of electricity is produced from hard coal which in periods of low demand regulates the wholesale market price. In order to capture the best of merit-order effect wind power should replace hard coal derived power generated in periods of low demand and natural gas derived power in periods of high demand.

•

An argument was presented in the studies that wind power could replace part of the base load energy usually generated from coal-fired or nuclear power plants. Authors suggest that construction of big wind power networks integrating areas spreading over national borders i.e. Denmark, Germany and the Netherlands could decrease dependence on fossil fuels for power generation in favor of renewables.

•

Greater electricity generation from windmills is shown to decrease wholesale spot prices. Merit-order effect can be seen ranging from 3 to 23 €/MWh (Figure 3.1).

•

The papers also discuss that greater penetration of wind power leads to direct and indirect cost savings due to lesser share of fossil fuels in electricity generation (wind has zero fuel cost), hence consumers (end-users) would pay a lower prices.

3.2 The cost of wind power As it can be read from Table 3.1 over 75% of the total cost of energy generation is contributed to wind turbines. Other upfront costs that follow are grid connection, foundation and land rent with a total cost share of 8.9%, 6.5% and 3.9% respectively. Wind turbines in contrast to conventional power plants are not affected by fluctuating fuel price that is the focal point in determining electricity price. Wind technology is capital intensive whereas fossil fuel fired technologies i.e. gas-fired or coal-fired power plants are strongly influenced by fuel costs, 70%-80% and 40%50% respectively (See Table 3.2 page 44.).

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Table 3.1: Cost structure of a typical 2 MW wind turbine installed in Europe (measured in € 2006)

Source: EWEA, “The Economics of Wind Energy”, March 2009 The estimated operations and maintenance (O&M) costs for electricity generated from onshore wind energy are given between 1.2 and 1.5 c€/kWh during the turbine’s operational life span17. The data provided from Spanish energy department point out that O&M of the turbine and power installations, spare parts and labor costs are accountable for roughly 60% of this amount. Insurance, land rental and overhead are equally attributed to the rest of 40% total costs. Figure 3.2: The costs of wind produced power as a function of wind speed (number of full load hours) and discount rate. The installed cost of wind turbines is assumed to be 1,225 €/kW.

Source: EWEA, “The Economics of Wind Energy”, March 2009 Figure 3.2 presents the cost of electricity generation by categorizing the areas as low wind, medium wind and coastal. The trend curves have been done for Denmark because of unavailable data for other European countries. A simple mathematical calculation is done where the function

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of wind of a chosen site is defined in order to assess the cost per kWh of wind produced power. As seen, at the low wind areas the costs range roughly 6.3-8.0 c€/kWh at 5% discount rate, 7.89.2 c€/kWh at 7.5% discount rate and 9.0-10.8 c€/kWh at 10% discount rate. At the medium wind areas the costs range approximately 5.7-6.0 c€/kWh at 5% discount rate, 6.0-7.0 c€/kWh at 7.5% discount rate and 7.0-8.0 c€/kWh at 10% discount rate. At coastal areas the costs range about 4.8-5.2 c€/kWh at 5% discount rate, 5.7-6.0 c€/kWh at 7.5% discount rate and 6.1-6.5 c€/kWh at 10% discount rate. As it appears it essential to choose the most appropriate discount rate for evaluation of project investments in wind farms. If the discount rate is estimated too high the price of wind generated electricity might be overvalued and if the discount rate is chosen to low the price of wind generated electricity might be undervalued. This is true for low wind sites where the price for kWh of power is much more disproportionate than that of coastal sites. Figure 3.3: Total wind energy costs per unit of electricity produced, by turbine size (c€/kWh, constant €2006 prices), and assuming a 7.5% discount rate

Source: EWEA, “The Economics of Wind Energy”, March 2009 Figure 3.3 shows that installation of wind turbines at coastal sites leads to lower costs of electricity generation as measured in c€/kW. Obviously, as the years moved on larger and more power-efficient wind turbines have been produced. For instance, in 1987 the average cost for coastal site was 9.2 c€/kW for the 95 kW wind turbine and in 2000 it was 5.3 c€/kW for the 2,000 kW turbine, whereas for inland site the cost averaged at 11.6 c€/kW in 1987 and 6.1 c€/kW in 2006 – a change of roughly 42% and 47% respectively. Cost-effectiveness, constantly improved technology and larger turbines are an evident sign of growing attractiveness of wind energy as the most desirable renewable resource to extract electricity from.

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3.3 How does wind power influence the power price on the spot market? The two graphs in Figure 3.4 show the impact of wind power on power spot prices as measured on an hourly basis within a single day. As it can be seen on the left-hand graph two lines are drawn depicting the spot price influenced by absence or presence of wind. The shaded area between the two curves presents the closest price of wind generated electricity which is reflected upon lower spot power prices. Figure 3.4: The impact of wind power on the spot power price in the west Denmark power system in December 2005.

Source: EWEA, “The Economics of Wind Energy”, March 2009 The graph on the right side of Figure 3.4 gives an overview of wind power production at five different levels. Each line represents power prices corresponding to the amount of electricity generated from wind power at each hour of the day. The curve 0-150 MW shows values for approximate prices of wind generated electricity for Western Denmark in a scenario where wind power had no contribution. Taking a closer look at the other curves it can be clearly seen that the higher the electricity generation from wind the lower the spot power price. The curve 150-500 MW shows a scenario with low wind, the curve 500-1000 MW is a situation with medium wind and 1000-1500 MW with strong wind. The line found at the bottom of the graph represents >1500 MW which normally occurs during storms or other turbulent weather conditions. As it can be inferred during the moments when the wind power production levels are the highest the electricity price falls significantly during the daily hours but records a rather small decrease during night hours. It must be noted that the contribution of wind in the power mix has an important influence on the power spot price and it may lead to even bolder decreases in electricity price if wind power

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captures a larger share of the power market. Moreover, a lower spot price would be beneficial to all electricity consumers because the reduction in price is relevant to all power traded and not only power produced by wind turbines. As it was proved in Figure 3.4 wind speed is an important factor in making the final decision as to the location where a wind farm should be constructed. The height of the tower is an important factor that defines how much energy can be generated by wind turbine. As a matter of fact, the electricity output from a wind turbine is proportional to the cube of wind speed (Figure 3.5). For example, if wind speed doubles then power generation increases by a factor of eight. Figure 3.5: Relationship between wind speed and the level of power obtained

Source: http://ecee.colorado.edu/~ecen1500/LectureSlides/Guest1.pdf

3.4 Supply and demand curve in power market Figure 3.6 presents an example of electricity supply and demand curve. As it can be seen, the energy market consists of different power technologies: wind, nuclear, combined heat and power plants, condensing plants and gas-fired power plants. The amount of electricity produced from each of the fuels depends on the cost and installed generating capacity of these power plants. The supply curve depicted in Figure 3.6 is a representation of the merit-order curve. As shown, such curves enter the graph from the cheapest to the most expensive power generators. Since wind and nuclear power have the lowest marginal cost they are shown at the bottom of the supply curve, followed by combined heat and power plants whereas condensing and gas-fired

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power plants carry the highest marginal costs. XII It must be noted that the differences arising in power generation costs depend on the technology used and the amount of fuel it consumes. Figure 3.6: Supply and demand curve in the power market

Figure 3.7: Impact of wind power on the power spot price at different times of day

Source: EWEA, “The Economics of Wind Energy”, March 2009 Figure 3.7 shows the influence of wind power on the power spot price at different times of day. Since wind power carries no fuel costs its marginal cost is low and that is the reason why it can be found at the bottom of the supply curve near the nuclear power. As a result the supply curve shifts slightly to the left and is shown here as the dark-blue line. It is worth noting that the power market is inelastic and electricity is seen as a crucial good without which the existence of modern civilization would be difficult if not impossible. Since the demand is inelastic, even slight changes in the supply might cause significant changes in price. Diversification of power mix by adding wind power affects the supply curve by shifting it in a manner that determines a new power spot price due to occurring market dynamics. In Figure 3.7 during peak demand the generation of electricity from wind power reaches its highest level and thus the power spot price falls from Price A to Price B. Evidently, the power spot price is estimated to be higher in periods of low wind speed and to be lower in periods of high wind speed. This phenomenon is called as the ‘merit-order effect’ and it has already been discussed at the beginning of this section. Nonetheless, the wind power has a significant influence upon power spot price as looking on the hourly electricity consumption. For instance, the most beneficial use of wind power generating XII

Hydropower has not been included in the supply and demand curve since the bids from hydro power are usually strategic and are dependent on rainfall and the level of water in reservoirs.

