DEGREE PROJECT IN MECHANICAL ENGINEERING, SECOND CYCLE, 30 CREDITS STOCKHOLM, SWEDEN 2020

Renewable energy outlook for the River Basin countries

EMIR FEJZIC

KTH ROYAL INSTITUTE OF TECHNOLOGY SCHOOL OF INDUSTRIAL ENGINEERING AND MANAGEMENT

Master of Science Thesis EGI 2018:2020

TRITA-ITM-EX 2020:69 outlook for the Drina River Basin countries

Emir Fejzić

Approved Examiner Supervisor

27.03.2020 Francesco Fuso Nerini Youssef Almulla Commissioner Contact person

Abstract The Drina River Basin (DRB) plays a vital role for the power sectors of the riparian countries of and Herzegovina, and . The Drina river and its tributaries have a considerable hydropower potential, which, due to its geographical position and the political landscape between the riparian countries, have not yet been utilized to its full potential. This study aims to investigate the role of hydropower and other renewables in the future energy mix under different scenarios. Additionally, the study aims to examine the renewable energy penetration within the DRB, as well as changes in total CO2eq emissions from the power sector by 2035. The study describes the implementation and testing of a modelling framework with the purpose of analysing the future energy mix. To answer the key research questions, an energy model was created using the Open Source Energy Modelling System (OSeMOSYS). Input parameters for the model were obtained through information gathering based on literature reviews, interviews with local experts and reviews of policy documents. The scenario analysis includes a business as usual scenario (BAU), a nationally determined contribution scenario (NDC), renewable energy scenario (RE) and a sensitivity analysis based on three different levels of implementation of the emission trading scheme (ETS). The results indicate that the share of hydropower differ amongst the scenarios, ranging between 41% and 55% by 2035. The scenario results also show that the share of RES located within the DRB ranges between 45-58% by 2035, in relation to the total installed RES capacity in the basin countries. This high share of economically feasible RES potential highlights the importance of the DRB, particularly since the basin area accounts for approximately 12,8% of the total country area. Furthermore, the obtained results from the scenario analysis indicate the possibility of emission reductions between 7% and 50 % by 2035, compared to the BAU scenario emissions.

Keywords: OSeMOSYS; Drina River Basin; Hydropower Sammanfattning Flodområdet Drina (DRB) spelar en central roll för kraftsektorerna i de angränsande länderna Bosnien och Hercegovina, Montenegro och Serbien. Drinafloden och dess bifloder har en betydande vattenkraftpotential som, på grund av dess geografiska position och komplexa politiska landskap, inte har utnyttjats till fullo. Denna studie syftar till att undersöka förnybara energikällors roll i den framtida energimixen, under olika scenarion, med fokus på vattenkraft. Studien ämnar fortsättningsvis att undersöka penetrationen av förnybar energi inom DRB, såväl som förändringar i de totala CO2-utsläppen från kraftsektorn, fram till år 2035. Vidare beskriver studien implementeringen och testningen av en modelleringsram framtagen med syftet att analysera den framtida energimixen. För att besvara forskningsfrågorna skapades en energimodell med hjälp av Open Source Energy Modelling System (OSeMOSYS). Inmatningsparametrar för modellen erhölls genom informationsinsamling baserad på litteraturgranskningar, intervjuer med lokala experter samt granskningar av nationella policydokument. Scenarioanalysen inkluderar ett Business as Usual scenario (BAU), ett Nationally Determined Contribution scenario (NDC), ett scenario för Renewable Energy (RE) samt en känslighetsanalys baserad på tre olika nivåer för implementering av systemet för utsläppshandel (ETS). Resultaten indikerar på att andelen vattenkraft skiljer sig mellan scenariona och sträcker sig mellan ett intervall på 41% och 55% år 2035. Scenarioresultaten påvisar även att andelen RES som ligger inom DRB varierar mellan 45–58% fram till 2035, i förhållande till den totala installerade RES-kapaciteten inom de angränsande länderna. Den höga andelen ekonomiskt genomförbar RES-potential belyser betydelsen av DRB-området, framför allt då flodområdet utgör cirka 12,8% av det totala landområdet. Vidare indikerar resultaten från scenarioanalysen möjligheten till utsläppsminskningar på mellan 7% och 50% fram till 2035, jämfört med utsläpp indikerade i BAU-scenariot. Nyckelord: OSeMOSYS; Drina River Basin; Vattenkraft

Contents

1. Introduction ...... 5 1.1 Energy Sector in ...... 7 1.2 Energy Sector in Montenegro...... 15 1.3 Energy Sector in Serbia ...... 20 1.4 Energy trade between the riparian countries ...... 24 1.5 Aim and Objectives ...... 27 2. Methodology ...... 28 2.1 Short description of OSeMOSYS ...... 28 2.2 Scenario definition and key assumptions ...... 28 3. Model Results and Discussion ...... 30 4. Conclusion ...... 41 5. Limitations and Future work ...... 42 6. References ...... 43 7. Appendix ...... 52

List of figures Figure 1: The hydrographic network of the Drina River Basin Figure 2: Installed capacity by technology type in the riparian countries in 2018 Figure 3: Total power production by source in BiH 2008-2018 Figure 4: Photovoltaic power potential in Bosnia and Herzegovina Figure 5: Monthly max and min hourly loads in BIH 2017 Figure 6: Monthly max and min daily loads in BIH 2017 Figure 7: Yearly production and consumption of electricity in BiH Figure 8: Electricity consumption on the transmission network by utility in BIH 2014-2018 Figure 9: (Left) Photovoltaic power potential in Montenegro (Right) The energy potential of [W/m2] at 50 m AGL Figure 10: Projected monthly peak load for the period 2020-2022 in Montenegro Figure 11: Total electricity demand by consumer type in Montenegro 2012-2018 Figure 12: Wind (left) and Solar (right) potential in Serbia Figure 13: Average electricity trade (GWh) between 2014-2018 between the riparian countries Figure 14: ENTSO-E Continental South East Region Figure 15: Illustration of Net Transfer Capacities in CSE region (2013) Figure 16: Reference Energy System representing the OSeMOSYS model Figure 17: Power production by technology type for all scenarios – Bosnia and Herzegovina