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capacity can be obtained at midday, during the peak load when the demand is the highest. As seen from the graph in Figure 3.7 we find ourselves at the steep part of the power supply curve and with high wind speed, wind power plays a significant role in power spot price reduction. On the other hand, at night the majority of electricity is generated on base load plants such as coalfired or nuclear and at that time of the day greater power production from wind will have a minor influence on the spot price because it occurs at the bottom part of the supply curve where the demand and consumption are at their lowest. There is also a risk that during the periods of intensified electricity generation from wind power transmissions may become congested due to sheer abundance of power supply from other energy sources. Therefore, if it is not feasible to fully relieve the transmission capacity from its excess of power, the supply site is detached from the rest of the power market and allowed to regulate the spot price on its own. Taking into consideration that excess supplies of wind generated power are economically and environmentally beneficial it would seem wise to reduce the production of electricity from conventional power plants in order to achieve lower power spot price in the submarket.

3.5 Future projections of wind power electricity cost compared to gas and coal Figure 3.8: Electricity generating costs in Europe, 2015 and 2030

Source: EWEA, “The Economics of Wind Energy”, March 2009 Figure 3.8 shows the electricity generating costs in Europe for the years 2015 and 2030. As seen the attractiveness of wind-generated power is justified by its lower marginal costs as opposed to fossil fuels: coal and natural gas. Competitiveness of wind power speaks for itself; zero fuel costs and no pollution hence no CO2 allowance. In 2015 the cost of electricity generated from wind is

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projected to be 75 €/MWh, from coal 82 €/MWh and natural gas 101 €/MWh. Currently, the majority of wind-generated electricity is delivered from inland sites however, in the next 20 years 60% of total wind-generated electricity will come from offshore sites. Now, as mentioned earlier offshore wind turbines produce power at a lower cost than onshore machines and thus the 7 €/MWh decrease in electricity generating costs which should equal to 68 €/MWh in 2030. The projections show that only the power generating costs for gas-fired power plants will increase up to 113 €/MWh, a 12% change. Coal being the most unfavorable energy fuel due to being carbon intensive will experience narrower use which will result in slightly lower generating costs to 79 €/MWh. Moreover, conventional plants are exposed to uncertainties regarding the future price of fossil fuels which entail substantial risk for future generation costs of electricity. In order to prepare an accurate sensitivity analysis of the electricity generating cost for given fuels a wide range of factors would need to be considered such as fuel price distortions, CO2 allowance, power mix portfolio and merit-order effects, among the most important agents. Although, for the time being wind power might still appear to be more expensive per kWh than conventional power plants, it has one very strong argument in favor of it that would explain growing interest in allocating more and more investments in this power market sector. Fossil fuels and CO2 are sensitive to unforeseen rises in prices which wind power totally hedges against. According to the Europe’s Energy Portal, an EU carbon price of 16.60 €/ t CO2 XIII contributes to approximately 1.7 c€/kWh to the coal generated electricity and 0.8 c€/kWh to the generating cost of natural gas. All in all, the reliability and certainty of wind power costs goes in favor of it regardless of current higher price as contrasted with fluctuating risky future costs of fossil fuel driven power plants.

3.6 Price of wind energy The previous section determined the cost of electricity generated from wind power, yet the price set on electricity obtained from wind energy is very much different than the former one. It is essential to consider the environmental and institutional surroundings that regulate the power price. Not only will the analysis make a comparison between wind-generated power costs and the price for wind power but it also will also investigate under what circumstances future owner XIII

http://energy.eu/ Accessed on 10 May 2011.

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of a wind turbine will be willing to accept the contract (fixed price, fixed premium or fixed payment per kWh). Interestingly, wind-produced electricity does not carry a fixed price which means that it is regulated by a wind turbine owner who needs to perform cost-benefit analysis that serves as a basis for determination whether he is able to fulfill the obligations entailed in the contract or not. The main costs of employing a wind turbine are fixed and known right from the start therefore wind turbine owners would usually prefer solid long-term contracts i.e. 20-25 years in order to secure the risk of their investment. In contrast to conventional power plants such as gas-fired or coal-fired, buyers who decide to enter long-term agreements with wind-generating electricity suppliers are given the benefit of stable and expected power prices. Electricity markets are strongly controlled by the national governments that possess the authority to introduce and implement regulations and energy laws. In order to secure consumers with appropriately adjusted power price it is vital that public regulation oversees monopolies of power transmission and distribution grids and restrains them from taking advantage of their position for their own benefit. However, in the past few decades the energy market has seen greater cash inflows of capital investments which have led to deregulation of it. The emergence of newer transmission and distributions grids providers has led to greater market competition in the segment of wholesale and retail sales of electricity. It is important that market regulations oversee external effects or spill-over effects of the transmission and distribution costs and benefits that are excluded from the prices of the product, here electricity, as they have impact on the consumers who are affected strongly by it. Wind power is a capital-intensive technology and there are many regulatory challenges it must overcome to become a solid competitive player on the power market. Not so long ago energy policies and market regulations existed to better tailor the needs of conventional power plants. However, more focus has been given to extracting energy from renewable resources where technological development has permitted to lengthen operational lifespan and remove the constant fuel price uncertainty as opposed to fossil-fuel driven and carbon intensive power generating technologies. Nonetheless, it must be noted that market deregulation is not going to immediately guarantee that quality and service of the generated and delivered product is excellent as the consumers expect it so. Power market appears to be no different than

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telecommunication market and it has to undergo dramatic changes that meet the criteria of economic and environmental policy. Growing concerns about the increasing amount of greenhouse gas emissions that can cause dramatic climatic destabilization have led many national institutions all around the world to assess the public policies regulating power markets. Electricity generation from conventional power plants has been found liable for the vast economic and environmental costs and heads have turned to renewable resources to improve the social well-being and reduce air pollution. Therefore, there have been lengthy debates about introducing market regulations for renewable resources that would accommodate the needs of the energy market. One of the ways to battle the increasing carbon dioxide emissions in Europe was to introduce by the European Union a pollution tax, commonly known as EU CO2 allowance, which forces the polluter to pay a fee for every metric tonne of CO2 released into the atmosphere. There have been done several studies and demonstration projects that measured the applicability of tax deduction schemes or investment tax credit in order to compare the cost efficiency between conventional plants and renewable energy. The result was that even though renewable energy is more capital intensive and thus, is still more expensive than using combustible fuels its entrance into the power market can be eased away by creating favorable regulating policies and feed-in tariffs that accelerate the process of its integration. There are two basic schemes that represent the process of integration and public regulation of wind energy. Power suppliers of renewable energy can benefit from regulatory price-driven mechanism by obtaining financial aid as payment per kW of installed capacity or per kWh produced or a fixed premium. Feed-in tariffs have become also very popular in promoting renewable energy as individuals and companies are paid for self-produced electricity. The second type of scheme is based on the green certificate models or common energy policies where national governments mandate an increasing share of renewable contribution to gross final energy consumption that comprises of direct use of renewables (i.e. biofuels) in addition to electricity generated from renewables (i.e. wind, hydro, solar).

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Figure 3.9: An example of experience curves to show the future development of wind turbine economics until 2015

Source: EWEA, “The Economics of Wind Energy”, March 2009 The graph in Figure 3.9 presents an experience curve that demonstrates the possible outcome of future development of wind turbine costs until 2015. The first study involving an experience curve was done by Boston Consulting Group in late 1960s and since then it has been a benchmark in designing future projections based on pattern of past results. It must be noted that the experience curve is not the most precise forecasting tool as it difficult to separate experience effects from economies of scale. Experience effects stem from the learning and constantly repeated activities whereas economies of scales stem from intensified scale of production. Since the experience curve doesn’t take into consideration such costs as raw materials or the relationship of supply and demand it only shows a probable trend of a continuing development. Moreover, every experience curve will eventually face a declining return curve which in the end leads to breaking the pattern. Therefore, companies need to pay undivided attention to any factors that can affect the process and the cumulative production quantity that are strongly dependent on the effectiveness of using the experience curve. In the recent years installed capacity of wind power has increased significantly by 25-30% per year in the last decade. It safe to assume that with maintaining such pace the wind power capacity should double roughly every four years. In the analysis for the demonstration of future development of wind turbines several factors were considered, namely:

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•

The experience curve was done for Denmark and presents cost development of coastal and inland wind turbines. The study refers to a 2 MW wind turbine with initial power generation cost of 5.3 c€/kWh and 6.1 c€/kWh for offshore and onshore wind turbine in 2006, respectively.

•

It is projected that cumulative installation of wind power will double every four years when looked at the growth rate of installed generating capacity

•

The analysis maintains the 2006 price up to the year of 2010. Since the wind market has been experiencing and extremely high growth rate, wind turbine producers face great challenges in fulfilling the demand for their machines. The other factor that could not be predicted yet fits the experience curve pattern is the financial crisis that took place in 2008-2009. The economic recession would not have had a great impact on the price but it would definitely reduce the growth rate of installed capacity as many development projects would have been postponed.