Figure 18: CO2eq emissions from the power sector in Bosnia and Herzegovina Figure 19: Power production by technology type for all scenarios– Montenegro

Figure 20: CO2eq emissions from the power sector in Montenegro Figure 21: Power production by technology type for all scenarios - Serbia

Figure 22: CO2eq emissions from the power sector in Serbia Figure 23: Total emission reductions per scenario compared to the BAU in 2035 Figure 24 – Share of RES located within the DRB in relation to total installed RES capacity Figure 25: Average annual electricity imports to Bosnia and Herzegovina Figure 26: Average annual electricity imports to Montenegro Figure 27: Average annual electricity imports to Serbia

1. Introduction Two merging rivers, and , form the Drina river at Šćepan Polje at an altitude of 434 m AMSL. The river basin covers an area of 19 226 km2, as illustrated in figure 1 below. The Drina River Basin (DRB) is located within the borders of Bosnia and Herzegovina, Montenegro and Serbia and amounts to one fifth of the River Basin from an area perspective. One third of the Sava river water comes from the Drina river. The most water abundant tributaries of the Drina river originate in Montenegro. The rivers Piva, Tara and provide two thirds of the Drina river water.

Figure 1: The hydrographic network of the Drina River Basin (World Bank Group, 2017) The three administrative units shown in figure 1 consist of areas located in Bosnia and Herzegovina (36%), Serbia (34%) and Montenegro (30%). While the areas are evenly distributed between the riparian countries, the population is not. Due to differences in population density within the administrative areas, 47% of the DRB population lives in Serbia, 39% in Bosnia and Herzegovina and only 14% in Montenegro (World Bank Group, 2017). Constructions of several water reservoirs within the DRB has led to changes in the natural regime of the river which has been significantly altered. The river has become more uniform, and today, one third of the river has been converted into lakes. The economically viable hydropower potential of the river is 14,4 TWh, and as of 2013, only 35% of that potential is utilized (JP Elektroprivreda BiH, 2013). This untapped power potential indicates the importance of the Drina river for the riparian countries. In recent years, projects aiming at enhancing the interconnectivity between the European Union (EU) and the Western Balkans have been conducted. One significant project is the interconnector between Italy and Montenegro. The interconnector will assist in lowering the price difference between South Eastern and Italy. In addition to this, the project aims to decrease system adequacy deficiencies, as well as promoting integration of renewables (European Commission, 2019a). Figure 2 illustrates the total installed capacity by technology type in the riparian countries as of 2018. A detailed list of the power plants included in this graph are shown in the appendix.

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Figure 2 – Installed capacity by technology type in the riparian countries in 2018 It can be observed that thermal power plants account for 50% of the total installed capacity in the DRB countries, indicating a large dependency on coal to meet the power demand. Hydropower accounts for 91,6% of the installed RES capacity, while solar power plants are absent from the installed capacity mix in each country. Wind power additions are present, with the largest instalments found in Serbia. The Drina basin countries were identified as potential candidates for EU membership in 2003 during the Thessaloniki European Council summit. As of 2019, they have the status of Contracting Parties. In March 2012, Serbia was granted an EU candidate status. In September 2013, a Stabilisation and Association Agreement between the EU and Serbia entered into force (European Commission, 2019c). In February 2016, Bosnia and Herzegovina submitted their application for EU membership (EU Delegation to BIH, 2019). Montenegro’s parliament declared independence from the State Union of Serbia and Montenegro in 2006. Two years later, in 2008, they applied for EU membership. As of June 2012, the accession negotiations between Montenegro and the EU has commenced (European Commission, 2019b). The following sections of the introduction chapter aims to inform the reader about the current situation within the power sector in the riparian countries of the DRB. Energy production, technologies used and power potentials within the countries are described, as well as current policies regarding the power sector. Trading patterns and cross border collaboration are also highlighted in the introduction.

1.1 Energy Sector in Bosnia and Herzegovina Since Bosnia and Herzegovina is divided into two entities, the Federation of Bosnia and Herzegovina (FBIH) and (RS), together with a third district under the name of Brčko District, the governance of the electricity production, its distribution system operation and supply of energy is split between these three. The Federation Ministry of Energy, Mining and Industry is the main institution in the FBIH, together with the Federation Electricity Regulatory Commission (FERC). The electricity sector in FBIH is governed by the Law on Electricity, which was adopted in 2013. Electricity distribution together with the bigger part of the power generation and supply, is carried out by Elektroprivreda Bosne i Hercegovine (EPBIH) and Elektroprivreda Hrvatske Zajednice Herceg-Bosne (EPHZHB). These two companies are vertically integrated with their own separated territories in which they operate. The key institutions in Republika Srpska are the Ministry of Industry, Energy and Mining, together with the Republika Srpska Energy Regulatory Commission (RSERC). The electricity sector in Republika Srpska is, however, not governed by the same laws, building its governance on the Law of Electricity adopted in 2008, together with the Energy Law that was introduced in 2009. Elektroprivreda Republike Srpske (EPRS) is the Republika Srpska equivalent to the EPBIH and EPHZHB in FBIH. They own five subsidiaries for electricity generation, together with five distribution and supply companies. For the Brčko District, the main communal utility is the Komunalno Brčko (KB). This utility is the provider of electricity for all customers in the Brčko District, and it has the responsibility for operation of the distribution network (USAID EIA, 2019) The above stated ministries work under the Ministry of Foreign Trade and Economic Relations of BiH. Their responsibilities include defining policies as well as coordinating the FBIH and RS entity authorities and institutions. Additionally, they are responsible for creating plans on an international level, where questions regarding the energy sector and environmental protection are covered. The goal set by the Energy Community is to create a market space with a single regulatory framework with the purpose of attracting much needed investments, which would increase the access of stable energy supply. From an international commitment perspective, BiH is mostly contained in the Energy Community Treaty with regard to the energy sector (USAID EIA, 2019). Figure 3 below illustrates the power production in Bosnia and Herzegovina during the period of 2008 to 2018. It indicates the dependence on coal fired thermal power plants, as well as the importance of hydropower as a renewable energy resource. Volatility in the power production, as presented in figure 3, depends on water availability for hydropower plants. When water is available, the power production ramps up, since any power excess is exported to neighbouring countries, especially Croatia and Montenegro. For this reason, the power production graph does not follow the power demand of Bosnia and Herzegovina. 20000 18000 16000 14000 12000 10000 GWh 8000 6000 4000 2000 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Hydropower Plants Thermal Power Plants Wind Power Plants

Figure 3. Total power production by source in BiH 2008-2018 (NOS BIH, 2019) 1.1.1 Energy Policies in Bosnia and Herzegovina On October 8th, 2015, Bosnia and Herzegovina submitted their first Climate Action Plan in their Intended Nationally Determined Contribution (INDC) to the UN Framework Convention on Climate Change (UNFCCC, 2015a). According to the INDC, BiH levels of greenhouse gas (GHG) emissions will reach the 1990 levels in 2020, based on scenarios developed through the Second National Communication (SNC) and First Biennial Unit Report (FBUR) under the UNFCCC convention. If provided with access to international support or development financial mechanisms, the countries GHG emissions could be 3% lower in 2030 compared to 1990 levels. If this condition is not fulfilled, the emissions will rise with 20% in 2030 compared to 1990 (Government of Bosnia and Herzegovina, 2015). In order to decrease their dependency on fossil fuels, Bosnia and Herzegovina has presented their plan for investments in the power sector in their Indicative Production Development Plan 2020-2029. It includes 133,5 MW of new wind power and 240 MW of new hydropower. The total new Renewable Energy Sources (RES) capacity in the period between 2020 and 2029 will amount to 373,5 MW if all the projects are implemented within the given timeframe. The planned increase in RES is relatively small in comparison to the planned new thermal power capacity. New plants in Tuzla, Kakanj and Zenica will add approximately 1100 MW of coal fired thermal power. New thermal power plants (TPPs) will replace three existing units in Tuzla, as well as two in Kakanj (NOSBiH, 2019). In its NDC, BiH has announced to commission small hydropower plants up until 2030, the size of which would be less than 10 MW each, with a total capacity of 120 MW (International Hydropower Association, 2016). It can be observed that the Indicative Production Development Plan includes new hydropower capacity additions that are twice as high compared to the INDC. Additional pledges in the NDC are replacements of existing thermal power plants, which currently have an average efficiency of 25-31%. New modern TPPs will have an efficiency of approximately 40%. Installation of wind power plants will also be required, and the INDC projects a power generation capacity from wind power of 175 MW by 2030. Solar photovoltaic (Solar PV) will, according to the determined contribution, account for only 4 MW of installed power generation capacity in 2030 (Government of Bosnia and Herzegovina, 2015). It should be noted that the Solar PV additions pledged in the INDC are not a part of the Production Development Plan. Being an EU candidate since 2008, BiH strives to comply with EU regulations in order to achieve a membership status. By doing so, BiH would also need to follow the regulations regarding CO2 emissions. In order to reflect the price of electricity (in this case without cross- subsidisation) including the cost of CO2 emissions associated with the EU’s emission trading scheme (ETS), the price of electricity for households would increase with 58% in Bosnia and Herzegovina (Kopač, 2019). 1.1.2 Thermal Power Plants in Bosnia and Herzegovina There are four thermal power plants in Bosnia and Herzegovina. Ugljevik and Gacko are thermal power plants owned by Elektroprivreda Republike Srpske (ERS), while Kakanj and Tuzla are owned by Elektroprivreda Bosne i Hercegovine (EPBIH). All four plants are characterized by a low energy efficiency, since they require between 11 500 and 14 500 kJ of heat from the fuel in order to produce one kWh of electricity. This gives an overall energy efficiency between 25 and 31% (Centar za istraživačko novinarstvo, 2015b). Their installed capacity and power production are stated in the appendix table A1. The average age of the thermal power plants in Bosnia and Herzegovina was 39 years in 2016, which indicates the need of investments for reconstructions, and possibly even shutdowns in the upcoming years (Čuta J. Galop P., 2016). According to the Europe Beyond Coal campaign, that published the Chronic Coal Pollution th Report on February 19 , 2019, the Ugljevik thermal power plant emits more SO2 than all the German thermal power plants combined. Tuzla, Kakanj and Ugljevik are among the top 10 most polluting power plants in Europe with regards to SO2 emissions, while Gacko ranks as the second most polluting plant in Europe considering PM10 in 2016. Emissions from the above stated power plants have a considerable impact on people’s health not only in Bosnia and Herzegovina, but also in the whole of the Western Balkans and large parts of Europe. It is estimated that the pollutants cause premature deaths for 3906 people in 2016 alone (Health and Environment Alliance, 2019). Statistics shown in the Chronic Coal Pollution Report clearly indicate the need to step away from old and unsatisfactory coal power plants that are currently active across the whole region of the Western Balkans. Information provided in the report regarding Ugljevik’s problems with SO2 emissions are known by authorities in BiH. Projects concerning reduction in SO2 emissions were planned even before the war in the early 1990’s. Due to the given circumstances the projects were delayed, but with a loan from the Japan State Agency, a project of lowering the SO2 emissions from the plant was initialised, and the reconstruction is planned to be finalized in December 2019. The total cost for this project was estimated to 80 million euros, and the new levels of SO2 per nominal cubic meter will be in the range of 25 to 30 mg, which is well below the 50 mg requirement limit (Šurlan S, 2019). A study performed by the European Energy Agency (EEA) indicates scepticism towards the feasibility of the investment. EEA has previously stated that the RiTE Ugljevik plant will have to shut down by 2025 if no major investments are made to the power plant facility. However, optimistic views within the institutions of Republika Srpska claim that the power plant will be active until 2039 (Centar za istraživačko novinarstvo, 2015b) According to NOSBIH, the EPBIH has announced the shutdown the units 3, 4 and 5 in their old thermal power plants in Tuzla. Unit 3 will shut down in 2023, followed by unit 4 in 2024 and finally unit 5 in 2027. They will be replaced by two new units, 7 and 8, which will be commissioned in 2022 and 2024 respectively (NOSBiH, 2018). 