•

It has also been assumed that from 2010 to 2015 the rate of learning of 10% follows. It means that the costs per kWh of electricity produced from wind decrease by 10% every time when the installed generating capacity doubles.

In 1985 the cost of wind-generated power for 2 MW turbines located at an inland site was approximately 11.6 c€/kWh and for coastal site 9.2 c€/kWh. In the next twenty years the production costs recorded an average annual price decline of 2.6% and 3% for offshore and onshore wind turbines, respectively. If the 2006 price is assumed for the year 2010 and total installed capacity is doubled every four years then in 2015 the generation cost of electricity from wind would be roughly 4.3 c€/kWh for an offshore installation and 5.1 c€/kWh for an onshore wind farm. However, the graph here represents the projected experience curve for Denmark where the share of wind in the power mix is high (over 20%) and the resource is abundant. Probably if similar analysis was done for a different European country the production costs would be slightly higher influencing the conclusion of final results. For the purpose of this study an average cost increase of 1-2 c€/kWh should be added to wind-generated power for other country than Denmark.

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3.7 The cost of power generation from wind energy in comparison to other power plants The first section of this study presents the analysis of the costs of electricity generation from wind power and compares it to other renewables such as hydro and solar. The study is done for a number of 19 power plants in Europe; 6 onshore wind farms, 4 offshore wind installations, 5 solar photovoltaic plants and 4 hydroelectric power plants. The second part compares the cost of electricity generation from nuclear, gas, coal, wind and solar energy in Germany. Both sections use the levelized lifetime cost approach using the discounted cash flow method in order to analyze the projected plant-level costs measured as overnight construction costs and estimate investment, operations and maintenance, fuel costs and levelized generation cost XIV at 5% and 10% discount rates. The calculations include also carbon allowance cost which is assumed to be 22 € for a metric tonne of CO2/MWh. The costs and prices used in this analysis were converted from USD to Euro at an average exchange rate of 0.7547 €/$ in 2010 XV. The main purpose of this study was to analyze the wind technology with the focus on its capital investment costs and power generation costs in comparison to nuclear, gas, coal, solar and hydro power plants in order to assess the competitiveness of wind energy and identify the characteristics that will have great influence on the dynamics of the electricity sector in the future. It is concluded that in locations where local or weather conditions allow greater power production from wind or hydro it is more favorable and cost-efficient to generate electricity at base load level from renewable technologies. The competitiveness of renewables is dependent on a country’s natural characteristics, the type of energy project financing and the price of natural gas, coal and CO2 allowance. Wind power being capital-intensive and free-carbon technology can definitely be even more competitive if the cost of investment is lower. The research shows that onshore wind farms are experiencing lower power generation costs which is due to constantly improving wind technology, government support and imposing carbon fees on fossil fuel driven conventional power plants that helps to close the competitiveness gap. The main XIV

Levelised generation cost is an economic assessment of the cost of the energy-generating system including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, cost of capital. XV http://www.oanda.com/currency/average

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disadvantage of wind energy is intermittence of fuel and inconsistency that can lead to higher system costs than plants costs, however, these issues can be resolved through geographic analysis and more suitable mix with other power plants. Considering the data obtained for this research, conventional and nuclear power plants have greater competitive advantage over offshore wind installations for base load power production. Taking into account that offshore wind technology has recently emerged on the power market and therefore is relatively immature technology its capital investment costs are projected to diminish with greater power market diversification promoting renewables. Wind power like nuclear has clearly defined capital investment costs which together with predictable variable costs are beneficial in estimating an accurate cost of electricity generation which cannot be said about gas-fired or coal-fired power plants. Moreover, each power generating technology possesses certain important strength and weaknesses that cannot always be measured by the LCOE model applied in the study.

3.7.1 Overnight construction costs The overnight construction cost is a sum of all expenses that have been incurred for constructing power plant as if it the money was spent directly. Table 7 in Appendix B shows overnight construction costs for a wind, solar and hydro power plants in several European countries. As viewed from the table the specific overnight construction costs for wind power range between 1,400 €/kWe and 4,600 €/kWe. Onshore wind farm installations record much lower overnight construction costs than offshore wind farm installations. For instance, France has the lowest cost for onshore sites of roughly 1,444 €/kWe and Italy has the highest cost of 1,991 €/kWe. It appears that onshore wind farms have an overnight construction cost in range of 1,400 €/kWe to nearly 2,000 €/kWe. On the other hand the overnight construction cost of offshore wind farms is much higher and is estimated to be between 2,800 €/kWe and 4,600 €/kWe. Clearly, offshore wind farms incur twice the amount of overnight construction costs than onshore wind installations. The reason for it is that onshore wind farms have lower capital investment costs and also their share in total wind power market is very high at about 90%. Offshore wind installations are more expensive because more costs are incurred in laying down the foundation, production of larger windmills and integrating an offshore site to the power grid. At present

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offshore wind farms are in the process of development and it is expected that the learning curve will reflect in lower power generation costs. Solar Photovoltaic still remains the most expensive renewable resource. The capacity ranges from as low as 0.03 MWe (roof) in the Netherlands to as high as 10 MWe (open-space industrial) in France. Load factors range from 9.7% (Netherlands) to 24.9% (France). Overnight construction costs are the lowest in Germany – 2,467 €/kWe and the highest in the Czech Republic – 5,573 €/kWe. However, being extremely capital-intensive technology doesn’t necessary mean that this sustainable resource will be condemned to unpopularity. Considering the past historical trends and current increasing solar installations driven by strong policy actions taken by the EU government solar energy’s costs might drop by even 50% by 2020 reducing the current expenses between 1,300 €/kWe to 2,800 €/kWe. The data pertaining hydroelectricity is rather limited and doesn’t allow to give a clear picture of its future trends. Hydroelectric power plants are shown as either small or large scale investments. For instance in the Czech Republic both small and large hydro are very expensive as measured in overnight construction costs, both record 8,756 €/kWe and 14,594 €/kWe respectively. On the other hand Sweden offers the lowest overnight construction cost of 2,578 €/kWe.

3.7.2 Levelized Cost of Energy Levelized cost of energy is a vital tool used widely in energy and power industry to compare different power technologies whose life times and capacities are not the same instead of developing a sophisticated finance project. In order to be able to compare the power generating cost with respect to various technologies the model requires obtaining the following data: capacity in MWe, capital investment mil €, fixed and variable O&M cost measured as €/kWe per annum, plant’s efficiency %, economic life years, load factor %, fuel cost €/GJ, the length of construction till commissioning (years), capital recovery factor and overhaul costs €/kWh. Table 7 in Appendix B presents levelized cost of energy for wind, solar and hydro power at 5% and 10% discount rate. At 5% discount rate the levelized generation costs range between 65 €/MWh (Netherlands) and 110 €/MWh (Italy) for onshore wind farm installation whereas for offshore wind farm installations it is between 97 €/MWh (Netherlands) and 142 €/MWh

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(Belgium). There are three main factors that affect the amount of LCOE; fuel, capital investment cost and operations and maintenance cost. Since renewables have zero-fuel cost it must be the other two factors that influence the LCOE. As seen Belgium, the Czech Republic, France and the Netherlands have similar O&M cost that range from 13.5 €/MWh to 16.5 MWh for onshore wind farms whereas in Germany and Italy these costs are much higher 27.6 €/MWh and 32.3 €/MWh respectively. However, the reason for the largest LCOE in the Czech Republic and Italy is attributed to very high capital investment cost; 93.6 €/MWh and 77.6 €/MWh as opposed to the other countries where it is range of 51-53 €/MWh. At 10% discount rate the levelized generating costs increase significantly and now range from 92 €/MWh (Netherlands) to 174 €/MWh (Italy) for onshore wind farm installation and from 141 €/MWh (Germany) to 197 €/MWh (Belgium) for offshore wind farm installations. Apparently, at 5% and 10% discount rates the Netherlands have the lowest and Italy has the highest LCOE for onshore wind farm installations whereas offshore wind farm installations have the highest costs for Belgium at both 5% and 10% discount rates and the lowest for the Netherlands and Germany at 5% and 10% discount rates, respectively. It must be noted that the discount rate factor has almost no impact on the amount of O&M costs as they are remain the same. However, the capital investment cost is affected profoundly by the higher discount rate and has a resounding mark on the final outcome for the project assessment. A switch from 5% discount rate to 10% discount rate increases the capital investment cost by at least 50% for wind power projects. It is safe to say that applying the right discount rate is a vital decision for development of energy project especially those involving renewables as too high discount rate can lead to overestimation of the project and rejecting it in favor of other energy resources i.e. conventional power plants. Taking a closer look at the hydroelectric power plants in Austria, the Czech Republic and Sweden, the capital investment costs increase by 100% at the 10% discount rate. Doubling up of capital investment costs due to the higher discount rate factor would definitely reject many of the profitable projects that would have been approved on any other occasion. The same can be said about solar photovoltaic technology extremely capital-intensive as it is, its capital investment costs rise to huge amounts rendering them totally unacceptable for development.