1.1.3 Planned Thermal Power Plants in Bosnia and Herzegovina Thermal power plants are, as previously mentioned, reaching the end of their operational life, and the need for new TPPs is significant. Appendix table A2 lists all planned TPPs in Bosnia and Herzegovina, their installed capacities and planned electricity production. The planned year of commission indicates that the majority of the planned TPPs are already behind their schedule. The Gacko II thermal power plant has been announced, but no specific commission date has been communicated. The construction of unit 7 (450MW) in Tuzla was planned to start in September 2018, and the construction time was planned to be 56 months (commission in 2023) (Salkić, 2018). However, the process got delayed and in November 2019, local companies responsible for preparing the area where the new unit 7 will be built started their 12-month working period, prior to giving the Chinese contractor (China Gezhouba Group Company Limited Peking and Gedi - Guandong Electric Power Design Institute) a green light to start the construction. Unit 7 will be connected to the grid by the end of 2024 or the beginning of 2025, according to Dr Senad Salkić. The planned yearly production will be 2756 GWh and the cost of the project is estimated to 750 million euro (Al Jazeera Balkans, 2019). 1.1.4 Coal production and coal reserves in Bosnia and Herzegovina The endogenous coal production in BiH is of great importance since a large share of the electricity production comes from thermal power plants. The production is vital for the energy security of the country due to major deposits of brown coal and lignite. Mining of coal in BiH is conducted with small financial gains, usually at breakeven or even with losses. Active mines in the FBIH are operating to a high extent to satisfy the demand of the EPBIH. For the entity of Republika Srpska, the coal goes towards supplying the Gacko and Ugljevik thermal power plants owned and operated by Elektroprivreda Republike Srpske (ERS). Coal mines in BiH can be divided into two types, brown coal and lignite. The IEA does not make this differentiation in their methodology, and they are therefore only referring to the coal produced as lignite. Lignite mines in BiH are located in the following areas: , Duvno, Gatsko, Livno, Kreka and Stanari. Brown coal comes predominately from the three big mines located in Banovići, Djurdjevik and Ugljevik. In addition to these there are also smaller mines in Kakanj, Kamengrad and Zenica. For all of the above mentioned mines, surface mining is the main activity, but due to limitations in the surface mining it should be pointed out that there is a need for underground mining in order to supply the TPPs in the future. Coal demand is regulated by the demand of thermal power plants since 90 % of the produced coal is used for power production (Granić G. et. al., 2008b). The Federal Ministry of Energy, Mining and Industry released data in their FBIH Energy Sector Strategic Plan and Program, which indicates that the market reserves of coal in Bosnia and Herzegovina are 327 million tons. In Republika Srpska, this number amounts to 578 million tons, of which lignite accounts for 353 and brown coal 225 million tons (Centar za istraživačko novinarstvo, 2015b). 1.1.5 Oil production and oil reserves in Bosnia and Herzegovina Since 1990, the Energoinvest-Energonafta Bosanski Brod has been the only oil producing company in BiH (Granić G. et. al., 2008b). According to the International Energy Agency, the production of oil in BiH amounted to 1720 ktoe in 2017 (IEA, 2019). A study conducted, with support from the World Bank in the form of a 2.5 million USD loan called “North Bosnia Project”, found that the total oil reserves in the country amount to approximately 355 million barrels, which is equal to 50 million tons of crude oil. Stated in the report is also the fact that between 1963 and 1991 there were extensive oil and geological explorations carried out in BiH, but that all activities ceased in 1992 with the outbreak of the war (Granić G. et. al., 2008a). 1.1.6 Hydropower Plants in Bosnia and Herzegovina The riparian countries of the DRB are all located in the Western Balkan region. This region has the largest remaining unexploited hydropower potential in Europe. Bosnia and Hercegovina, being one of the countries, produces 41 % of its domestically produced electricity from hydropower (International Hydropower Association, 2016). Rivers with a technically utilizable large hydropower plants (HPPs) production are the , Cetina, Drina, Liđtica, , , and rivers (Granić G. et. al., 2008b). Bosnia and Herzegovina currently has a 2100 MW installed hydropower capacity, and a potential of over 6000 MW. Small HPPs have a power production potential of 1813 GWh, with 313 being in FBIH and 1500 in Republika Srpska (Granić G. et. al., 2008a). Despite the vast potential in this region, a lack of financing in combination with concerns regarding the environment have stalled the development of new hydropower plants (International Hydropower Association, 2016). All currently installed and planned hydropower plants are listed in appendix table A3 and A4. 1.1.7 Other Renewable Power Sources in Bosnia and Herzegovina According to the most recent report from 2017 published by IRENA, Cost-competitive renewable power generation: Potential across South East Europe, Bosnia and Herzegovina has a considerable technical potential for renewable energy. The cost-competitive hydropower potential in BiH has been estimated to 2510 MW, solar power 993,5 MW and wind power ranging from 2556 MW to 5861 MW. Therefore, further exploitation of renewable energy sources in the upcoming years will, to a great extent, depend on price reductions of certain technologies, incentive mechanisms, administrative barriers during obtaining permits, et cetera. Although Bosnia and Herzegovina has a good position from the perspective of the natural resources themselves, additional strategic planning need to be conducted to update data on the potential for their further exploitation, especially in the hydropower segment (Government of Bosnia and Herzegovina, 2019). As of today, only one wind power park has been built. In addition to this, there are 21 planned wind power plants (WPPs), with most of them located in western Herzegovina. The total capacity of the current and planned wind power in BiH is approximately 1695 MW. Appendix table A5 shows the constructed and planned WPPs. Figure 4 below illustrates the solar photovoltaic power potential in BiH based on the long-term average of PVOUT in the period of 1994-2018. The solar potential of the DRB within BiH is low compared to the regions of Herzegovina in southern BiH. The largest wind power potentials can also be found in the area with high solar PV potential, i.e. in Herzegovina.