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3.7.3 Comparison of the cost of electricity generation from nuclear, gas, coal, wind and solar energy in Germany. Table 3.2 presents data on comparison of the cost of electricity generation from nuclear, gas, coal, wind and solar energy. For Germany a CCGT XVI gas-fired power plant have the lowest overnight construction cost of 774 €/kWe and although a PCC XVII coal-fired power plant carries the same capacity as gas turbine (800 MW) it reports much higher cost of 1,904 €/kWe. The difference in costs arises because gas-fired power plants are usually small-scale utilities that require much less time and materials for construction. On the other hand a nuclear power plant incurs the highest investment cost of almost €5 billion but since its generating capacity is large 1,600 MW its overnight construction cost equals to 3,097 €/kWe. Looking at the renewables onshore wind installation has 1,460 €/kWe in overnight construction cost which is much lower than for an offshore one that incurs 3,694 €/kWe. The difference in costs between wind installations is offset by very high capital investment cost for offshore wind farm which allows only a 300 MW capacity. Solar power might be showing an average overnight construction cost of 2,467 €/kWe but due to its very low capacity and capacity (load) factor it is still not very attractive renewable resource. Operations and maintenance cost are much higher for renewables than for the other power plants. It is because renewable technologies are developing technologies that have relatively shorter life times and depend on intermittent fuel. However, renewables have zero-fuel costs and generate no CO2 emissions. A gas-fired plant incurs the highest fuel cost of 44.2 €/MWh which is over two-fold of the fuel cost for a coal-fired plant and over six-fold more than for nuclear plant. Natural gas price is unpredictable, coal is sold under contracts whose price is linked to spot prices and uranium is sold under confidential terms for pre-specified multiannual contracts. But a coal-fired power plant, being more carbon-intensive, suffers from higher CO2 cost of 16.7 €/MWh as opposed to gas-fired plant’s 7.6 €/MWh. Nuclear power is carbon free but its main drawback is the radioactive waste that cannot be refined. Lead time represents length of time (in years) it usually takes to commission a power plant; for onshore and offshore wind installations and solar plants it is about one year, for gas-fired plants 2 years, coalfired plants 4 years and for nuclear plants it can stretch even up to 7 years. Nuclear power plants have the longest construction time as they are built from expensive and sophisticated raw materials, require extensive knowledge for project development and must be thoroughly XVI XVII

Combined cycle gas turbine Pulverized coal combustion

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scrutinized before given final approval for commissioning. The operational lifetime of an asset in power industry is usually very long so that energy investors could earn an adequate return on their investment. It is assumed that lifetime for nuclear power plants is 60 years, 40 years for coal-fired, 30 years for gas-fired and 25 years for wind and solar installations. Load factor or capacity factor represents the relationship between the amount of electricity generated by a plant and the projected maximum that could be generated at non-interrupted power production. Increasing load factor indicates that more electricity is produced per unit of generating capacity which in turn helps recover fixed capital costs of a power plant. For nuclear, gas and coal plants the load factor is assumed to be 85% in order to compare the cost of a kWh generated by these various technologies. The load factor for wind and solar technologies is assumed to be much lower; 20% - 40% for onshore, 25% - 45% for offshore and roughly 13% for solar due to intermittency of the fuel. It must be noted that the load factor for gas-fired plants is highly influenced by the demand for power i.e. during peak loads the electricity consumption is the highest and since gas-fired plants are capable of generating power on short-time notice that is when they are most effectively used. On the other hand greater load factors for wind and solar would lead to lesser reliance on base load power generation and result in reduced power generation costs decreasing the price of a kWh.

Table 3.2: Comparison of the cost of electricity generation from nuclear, gas, coal, wind and solar energy in Germany.

Source: ‘Projected Costs of Generating Electricity’ 2010

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It is evident from Table 3.2 that renewable technologies have a range of values for levelized costs much larger than for nuclear, coal and gas. The reason for that is high uncertainty on projecting their costs. Nuclear power plants represent a capital intensive technology, carbon-free with low fuel cost and long operational lifetime. Its purpose is to generate electricity in great quantity at a base load level at the lowest cost possible. Therefore, it has the lowest LCOE of 37.7 €/MWh and 62.4 €/MWh at 5% and 10% discount rate, respectively. Gas-fired and coalfired power plants present comparable levelized cost of electricity that ranges between 60 €/MWh to 71 €/MWh at 5% and 10% discount rates. However, the volatility of natural gas prices only increases the uncertainty of the level of costs. Moreover, the additional costs induced by CO2 allowances could bear a great impact on shaping the levelized costs for gas-fired and particularly coal-fired power plants. In case of wind technology, onshore wind installations carry lower levelized costs than offshore wind farms as they have already gained a foothold in the power market but still are much behind the main power generators. Offshore wind farms as well as solar plants are new entrants on the power market and there are only a few operational plants to fully exploit their benefits. Furthermore, the amount of electricity generated from these renewable technologies depends of the site they are installed. Finally, wind and solar energy are actively undergoing technological developments and changes in their cost structure.

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Chapter 4 – Power grid and system integration 4.1 A brief look at power network The EU Environment Commission has introduced environmental policies that mandate the EU member states to wider use of renewables so that CO2 emission reduction targets are met. In order to reach that goal wind power needs to obtain a greater share in the power market by means of integrating it into Europe’s electricity network. By the end of 2010 installed wind capacity generated 181 TWh which represented roughly 5.3% of total electricity consumption in Europe. The study of power market done by EWEA18 projects that by 2020 between 14% - 17% and by 2030 between 26% - 34% of electricity consumption will come from wind energy. If these projections were true wind power would level up with contributions from conventional power plants. But, in order to reach these targets it is essential to redesign and improve the efficiency of the current power systems alongside their operational capabilities. It is feasible to reach the EWEA’s forecasts for large share of wind-power generated electricity consumption keeping the system costs at reasonable level and at the same time managing power grid network at a high degree of security.

It is worth noting that wind

technology has little impact on the pace of wind power integration into the electricity network but other agents such as cost allocation for power infrastructure, legal, structural, economic constraints and power market changes have significant bearing in modeling the outline of electricity market.

4.2 Large-scale wind power integration The construction of highly advanced power networks for wind farms can secure voltage and power control whose economic value has a significant role in estimating the power generation costs corresponding to these two agents’ costs. Power generation from wind energy is variable yet predictable over different time periods such as hours, days or seasons and is important for drawing projections of system’s capability and efficiency. Wind farm installations are usually found on remote sites or large areas whose variability can be reduced by integrating them into national electricity networks. In order for wind power to gain greater share of electricity generation several significant factors must be considered i.e. flexibility of power generation, power capture and energy storage, power

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exchange through interconnection and intelligent utilization of wind farm capacity. Moreover, maintaining active control over wind farm power output is essential to ensure system security in the periods of high degree of variability when wind power penetration subsides. Future projections show that wind power will be the largest recipient of investments in the years to come which reflect the importance of economic benefits of upgraded wind technology. Given the fact that wind power entails great potential for carbon-free power generation there is increasing demand for additional financial contributions towards R&D in order to improve the technology in order to ease away the entrance of wind energy into the power market. Incorporating wind power necessitates reducing uncertainties by improving existing forecasting tools and developing models. The recent results of a research undergone by EWEA XVIII show that at a penetration level of 20%, between 4% - 18% of reserve capacity is required for effective use of wind power that is to be reached by 2020. It would mean an increase in additional balancing costs between 2-4 €/MWh. Reducing the uncertainties and forecasting errors can be achieved through agglomerating wind farms over larger areas. Collecting wind farms dispersed in many areas and aggregating them into European transmission networks would have a significant benefit as to managing the efficiency of wind farm installations. From cost-benefit analysis it would result in diminished operational (balancing) costs due to reduced level of uncertainty. It appears to be practical to combine wind farms into an aggregated virtually controlled wind installation as it increases the efficiency and offers a better management over wind power output. One of the examples can be Denmark where integration of wind power into the electricity network has been a great success in developing a better control over variability as well as diminishing the level of unpredictability. In 2010 approximately 24% of total electricity consumption in Denmark came from wind energy.

4.3 Costs of grid infrastructure The cost of integrating wind farms into the power network depends on the location of wind power plants, number of load hours and grid infrastructure. It is difficult to compare these costs XVIII

The study was done for Denmark, Germany, Ireland and Spain.

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between countries as they are influenced by different local conditions. For instance EWEA reports that the cost of grid reinforcement for wind power plants as measured over wind capacity is found between 0–270 €/kW and between 0.1–5 €/MWh as measured over wind power generation. When the level of wind energy penetration increases to 30% these costs usually form 10% of wind power production costs. The costs of extending electricity network likewise the additional balancing costs increase with the higher level of wind power penetration. However, power network costs don’t increase uniformly to the rising wind power penetration. Sometimes there can be very high one-time expense on reinforcing grid infrastructure which is caused by landscape obstructions hindering the development of power network and increasing the transmission costs. Table 4.1: Grid upgrade costs from selected national system

Source: EWEA, ‘Powering Europe: wind energy and the electricity grid’ November 2010. Table 4.1 presents the costs of grid upgrade for selected European countries. As it can be seen Portugal has the lowest grid upgrade costs that oscillate from €53 to €100 per kW of grid reinforcement. Germany reports a fixed cost of 100 €/kW which is due to the fact that majority of wind farm installations are located on land sites in close proximity of motorways and therefore are relatively convenient to link with national power grids. On the other hand Denmark incurs the highest grid upgrade cost which is probably due to its multi-island geographical characteristic which adds extra cost to grid reinforcement and transmission lines. However, in order to achieve a better grid infrastructure it is vital that the member states of the European Union strive for cross-border interconnection of national power networks. EWIS XIX XIX

European Wind Integration Study

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investigated a study where the expected costs of international network developments were calculated for increasing penetration of wind energy from 2008 to 2015. The result was that the costs will range from 25 €/kW to 121 €/kW for short- and long-term measures, respectively. Looking at the additional operational costs the 121 €/kW shows a cost of 4 €/MWh which is a less significant factor among other advantages extracted from wind power generation.

4.4 Hints for greater wind power integration Not only is it important to develop an integrated European electricity network infrastructure by improving transmission and distribution channels but also aiming at creating large-scale wind power market. The amount of wind power that can be absorbed by European power networks is influenced mostly by regional economics and regulatory aspects rather than technical or landscaping constraints. The reason for wind power’s relatively small penetration in the power market is not caused by the wind’s variability or unpredictability but inaccurate grid infrastructure and lack of interconnection impaired by power markets where wind power technology is not seriously considered due to strong reliance on conventional thermal plants. It is assumed that at the present moment approximately 20% of electricity demand on a large-scale power network could be fulfilled by wind energy with no severe technical difficulties. As of 2010, 5.3% of total electricity consumption in Europe was delivered from wind power and even though wind power is still in the lower limit of electricity penetration it doesn’t bear any negative impact on operational aspects of power grids. The existing grid management and power storage systems are fully adequate to manage the variability of wind-power generated electricity even if it could reach a share of up to 20% of power supplies. Nevertheless, in order to achieve higher contribution from wind power it would be necessary to modify power systems so that they are able to capture more wind power. Taking into account the evolution of wind power markets in Denmark, Germany and Spain that are quite abundant in wind resources one can conclude that the potential of increasing wind power penetration into the existing power grids is mostly regulated by economic and legal matters as opposed to technical constraints. Therefore, it is essential that countries who are early entrants on the wind power market learn from the countries who have already gained experience in utilizing wind power to a greater extent.

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Chapter 5 – Carbon Trading It is believed that carbon trading will become the world’s largest commodity market and it might have potential to grow as the largest market overall. After the European Union has introduced a cap-and-trade system for CO2 emissions in order to meet the Kyoto Protocol demands, the carbon trading market has gained a significant role in Europe where it is centered at the moment. In 2009 the carbon trading market was valued at nearly €94 billion19, a slight €2 billion increase in comparison to the previous year. Since the global recession took a horrific toll on many stock exchange trading markets it was also expected to ripple through the carbon trading market violently and as a result the carbon prices fell dramatically and the capability of the carbon trading was questioned. However, to great surprise carbon trading increased by 68% reaching a colossal amount of 82 billion tonnes of carbon dioxide traded.

5.1 What is a carbon credit? The increasing energy consumption is strongly related to economic growth which in turn translates to greater emissions of carbon dioxide found as the main cause of the global warming. For the past two decades many countries have been debating on taking the most efficient course of action in order to reduce the greenhouse gas emissions. Therefore, the European Union member states were among 170 countries that enforced in February 2005 Kyoto Protocol that requires each signatory to reduce greenhouse gas emissions to well-specified caps. In the period from 2005 to 2007, The European Union established a National Allocation Plan that regulated the emission cap for each member state. According to this plan, every member state had to publish a project that determined the quantity of greenhouse gas emission allowances that were allotted to every major company within the state. The introduction of the cap-andtrade system by the EU Environment Commission has allowed for the first time to require the companies to use allowances that specify the acceptable amount of carbon dioxide emissions equal to their cap. Approximately 12,000 companies were included in the compliance period and nearly 2.2 billion EUAs XX were issued to them. At the end of the compliance period, each company must assess the total amount of its emissions and return the equivalent number of EUAs. For example, if a company has generated a total amount of CO2 emissions under its cap XX

http://ec.europa.eu/clima/policies/ets/allocation_en.htm

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then it possesses an excess of EUAs to sell. However, if a company’s total emissions for the period are greater than its cap it means that it has run out of EUAs and needs to buy additional allowances from a company that has extra ones. Currently, there are two international markets the Chicago Climate Exchange and European Climate Exchange where businesses can exchange, sell or buy credits between each other. In trading terms, one credit equals to one tonne of CO2 emissions and is traded on the international markets at the prevailing market price. With respect to the Kyoto Protocol, the second compliance period began on January 1, 2008 and will end on December 31, 2012. As mentioned earlier, the EU Environment Commission realized that the guidelines set in the previous National Allocation Plan were too complex and vague which resulted in total misunderstanding and abuse of the trading system. Therefore, the European Union decided to discard the next National Allocation Plan that will begin on January 1, 2013 and it will determine the carbon dioxide allowances directly at EU Level. There are two ways that a company can follow to reduce CO2 emissions. Adopting new technologies, replacing obsolete equipment or investing money into renewable sources of energy generation such as wind power can aid in obtaining new norms for emission of gases. The other option is to prepare projects that aim at helping developing nations setting up newer ‘green technology’ such as turnkey wind farm installations and thus the company earns so called ‘carbon credits’. So far, mostly European countries have found benefit in this system as the United States did not approve the Kyoto Protocol.

5.2 How buying carbon credits attempts to reduce emissions? The implementation of regulations to reduce greenhouse gas emissions has created the market for carbon credits and has turned the cost of polluting the air into a monetary value. From a business perspective carbon has become a cost comparable to the one as labor, raw materials or overhead. The National Allocation Plan was enacted by the EU Environment Commission in order to set a limit on the maximum amount of emission a company is allowed to emit. To make the picture clear, let’s assume that a business generates 50,000 tonnes of CO2 in a year. The quota set on greenhouse gas emissions for that company is 45,000 tonnes. The company has two choices; it

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can either reduce the amount of emissions in order to meet the quota level or it can buy carbon credits needed to equalize the balance. That is the reason why the European Climate Exchange was founded so that companies would be able to purchase carbon credits on an open market from other companies that have excess capacity of carbon allowances and have been legally approved to sell them. For instance, the seller might be a company that prepares development projects for wind farms and by selling credits it gathers funds to cover the part of the investment expense. Although, the company maintains producing the exact or even higher level of pollution it pays other company to install wind farms that generate power from a renewable resource with no CO2 emissions. As it can been seen from the graphs in this section the level of emissions is projected to be increasing over time. More industries will be included in the European Trading System and the number of companies involved in the carbon trading will increase. As a result of the expansion of ETS the price of CO2 allowance will move up and more companies will be encouraged to pursue and support environmentally friendly actions in order to decrease their greenhouse gas emissions or earn more carbon credits tradable on the market. The outline of the Kyoto Protocol has been used as a basis to develop three mechanisms namely Joint Implementation (JI), Clean Development Mechanism (CDM) and International Emission Trading (IET). Each of these mechanisms is a tool for the European Union’s policy to battle the climate change and a crucial factor in reducing greenhouse gas emissions cost-effectively. Under IET, the carbon trading applies to human-related emissions allowances, chiefly carbon dioxide, in the international carbon credit markets. On the other hand CDM and JI create more flexibility. JI obliges developed countries with relatively high costs of greenhouse gas emissions programs to invest in other developed countries where the costs of greenhouse gas emissions programs are relatively low. In contrast, CDM allows developed countries to set up greenhouse gas reduction projects in a developing country where the investment costs of such projects are usually lower. The great benefit of CDM is that the developed country earns extra credits for achieving its emission reduction targets, whereas the developing country is a recipient of capital and green technology. Furthermore, the participants of each of the programs are entitled to Certified Emission Reduction (CERs) and Emission Reduction Units (ERUs). Both of them can

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be traded on the market and can also be used as substitutes of CO2 allowances at some certain levels. The European Union Emission Trading Scheme was founded in alliance with the Kyoto Protocol in January 2005 and has grown to become the largest international trading market for greenhouse gas emissions. All member states of the European Union are actively involved in its operations. ETS regulates an obligatory carbon trading program, so far the only one in the world. Power generating facilities and carbon intensive business are bound to produce a limited amount of greenhouse gas emissions that is imposed by cap-and trade system which oversees over 50% of the total EU’s carbon dioxide emissions. Of course, critics disagree that carbon trading is the most efficient and effective solution to CO2 reduction initiative. They claim that are many companies that generate little if no pollution and sell their allowances to the highest bidder. Therefore, in order to ensure that the carbon trading system is not exploited and carbon allowances are appropriately distributed, another challenge arises to reduce sufficiently and wisely the number of allowances offered in the system. One of the biggest critics of carbon trading, Carbon Trade Watch, emphasizes on the failure of the ETS to acknowledge broader systemic changes and further complains that fraud and scams benefit only to those that make profit in trading carbon credits. The organization has turned into a watchdog of any mischief and misbehavior of the ETS and calls all interested in combating major polluters to achieve more equitable and sustainable economy.