Figure 4: Photovoltaic power potential in Bosnia and Herzegovina (Global Solar Atlas, 2020) Approximately 27 000 km2, or 50 % of the total area of BiH, is covered by forests and timberland according to data from the 1960s and 1970s. However, this number has decreased due to uncontrolled cutting and mining, in combination with reservoir construction during the expansion of the hydropower capacity. More information is needed in order to assess the energy potential from forest biomass in Bosnia and Herzegovina. According to a pilot study which was part of a UN Development Program from 2006, the agricultural biomass potential was estimated to 76 TJ, corresponding to 3857 tons of turnip seed, sunflower, soy and beans (Granić G. et. al., 2008b). Biomass is widely used for heating and cooking in the residential sector in BiH. This has a significant impact on the air quality of the cities and the health of the residents during the winter season. Sarajevo is frequently ranked amongst the most polluted cities in Europe. The largest contributor to air pollution in Sarajevo is burning of coal and biomass in residential buildings, and in later years an increased amount of car traffic. Cities like Tuzla, Lukavac and Zenica, that in addition to burning biomass also have high industrial activities, suffer from air pollution throughout the whole year and not only in the winter season. In Sarajevo, gas connections were installed throughout the city in the 1970’s, which in return reduced the SO2 and soot levels in the city. Due to high gas prices, the residents have turned to biomass and coal for heating. Thus, the progress made in past decades have been undone in recent years (Huseinovic & Petrovic, 2019). 1.1.8 Electricity demand in Bosnia and Herzegovina Electricity demand in BiH amounted to 12 540 GWh in 2017, an increase of 3.97% compared to 2016. Electrical distribution companies supplied 9722 GWh, while directly connected consumers received 2420 GWh of electricity. The maximum hourly peak load was registered on January 1st, 2017, and it corresponded to 2189 MW at 18:00, which was 91 MW higher compared to the peak demand in 2016. The minimum hourly load was 847 MW and it was registered on May 2nd, 2017, at 04:00. The maximum and minimum hourly loads for 2017 are illustrated in figure 5 below.