5.3 Trading European CO2 Allowances European Climate Exchange (ECX) futures market is currently the largest market for trading carbon dioxide credits. The European Climate Exchange was established in January 2005 and is listed for trading on the ICE Futures Europe electronic platform. As of last year nearly 80% of world’s exchange-traded CO2 futures volumeXXI based on the EU Allowances (EUAs) and Certified Emissions Allowances (CERs) was handled by the European Climate Exchange. Despite of the recent economic recession the market has kept on increasing its growth with the European emissions trading scheme (ETS) whose value was estimated at €73 billionXXII. Next to XXI XXII

http://en.wikipedia.org/wiki/European_Climate_Exchange http://www.businessgreen.com/bg/news/1805722/global-carbon-market-expanded-68-cent-2009

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it was UN Clean Development Mechanism (CDM) that delivered €17.5 billion worth of trades and US Regional Greenhouse Gas Initiative (RGGI) that reached a value of around €1.7 billion – a tenfold increase in comparison to the previous year. All carbon trading takes place on the Intercontinental Exchange ICE Futures network as the European Climate Exchange lacks its own electronic trading network. Intercontinental Exchange, Inc. is a publicly traded company listed on NASDAQ with a market capitalization of approximately €9.45 billion as of February 201120. Moreover, not only is ICE Futures the world’s biggest electronic energy futures exchange but it is also most prominent market of energy exchange for futures and options in Europe. Carbon Financial Instrument (CFI) is a CO2 futures contract that can be traded on the European Climate Exchange. The European Union Allowance (EUA) is the underlying instrument which determines the allowance to emit one metric tonne of carbon dioxide. A typical CFI futures contract is comprised of 1,000 EUAs and is expressed in terms of Euros per metric tonne of CO2 emissions. For example, as of May 14, 2011 the CFI futures contract was trading at €16.74 per metric tonne of CO2 XXIII and thus the nominal value of the futures contract was €16,740 (1,000 EUAs multiplied by €16.74). The previous day the futures contract was trading at €16.63 per tonne of CO2 which means that the value of the futures contract increased by €110. Figure 5.1: ICE ECX EUA CO2 Futures – Average Monthly Volume in Contracts 30.000 25.000 20.000 15.000 10.000 5.000 May-09

Aug-09

Nov-09

Feb-10

May-10

Aug-10

Nov-10

Feb-11

May-11

Source: Intercontinental Exchange, www.theice.com

XXIII

https://www.theice.com/productguide/ProductDetails.shtml?specId=197

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As it can be seen from the graph in Figure 5.1 the average monthly volume oscillated from as low as roughly 10,000 contracts in August 2009 to as high as about 25,000 contracts in May 2010 and March 2011. The growing importance of the European Climate Exchange EUA CO2 futures contracts can be further seen in Figure 5.2 that represents the increasing level of open interest. Open interest represents the total number of sold and purchased EUA CO2 future contracts and also those that are still outstanding. As seen in the graph the rapid decrease in open interest that happened around December 2009 and December 2010 was due to expiration of the futures contracts for the given months. European carbon market has experienced an exceptionally high volume of open interest in December 2009 and December 2010 of nearly 400,000 and 550,000 contracts respectively, prior to expiration of the futures contracts. It is believed that the attractiveness of CO2 futures contracts has been brought by selling EUAs at a spot price and repurchasing them at a predetermined fixed forward price which intends to generate bountiful profits from re-swaps. Currently, the open interest volume is of 470,000 and apparently will be even higher than in the previous year. Some reckon that trading allowances for Phase 3, which will commence on January 1, 2013, has already started driving the open interest ever higher. Figure 5.2: ICE ECX EUA CO2 Futures – Open Interest (in # of contracts) 600.000 500.000 400.000 300.000 200.000 01-maj-09

01-sep-09

01-jan-10

01-maj-10

01-sep-10

01-jan-11

01-maj-11

Source: Intercontinental Exchange, www.theice.com

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5.3.1 The value of CO2 futures contracts Table 5.1 provides data on the exchange of EUA CO2 futures settlement prices as of May 12, 2011. Each line shows a different futures expiration month. As seen, the first row is for June 2011 and it presents values concerning the CFI futures contract that expires in June 2011. Table 5.1: Table of ICE ECX EUA CO2 Futures Settlements

Source: Intercontinental Exchange, www.theice.com

There are a couple of important items on the table that need to be addressed. To begin with, December 2011 futures contract was the most popular trading futures contract on the given day which can be observed by the size of volume shown in the sixth column from the left. Furthermore, it can be inferred that the December futures contracts are the benchmark contracts for any year after 2011 as only detailed data related to trading December contracts is available. Even though, the December 2011 volume is the highest the same cannot be said about the number of contracts in open interest which is 145,997. The volume for December 2012 is over three times smaller than for December 2011 however, it represents total open interest of 241,280 which is greater by over 95,000. Taking a closer look at the settlement price for the contracts, it can be seen that the prices for EUA CO2 contracts are projected to increase with every following year. In order to avoid fall in price the European Union might need to reduce the amount of permits in its emissions-trading system. For the time being there are approximately 11,000 businesses and manufacturing

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companies that are encompassed by the pollution limits. The EU’s emissions trading system plans to set a cap on the discharge of greenhouse gas emissions and urges national governments and other energy related public institutions to prioritize energy efficiency in order to achieve a reduction goal of 20% below 1990 levels21. The next trading period starts in 2013 and will run until 2020. The European Union has drafted a plan to tighten the emissions caps and make it more expensive for companies involved in the EU carbon program. The commission has proposed to cut the supply of permits between 500 million and 800 million during the eight-year long trading period. However, many energy-intensive companies especially those involved in steel or chemical industry raised their objections as to the applicability of EU’s cap reduction program. The behemoths claim that it would significantly increase the production costs and make their goods more uncompetitive. On the other hand EU has learned from its mistakes. Back in 2005 when the European Climate Exchange was founded the EU Registries issued too many allowances during the 2005 to 2007 compliance period, rendering them worthless as the price was driven to extremely low levels. For example, the December 2007 futures contract closed at €0.13 per metric tonne of CO2 and a year later the December 2008 contract closed at €19.89/t CO222. During next compliance period from 2008 till 2012 the EU Registries took action and decreased the number of allowances significantly which has been reflected in higher prices for futures contracts and stabilizing the carbon trading market.

5.4 Price Movements of CO2 allowances A strong relation between the price movements of the European Union Allowance and CFI future contracts can be observed. Interestingly, the price of futures contract tracks the price of an EU allowance as it seeks to pinpoint the most desirable value of it. Figure 5.3 shows average monthly futures prices of the EU CO2 allowances. From January 2008 until January 2010 the price was oscillating in the range of €14 to €16 per metric tonne of CO2. The EU Environment Commission decides upon the total number of issued allowances which is a crucial factor influencing the price of EUA. To put it simply, the value of every EUA decreases as the number of issued allowances increases i.e. more CO2 emissions are allowed.

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Figure 5.3: ICE ECX EUA CO2 – Futures Prices €30 €26 €22 €18 €14 €10

Source: Intercontinental Exchange, www.theice.com As it was mentioned earlier, in January 2005 the EU Environment Commission permitted too many allowances to be issued by the national registries in the member states. The outcome of that decision was highly disadvantageous as the European Union found it difficult to reach the target of average 8% reduction of greenhouse gas emissions since it allowed too a great number of EUAs. Other significant drawback was sharp price decline of CO2 allowances that eventually made them worthless and put the carbon trading market in highly unattractive position. With the start of the second compliance period from January 1, 2008 to December 31, 2012 new regulations for CO2 allowances were imposed which resulted in smaller number of issued allowances. The price for future contracts increased up to the level of €25 in June 2007. However, few months later the EU gave a permission to issue more allowances for Ireland, Latvia and the Czech Republic23 which led to price decline that remained stable until March 2010 yet, in February 2009 the price fell to slightly below €10 per metric tonne of CO2. The price equilibrium from 2008 to 2010 can be explained by the economic crisis and developing recovery plans for industries that suffered the most during this period. The higher price in 2010 can be seen as successful implementation of recovery plans that lead to revitalized production that resulted in greater emissions and therefore increased demand for allowances. Another reason for increased futures prices the third quarter of 2010 reaching the highest level of nearly €28 per metric tonne of CO2 relates to the type of fuel used by power utilities. During that period there was a surge in natural gas price which forced power suppliers to increase electricity production from coal-fired power plants in order to avoid increasing costs from gas-fired plants. The wider usage of coal as a dominant fuel resulted in higher price. At the same time speculation

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arose as whether the European Union would increase reduction of emissions from 20% to 30% which eventually rallied the price to €28 in July 2010. Another important market factor upon the price of CO2 allowance is the European Union’s expansion plans of its existing Emission Trading System to airlines, petrochemicals, ammonia and aluminum industries when Phase 3 commences and that happens in January 1, 2013. The impact on the EUA prices can be either mild or severe depending on the weight of allowances supply. Nevertheless, addition of new players to the ETS will certainly strengthen the system and result in increased volume and open interest.

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Chapter 6 – Wind power vs. conventional power plants as seen from valuation perspective Renewable energy market, mainly comprised of wind, solar and hydro, is a capital intensive technology where operating and maintenance costs are lower compared to conventional power plants as they carry zero fuel cost. Since the cost of owning and operating a wind farm is known in advance it is much easier to reduce the level of uncertainty as to the exploitation of the technology. From the moment the wind farm is financed and commissioned capital costs such as depreciation and interest rate are easily accountable, thus a power supplier is aware of the future costs. O&M costs are a major part of total power generation costs for thermal power plants. Because wind power reduces the cost assessment due to low O&M costs it could be graded as low-risk technology. Conventional power plants have a one great disadvantage they are dependent on fuel input which is highly susceptible to price variations and which in turn increases the level of uncertainty. As thermal power plants are expense-intensive technologies they incur high O&M costs. Many governments including the European Commission have been using the conventional engineering-economics analysis of costs XXIV to reduce the level of uncertainty. As mentioned before, it is difficult to forecast oil or gas prices due to their high price fluctuation. However, it possible to forecast the development of oil and gas prices by taking into consideration their statistical mean. Unfortunately, future predicted mean of oil or gas prices is as good as cost calculation for simplified cost model analysis. A comparison of gas-fired power plants and wind farms shows that the incurred costs over time is different and in order to discount all of the costs to the same point in time interest rate on debt would have to be used in the calculations. Futures contracts for oil and gas prices could be bought as insurance for monthly fuel bills the same way wind power generation can be insured by estimating likely power output on an annual or season basis. Nevertheless, in reality oil and gas prices are usually influenced by speculation which doesn’t help stabilize the prices for oil and gas futures contracts. Long-term futures markets do not exist as there are great risks for both parties that agree to sign a fossil-fuel contract delivery for 10 or even 15 years into the future. Fuel prices are too

Engineering economic analysis focuses on costs, revenues, and benefits that occur at different times. Engineers try to compromise and find the most viable solution to the economic and technical aspects of the project.

XXIV

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unpredictable to allow for such a contract to be signed. It is difficult to extract reliable outcome from engineering-economics cost analysis as it fails to include the vital factor of fuel price fluctuations. Financial markets possess economic instruments such as futures markets for stocks and bonds that help reduce the risk which fossil fuel market is exposed to. Interestingly, bond investors are more inclined to purchase bonds that pay low but secure and predictable income (government bonds) rather than junk bonds carrying a higher interest rate that generates higher yet more unpredictable coupon payments. If the same point of view is applied to investors interested in the power market they should opt for investment is power plants with lower but predictable rate of return in contrast to power plants with higher but unpredictable rate of return. It is essential to apply the discount rate factor accordingly to the risk involved. A higher discount rate should be used for unpredictable income than for predictable income and a lower discount rate should be used for unpredictable expenditures than for predictable. The discounts rates that are used in this analysis were chosen randomly and intend to give an objective overview of the impact of selecting a discount rate to value proceeds from bonds. Currently, many institutions including the European Commission use the same single discount rate to calculate all future expenditures. They assume riskless and predictable fuel prices and as a result fuel prices are given too high rate of discount that leads to their cost underestimation and viewing them as a more secure capital expenditure. The assumptions used in the following calculation favor expenditure-intensive, fossil-fuel driven power plants rather than capitalintensive, zero-fuel risk and environment-friendly renewable energy such as wind power.

6.1 Impact of risk-adjusted factors on the choice of energy development projects An engineering cost model assumes that thermal power plants with unpredictable fossil fuel prices are more cost-effective than low-risk renewables with zero fuel cost because risky bonds that yield a higher coupon rate are more profitable than bonds with low yield even though the latter is a safe and predictable government bond. For instance, as seen from Table 6.1 there are two bond investment alternatives; junk bond with an interest rate that pays 10% and a government bond with an interest rate that pays 5%. The example assumes an investment of €1,000 in each of the bonds. The junk bond produces an

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annual coupon of €100 whereas the government bond generates €50. Clearly, in order to obtain the same payout as from a junk bond one would have to invest €2,000 in a government bond as its interest rate is half of that of a junk bond (€2,000 * 4% = €100). If the principles of the engineering cost model are used to compare both of the bond investments to the conventional and renewable power utilities, it can be concluded that government bonds bear twice as high cost as junk bonds or to put it simply one would need to double the investment in government bonds to achieve the same expected profit as from a junk bond. However, it must be noted that government bonds in spite of their lower interest rate trade at roughly the same cost as junk bonds. Since investors are fully aware of the risks involved in trading junk bonds the cost disparity between the two is diminished. That is the reason why the diversification of power market with increasing share of renewables should take into account aforementioned notions when wind energy is weighted against thermal power plants such as natural gas and coal. Table 6.1: Valuing two 8-year bond investments

Source: Author Before the technological development towards promotion of capital-intensive renewable technologies engineering cost models were applied on a regular basis to evaluate projects for power plants construction. Since gas-fired, coal-fired and liquid-fired power plants have closely related financial characteristics, capital investment and operating expenses over their lifetime are similar and the environment presents a stable technology. After the renewable energy has been prioritized in power generation in order to reduce greenhouse gas emissions and considering the unpredictable natural gas and oil prices the engineering cost model has become outdated. At the

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moment energy projects take into account a wide range of alternatives such as high and low economic growth, high and low fossil fuel prices, capital-intensive wind power with high, medium and low wind speed. On the other hand there are other models such as market-based or financial economics approach that are becoming more widely used than engineering cost model. Both approaches use discount rate in order to find the present value of expected future cash flows from a given power generating technology. However, it must be noted that from financial point of view the present value shows the market value of future stream that can be either positive or negative which means that they either contribute to profits or losses. As can be seen from Table 6.1 both the junk bond and the government bond are shown with their respective annual interest rates and coupon payments. In order to generate the most accurate result a proper discount rate factor must be chosen. If we consider scenario A with assumed discount rate of 7.5% it can be clearly seen that present value of the proceeds from the junk bond is greater than from the government bond which is a mistake because no risk is accounted for. Given the fact that the market from junk bonds has grown greatly in the last few decades many of them trade slightly above government bonds that carry much lower interest rate as the level of risk regarding the cash flows from both types of bond is different. Thus, it is vital to select the best applicable discount rate since the bonds are attached with different risk factors that influence the present value of future cash flows. Scenario B in Table 6.1 presents that the correct present value of the bonds can be obtained only by applying the riskadjusted discount rate which in this case is 10% for the junk bond and 5% for the government bond. Only then is the current value of future coupon payments and principal amount correct. Discounting both investments at the same rate produces the outcome that mistakenly shows that the proceeds from junk bond are worth more than from the government bond. Unfortunately, such events occur in reality when the costs of power generation between wind and other conventional technologies are applied with the same discount rate factor that ignores the level of risk. Interestingly, if the financial markets considered the same range of factors as energy investors do, the government bonds would be in a very low demand unless the interest rate would increase due to economic crisis or unstable political control.