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Figure 5: Monthly max and min hourly loads in BiH 2017 (NOSBiH, 2018) Maximum and minimum daily loads are shown in figure 6. The highest load can be observed in January for both the max and min loads, while May requires the lowest loads.

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Figure 6: Monthly max and min daily loads in BiH 2017 (NOSBiH, 2018) Bosnia and Herzegovina’s total electricity production and consumption in the ten-year period between 2007-2017 is shown in figure 7. The yearly production includes electricity received from the distribution network. The consumption includes the distribution losses and electricity required for pumped storage. Overall, the electricity demand is met with ease, with an exception for 2012, where the difference between consumption and production was marginal. 18000 16000 14000 12000 10000

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Figure 7: Yearly production and consumption of electricity in BiH (NOSBiH, 2018) In figure 8 below, the amount of electricity consumed on the transmission network within Bosnia and Herzegovina is shown. ERS is the only utility company that is present in the Bosnian part of the Drina River Basin.

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Figure 8: Electricity consumption on the transmission network by utility in BiH 2014-2018 (NOS BIH, 2019) Demand projections for Bosnia and Herzegovina used in the model are based on the Indicative Production Development Plan 2020-2029, made by NOSBiH (NOSBiH, 2019). The plan proposes three scenarios: base, higher and lower. In this case, the base scenario demand projection is used. 1.2 Energy Sector in Montenegro The institutional organization of the Montenegrin energy sector is structured with the Ministry of Economy (ME) as the highest instance. It is responsible for creating a state energy policy and strategy. In addition to this, the ME prepares laws and covers the Energy Sector, Energy Efficiency and the sector of Mining and Geological Research. Subordinate to the ME is the Energy Regulatory Agency (RAE), which was established in 2004 as an independent non-profit organization. Its main objective is to exercise public authority in order to regulate the energy sector in Montenegro (Government of Montenegro, 2014). The Electric Power Company of Montenegro (EPCG AD) carries the responsibility of electricity production, distribution and electricity supply. The EPCG AD has the status of a public electricity supplier in Montenegro. The ownership of EPGC AD is split between the Montenegrin government (55%), the government of Italy (45%) and minority shareholders (1,3%). The Montenegrin Power Transmission System (CGES AD) was separated from the EPCG AD in 2009. The CGES AD has licenses for operation of the transmission network and the transmission of electricity (Government of Montenegro, 2014). The Montenegrin electricity market operator (COTEE Ltd) started operating in August 2011 based on a decision of the Government of Montenegro in December 2010. It was then separated from the CGES AD, and the state gained full ownership of COTEE (Government of Montenegro, 2014). 1.2.1 Energy Policies in Montenegro With the ratification of the Agreement of establishing the Energy Community in 2005, Montenegro started the process of harmonization of the Montenegrin legislative framework, considering the field of energy, with the EU acquis (CEDIS, 2005). The way of meeting the national target for the share of renewable energy sources in the gross final energy consumption by 2020 (33%) has been determined by the Montenegrin Energy Development Strategy 2030. Details regarding sources and the extent of energy use from RES is presented in the National Action Plan for use of RES by 2020. The enforcement of this plan is monitored by the ME, which is implemented every other year. The law stipulates that the Agency performs an annual analysis and publishes data on the share of renewable energy sources and high-efficiency cogeneration in total electricity production and consumption (Medenica, 2019). In 2014, the government of Montenegro published their Energy Development Strategy of Montenegro by 2030, under the name Bijela knjiga (White book). According to this document, the three main priorities of the energy policies of Montenegro until 2030 are: 1. Security of energy supply 2. Developing a competitive energy market 3. Sustainable energy development The sustainable energy development is based on accelerated but rational use of the endogenous energy resources while respecting the principles of environmental protection, increasing energy efficiency and greater use of renewable energy sources (Government of Montenegro, 2014). Montenegro submitted their INDC in 2015, pledging to decrease their emissions by 30% by 2030 compared to the 1990 base year (Government of Montenegro, 2015). 1.2.2 Thermal Power Plants in Montenegro Montenegro has one coal fired thermal power plant located in , which generates approximately 43% of all electricity produced within the country (Elektroprivreda Crne Gore, 2019a). Pljevlja I TPP is, as many other thermal power plants in the region, fuelled by lignite coal. The plant was put into operation in 1982, and in 2009/2010 an environmental and technological modernization of the TPP Pljevlja I extended its operational life to 2025. However, in the Annual Implementation Report published in November 2019 by the Energy Community, the Pljevlja I TPP opt-out allows it to remain in operation for a maximum of 20000 hours between January 1st and December 31st, 2023. The power plant is expected to reach this limit as early as October 2020, based on its current load factor. For this reason, the focus on a planned replace capacity, which would be required to meet emission standards according to the Emissions Directive for new plants, is increasing (Energy Community Secretariat, 2019). In November 2019 an article published in Vijesti ME stated that the Electric Power Industry of Montenegro (EPCG) is planning an ecological reconstruction of unit 1 in the Pljevlja TPP until 2022. A consortium of three companies submitted the most favourable tender for the project, which has an estimated value of 54.5 million euros. According to EPCG the operational life of the power plant will be extended with 20 years as an effect of the reconstruction (Vijesti ME, 2019). This information indicates that Pljevlja I will continue to produce electricity even after the opt-out period has ended. 1.2.3 Planned Thermal Power Plants in Montenegro There are no planned thermal power plants in Montenegro as of 2019. In order to secure the production from the current TPP Pljevlja, investments are needed in the period of 2019-2021. For this reason, the EPCG announced a public tender on the 11th of July 2019, for the selection of contractors for the ecological reconstruction of the first unit of the thermal power plant Peljava. After this reconstruction is completed the EPCG estimates the remaining operational life of the TPP Pljevlja to be an additional 20 years (Elektroprivreda Crne Gore, 2019d). 1.2.4 Coal production and coal reserves in Montenegro Next to the hydropower plants, coal is the most important energy resource in Montenegro. Coal reserves in the country are located within the Pljevaljsko and Beransko areas, containing an aggregate of 13 coal basins. The total reserves amount to 198,9 million tons in 2009. The coal mine AD Peljava (RUP) is owned by A2A (39,5%), the State of Montenegro (31,1%) and other stakeholders (29,3%). It has an annual production of 1,8 million tons. Coal produced in this mine has a moisture content of 30-36% and a lower heating value (LHV) of 20-28 MJ/kg. Pricing ranges from 36 to 48,27 euro per ton excluding tax, depending on the size of the coal (Rudnik Uglja Pljevlja, 2019). The brown coal mine Ivangrad AD was privatized in 2007 by Balkan Energy d.o.o. from Greece. The planned production of 100 000 tons of brown coal per year have been delayed (Government of Montenegro, 2014). 1.2.5 Oil production and oil reserves in Montenegro Montenegro has no oil production and relies solely on import. The Jugopetrol AD Kotor Joint Stock Company for Oil Exploration was privatized in 2002 and 54,5% of the ownership belongs to Hellenic Petroleum International AG. In the period between 2006 and 2009, Jugopetrol AD averaged an annual turnover of 231 972 tons of petroleum products. Montenegro Bonus d.o.o. Cetinje is a state-owned oil trading company. Its main activities include wholesale trading of oil products, and the trade and supply of electricity. In addition to these activities, the government assigned the Montenegro Bonus the development of the IAP pipeline through Montenegro. The average annual turnover for the company is 25 574 tons of petroleum products (Government of Montenegro, 2014). 1.2.6 Hydropower Plants in Montenegro Despite having 57% of their electricity production from hydropower (Elektroprivreda Crne Gore, 2019b), the technology is still a controversial topic in Montenegro today. According to the Ecological Movement “Ozon”, the government has made an invasion on the watercourses due to the planned small hydropower plants (Jovićević, 2019). On May 23rd, 2019, the government of Montenegro made a statement that they will not make new concessions for mini hydropower plants (mHPPs), and that they would instead focus on revising their current concessions (Investitor, 2019c). Despite this statement, on July 12th, 2019, the government gave out concessions for two new hydropower plants to the Hidroenergija Andrijevica company (Investitor, 2019b). The planned constructions of new hydropower plants have also been criticized by WWF Adria, who pledged to the government of Montenegro to suspend their activities regarding this matter and to form a working group to review the concession policy in this field. The local population has shown dissatisfaction with the planned hydropower plants proposed by the government. The main arguments against these constructions are the effect they will have on the nature, the fact that hydropower was subsidised by the consumers who paid extra on their consumption bills for the “green energy”, which was later changed so that the subsidies came directly from the state budget (Jovićević, 2019). A drastic way of showing the dissatisfaction with the construction of HPPs in Montenegro became evident at the construction site of a mHPP on the river Bukovica near the city of Šavnika in central Montenegro. Locals were guarding the construction site day and night, forcing the minister of economy Dragica Sekulić to make a statement that there will not be any construction on the location (Jovićević, 2019). In April 2010, the Zeta Energy d.o.o Danilovgrad acquired a licence from the RAE, which made it possible for the company to produce electricity. The company is owned partially by Nord-Trøndelag Elektrisitetsverk (NTE) 49%, and partially by EPCG AD 51%. Zeta Energy facilitates two hydropower plants, Slap Zete sHPP and Glava Zete sHPP. These are small hydropower plants with a capacity of 2 and 6,4 MW respectively (Government of Montenegro, 2014). The installed capacities and average yearly productions of hydropower plants in Montenegro can be observed in appendix table A7. Planned constructions of new hydropower plats is shown in table A8 in the appendix. The incident at the Bukovica HPP mentioned above, and other dissatisfaction from local population and NGOs, could have a great impact on the year of commission of these planned power plants. Plans for the HPP Komarnica have not encountered any resistance from locals or NGOs, since it is planned to be built 45 km upstream from the existing Piva HPP. In addition to this, the area that will become flooded by the dam will only encompass the and some uninhabited areas where the soil is not suited for agricultural use (Investitor, 2019a). According to Igor Noveljić who is the director of EPCG, the project of constructing the HPP Komarnica will be acceptable from an ecological perspective. The capital investment for the project is estimated to 238 million euros (Spasić, 2019a). 1.2.7 Other Renewable Power sources in Montenegro Alongside its coal and hydropower plants, together with recent installation of wind power, the government of Montenegro is planning on commissioning their first solar power plant between 2020 and mid-2024. The plant will have an installed capacity of 250 MW, with a yearly production capacity of 450 GWh. See appendix table A10 for additional information. Studies regarding the wind power potential of Montenegro have been conducted in 2007, as part of the Assessment of Renewable Energy Potential in the Republic of Montenegro (Barbieri & Cassulo, 2007). The study showed that, only accounting for high and medium potential productivity areas, the total gross capacity of installable wind turbines in Montenegro is approximately 400 MW. 100 MW of these are classified as high productivity areas, characterized by a (CF) of approximately 30%. Remaining 300 MW installable capacity would be commissioned in medium productivity areas with a CF of 25%. The study estimates a technical wind potential of approximately 900 GWh/year. Even though the study was conducted in 2007 it was still used as the main source of information regarding the wind capacity in Montenegro in the Energy Development Strategy from 2014, in which the government stated that no further analysis has been conducted (Government of Montenegro, 2014). As of 2019, Montenegro has 118 MW installed wind power capacity located at WPP Možura and WPP Krnovo. These numbers indicate that there still are many high productivity areas where the capacity has not yet been utilitzed, giving more room for wind power expantion in Montenegro.