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7.0 Conclusion The perception of energy security in Europe encapsulates a broad scope of issues concerning foremost energy efficiency, diversification of energy supply, better transparency of energy demand and supply, harmony among the EU member states, amicable external relations with business partners and improved grid infrastructure. The aspect of energy security concerning fuel imports and the following dependence growing from decreasing or lack of own resources, influences the environment greatly. The choice of fuel mix used to generate power, the increasing demand in particular energy sectors and the speed with which these alternations have to be delivered defines and shapes a new emerging energy consumption market. The ongoing changing preference for use of various fuels for power generation brings mostly positive transformation in the environment. A good example of such change is Europe where there can be observed a high penetration of renewable energy sources and also a switch from so far dominant coal to gas. Not only did it result an immediate decrease in carbon dioxide emissions but also an increased dependency from natural gas reserves. At the present moment the EU is still mostly dependant on coal-fired power generation that contributes to 30% of total production where natural gas and nuclear energy have a share of 25% each. However, this is about to change. The European Union strives to reach an average of 30% of electricity generation from renewables and it will be followed by natural gas, nuclear and coal plants. In order to create a common single electricity market with even competition it is essential to construct an organized and well-interconnected power system in Europe. Without any doubt transmission and grid infrastructure need to be reinforced and expended for the European consumers to reap the benefits from aggregation of greater amounts of wind energy. Nevertheless, not only must these adjustments be done to ease the entrance of wind power into the electricity market, but also to join other energy sources so that dynamically growing power demand and trade flows in Europe are met. It is also important that the financing issues of grid inter-connection should be applied to the extended framework of electricity market development so that the benefits of grid-reinforcement are not attributed to individual technologies or projects. Grid infrastructure projects are regarded

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as natural monopolies and are beneficial to both producers and consumers alike and, therefore, their costs and benefits need to be socialized. A critical factor of climate change policy is to increase investments in technologies that generate electricity with no greenhouse gas emissions. In the past several years, renewables especially wind energy, have reported a sharp increase in capital inflow. However, in order to facilitate development of large-scale wind installations more investment must be delivered to transmission lines and power grids to ensure the efficiency of the power system. With the help of transparent regulatory energy framework, the risk or rejecting or postponing indefinitely an investment proposal, especially for capital-intensive high risk projects is minimized. The benefits from it would be unambiguous and more stable market with long-term prognostic concerning the future policy guidance for climate change abatement. In 2005 the European Union launched Emission Trading Scheme (ETS), a market-based instrument, in order to encourage and increase investments into ‘green technologies’. By setting a price on CO2 emissions the EU Environmental Commission has turned a policy factor into a quantifiable factor that can be included in the process of investment project evaluation. Carbonintensive power generators and major energy-intensive businesses incur higher production costs due to CO2 allowances which present an incentive to reduce reliance on fossil fuels and pursue power generation from renewables. It is essential that energy investors make the right decision as to the type of technology they are planning to undertake since it will bear significant ramifications for the power system and security of supplies. Taking into consideration levelized cost of electricity generation it assists in preparing diversified generation portfolio by determining cost-efficient technologies and assessing the expected level of investment needed to fulfill the consumer demand. Naturally, investors opt for investment in the type of technology that is most requisite to market requirements.

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8.0 List of literature 1. European Energy Administration, "Europe's onshore and offshore wind energy potential. An assessment of environmental and economic constraints", June 2009. 2. European Energy Administration, "Greenhouse gas emission trends and projections in Europe 2009. Tracking progress towards Kyoto targets", September 2009. 3. European Energy Administration, "The European Environment; State and Outlook 2010", Synthesis 2010. 4. European Energy Administration, "Tracking progress towards Kyoto and 2020 targets in Europe", July 2010. 5. Energy Information Administration, "International Energy Outlook", July 2010. 6. Eurostat, "Energy, transport and environment indicators", 2010. 7. Eurostat, "Europe in figures", Eurostat yearbook 2010. 8. Eurostat, "Sustainable development in the European Union", 2009 monitoring report of the EU sustainable development strategy. 9. European Wind Energy Association, "Powering Europe: wind energy and the electricity grid", November 2010. 10. European Wind Energy Association, "The European offshore wind industry key trends and statistics 2010", January 2011. 11. European Wind Energy Association, "Wind Energy and Electricity Prices; Exploring the 'merit-order effect", April 2010. 12. Global Wind Energy Council, "Global Wind Report", Annual market update 2010. 13. Global Wind Energy Council, "Global wind energy outlook 2010", October 2010. 14. International Energy Agency, "CO2 Allowance & Electricity Price Interaction; Impact on industry’s electricity purchasing strategies in Europe", February 2007. 15. International Energy Agency, "CO2 Emissions from Fuel Combustion, Highlights", 2010 16. International Energy Agency, "Energy Technology Initiatives", 2010. 17. International Energy Agency, "Projected Costs of Generating Electricity", 2010. 18. International Energy Agency, "Technology Roadmap; Wind energy", 2009.

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Internet resources: http://www.wind-industry-germany.com/en/facts/world-market/ http://www.wind-energy-the-facts.org/en/part-4-industry--markets/chapter-4-global-windenergy-markets/ http://www.mnforsustain.org/windpower_schleede_costs_of_electricity.htm http://zeroemissionproject.com/blog/article/15/how-much-does-a-wind-farm-cost http://www.windenergyleases.blogspot.com/ http://www.eurotrib.com/story/2009/5/1/174635/6513 http://www.bloomberg.com/news/2011-03-14/eu-may-need-tighter-supply-to-avoid-co2-slumpadviser-says-1-.html http://randomspaniard.blogspot.com/2009/06/co2-prices-eua-price-vs-implied-fuel.html http://www.wind-works.org/articles/feed_laws.html

9.0 List of endnotes 1

“Power and Steam Outlook for the EU”, European energy and transport: Trends to 2030 – update 2007 (2008), p.58-70. 2 European Wind Energy Association, "Wind in power; 2010 European statistics", February 2011. 3 “Sensitivity analyses in IEO2010”, International Energy Outlook (2010), p.20. 4 Energy Information Administration, ”International Energy Outlook 2008”, p.237. 5 Energy Information Administration, “International Energy Outlook (2010), Chapter 6: Electricity”, p. 77-83 6 European Parliament, “EU Climate and Energy Policy”, December 2008, www.ec.europa.eu/climateaction/docs/climate-energy_summary_en.pdf. 7 European Wind Energy Association, ‘Wind in power, 2010 European statistics’, February 2011 8 ELECTRONICS.CA PUBLICATIONS, “Global Market for Renewable Energy”, November 2010. 9 Stephens J. ‘The Value of a Wind Energy Land Association’, December 2009, www.windenergyleases.blogspot.com

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10

European Wind Energy Association, ”Wind Energy Fact Sheet: Wind Energy and Economic Development: Building Sustainable Jobs and Communities”, www.ewea.org/pubs/factsheets/EconDev.PDF 11 American Wind Energy Association, “Wind Energy Facts & Myths: Expensive and Unreliable,” www.ifnotwind.org/myths/mythexpensive.shtml 12 http://en.wikipedia.org/wiki/Wind_turbine_design 13 European Wind Energy Association, ‘Powering Europe: wind energy and the electricity grid’, November 2010, p.16. 14 American Wind Energy Association, ”Wind Energy 101: Potential” www.ifnotwind.org/we101/wind-energy-potential.shtml. 15 European Wind Energy Association, ”Wind in Power, 2010 European Statistics”, February 2011. 16 European Wind Energy Association, “The Economics of Wind Energy”, March 2009 17 European Wind Energy Association, “The Economics of Wind Energy”, March 2009, p. 9 18 EWEA, ‘Powering Europe: wind energy and the electricity grid’, November 2010. 19 James Murray, "Global carbon market expanded 68 per cent in 2009", BusinessGreen, 7 January 2010, http://www.businessgreen.com/bg/news/1805722/global-carbon-marketexpanded-68-cent-2009. 20 The International Exchange, Inc. https://www.theice.com/about.jhtml 21 Catherine Airlie, "EU May Need Tighter Supply to Avoid CO2 Slump, Adviser Says", Bloomberg.com. 14 May 2011, http://preview.bloomberg.com/news/2011-03-14/eu-may-needtighter-supply-to-avoid-co2-slump-adviser-says-1-.html 22 Mathew Carr and Saijel Kishan, “Europe Fails Kyoto Standards as Trading Scheme Helps Polluters,” Bloomberg.com, 16 July 2006, http://www.bloomberg.com/apps/news?pid=20601087&sid=awS1xfKpVRs8&refer=home. 23 Vertis, "EU ETS is short – Companies need CERs for compliance", http://www.vertisfinance.com/index.php?page=news&newsid=89&l=1

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Appendix A Table 1: OECD Europe Total Primary Energy Consumption, 2005-2035

Table 2: OECD Europe electricity generation from central producers by energy resource, 2007-2035 (Billion kilowatt-hours)

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Table 3: Table Delivered energy consumption in OECD Europe by end-use sector and fuel, 2007-2035 (Petajoules)

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Table 4: Average amount in euro per one kilowatt-hour of electricity for household consumers. Incl. Energy taxes & VAT.

Source: www.energy.eu

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Table 5: Average amount in euro per one kilowatt-hour of electricity for industrial consumers. Incl. Energy taxes & VAT.

Source: www.energy.eu

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Table 6: Feed-in tariffs in the European Union

Source: www.energy.eu

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Appendix B Table 7: The cost of power generation from wind energy in comparison to other renewables plants

Source: ‘Projected Costs of Generating Electricity’ 2010.

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