Figure 9. (Left) Photovoltaic power potential in Montenegro (Global Solar Atlas, 2020) (Right) The energy potential of wind power [W/m2] at 50 m AGL (CETMA, 2007) 1.2.8 Electricity demand in Montenegro According to the Montenegrin regulatory agency for energy, the monthly peak load will on average increase with 2.7% between 2020 and 2021, and 3.0 % on average between 2021 and 2022. The peak loads are displayed in figure 10 below. The peak load increases during all the months of the year. The estimation of the monthly maximum peak loads of the system for the period 2020-2022, were estimated in accordance with the criteria prescribed by the ENTSO-E standards, which define power and frequency controls (CG Regulatorna agencija za energetiku, 2019). 700

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Figure 10: Projected monthly peak load for the period 2020-2022 in Montenegro (CG Regulatorna agencija za energetiku, 2019) Electricity demand projections were made for the period 2014-2030 in the Energy Development Strategy published by the government of Montenegro in 2014. These presented a demand of 4105 GWh in 2020 and 5214 GWh in 2030 (Government of Montenegro, 2014). Comparing the projected values with the achieved demand up until 2018, it can be observed that the projection was 14% higher. This indicates that the future demand level is overestimated, meaning that the real demand increase will most probably be lower than the projected numbers presented in the strategy. The demand used in the model is based on the Energy Development Strategy, with an added 14% decrease based on the reasoning stated above. Figure 10 below shows the electricity demand in Montenegro based on customer type between 2012 and 2018. It can be observed that the demand in 2012 was higher than the following years, mainly due to the decrease in direct customers demand. Distribution customers demand has increased in this period.

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2000 GWh 1500 1000 500 0 2012 2013 2014 2015 2016 2017 2018 Direct customers Distribution customers Transmission losses Losses on the distribution network

Figure 11: Total electricity demand by consumer type in Montenegro 2012-2018 (Elektroprivreda Crne Gore, 2019b) 1.3 Energy Sector in Serbia The Republic of Serbia (RS) is, just like Bosnia and Herzegovina, heavily dependent on coal to reach its electricity demand. In 2017, approximately 58 % of the installed capacity for power production in Serbia came from lignite powered thermal power plants (Electric Power Industry of Serbia, 2018). Coal is an endogenous resource in Serbia and comes from coal mines that are using surface, underground and underwater coal exploitation techniques (Ministry of Mining and Energy, 2016). Additional power producing technologies that are being widely used in order to meet the power demand are hydropower, and in recent years also wind power. Hydropower plants are located on the Lim and Drina rivers in western Serbia, as well as the and Morava rivers in Eastern Serbia. Hydropower accounts for approximately 30% of the total power production in Serbia (Electric Power Industry of Serbia, 2018). 1.3.1 Energy Policies in Serbia On June 30th, 2015, the government of Serbia submitted their NDC to the UNFCCC (UNFCCC, 2015b). The country plans to reduce their GHG emissions by 9,8% until 2030 compared to the base year of 1990. According to the NDC, the methodologies selected for assessing the GHG emissions in Serbia are the IPCC Guidelines 2006, together with the IPCC 2013 KP Supplement. Identified sectors that are the most vulnerable to climate change impacts are the agriculture, hydrology, forestry, human health and biodiversity sectors. In the period of 2000- 2015, the damage caused by extreme climate and weather conditions exceeded 5 billion euros, the majority of which were associated with high temperatures and droughts (Republic of Serbia, 2015). The country has a candidate status for entering the EU, thus harmonizing its national legislation with the EU legislation. In this way, Republic of Serbia additionally contributes to the national emissions reduction (Republic of Serbia, 2015). Just like BiH and ME, RS will experience increases in their price of electricity if the cross-subsidisation and the cost of CO2 emissions under EU’s emission trading scheme are implemented. According to an article published by Janez Kopač in March 2019, the price could increase with 137% (Kopač, 2019). For Serbia to reach their NDC goal of 9,8% reduction of GHG emissions compared to their base year 1990 (Republic of Serbia, 2015), the government has developed a Climate Strategy and Action Plan. This document was a result of a project funded by the European Union. The Action Plan consists of two measures that are put in place to reduce the GHG emissions from the power sector. These are: 1. Implementation of the emissions trading system (and implementation of equivalent measures) 2. Increasing the use of RES in electricity production Implementation of the EU-ETS reporting, monitoring and verification in Serbia is expected to take place by 2025, after which the full implementation of the EU-ETS can commence. A gradual CO2 tax will be put as an equivalent measure for the period 2021-2025 prior to Serbia entering the EU in 2025 (GFA Consulting Group, 2019). The second measure regards updating of feed-in tariffs and installation of 3409 MW of hydropower, 869MW of solar photovoltaic and 732MW of wind power by 2030 (GFA Consulting Group, 2019). Promoting power production from renewable energy sources is regulated through incentives from the government of Republic of Serbia. On June 13th, 2016, President Aleksandar Vučić signed a statute which stated the different incentives for power production from renewable energy sources such as wind, solar, biomass and geothermal power, as well as co-generation and waste plants. Amounts given as an incentive for each of the stated technologies can be found in the appendix table A16. Curretly, the statute is valid until December 31st, 2019 (Vučić, 2016). It can be observed that the previous date of validity was December 31st, 2018, which indicates that the current one could be extended into 2020, continuing the support for renewables in the future years as well. 1.3.2 Thermal Power Plants in Serbia Thermal power plants in Serbia have in the last nine years accounted for 69,6 % of all the electricity production. Due to its vast endogenous coal reserves and an existing installed capacity of 4079 MW, Serbia can satisfy its domestic electricity demand without being reliant on neighbouring countries. The average working hours of all the thermal power plants in Serbia is 173 615 h, with the oldest being TE Kolubara A which has been operating connected to the grid for almost 350 000 h. The newest unit, Kostolac B, constructed in 1991 has been connected to the grid for 90 000 h (Electric Power Industry of Serbia, 2018). 1.3.3 Planned Thermal Power Plants in Serbia As of 2019, the total coal fired thermal power plant capacity in Serbia stands at 4079 MW. This number represents 58 % of the total installed capacity in the country (Elektroprivreda Srbije, 2018). Serbia is planning on further expanding their installed capacity of thermal power. Between 2021 and 2026, the plan is to add an additional 1400 MW of installed capacity, divided between TPP Nikola Tesla and TPP Kolubara. More information about the power plant additions is provided in appendix A13. Old thermal units, with a total capacity of 1340 MW, will be decommissioned during the period between 2015 and 2025 (Parliament of Republic of Serbia, 2014). This indicates that Serbia is planning on replacing their existing thermal power with new, instead of diversifying their energy portfolio more aggressively towards the implementation of RES in the system. Domestic coal production met 97% of the coal demand in 2019, while 3% was imported from neighbouring countries. The share of the total coal demand used for power production in thermal power plants was 94% (Government of Republic of Serbia, 2019). Based on these numbers an assumption was made that Serbia meets the coal demand for their coal fired power plants with domestically produced coal, eliminating the need of coal imports to satisfy the needs of the power sector. 1.3.4 Coal production and coal reserves in Serbia Serbia has two coal mines in active use. These are the Kostolac and Kolubara mines. The largest coal mine in Serbia is the Kolubara mine, which produces 30 million tons of coal yearly, used to produce 53% of all electricity production in Serbia. The Kolubara mine basin consists of four active surface mines (Electric Power Industry of Serbia, 2019a). Kostolac mine produces nine million tons of lignite coal per annum, sourced from one active surface mine (Electric Power Industry of Serbia, 2019b). Proven coal reserves in Serbia amount to approximately 4,5 billion tons, of which lignite account for 97% (Ministry of Mining and Energy, 2016). 1.3.5 Hydropower Plants in Serbia Hydropower plants in Serbia, as well as in many other countries in the region, are the backbone of the renewable energy contribution to the energy mix. According to the Energy Sector Development Strategy, the potential for hydropower in the Republic of Serbia is approximately 25 000 GWh/year. Production from HPPs in 2018 was 10,7 TWh, as seen in appendix A14, meaning that there still is room for expanding the HPP capacity in order to reach the 19,5 TWh/year technically usable potential in the country (Chamber of Commerce and Industry of Serbia, 2019b). Most of the installed hydropower capacity is located in the Drina river basin and at the Donau river bordering Romania. Đerdap 1 (1099 MW) is the largest hydropower plant in Serbia, contributing to 37% of the total installed hydropower in the country. 1.3.6 Electricity demand in Serbia The Statistical Office of the Republic of Serbia releases yearly publications regarding the energy balance of the country. Data found in these balances are harmonized with standards of Eurostat and the International Energy Agency. Serbia had, according to the published data, a final electricity consumption corresponding to 27 160 GWh in 2012, a number that increased to 28 048 GWh by 2018. In order to approximate the future demand, previous demand increases were considered and extrapolated for the modelling period. Losses in the system amounted to 5608 GWh (17,2%) in 2012 and 4532 GWh (14%) in 2018, which is considered high by European standards (Republički zavod za statistiku, 2020). The Council of European Energy Regulators published a report on power losses in October 2017 which indicated that most of the EU 27 countries have total transmission and distribution losses between 2 and 9 % (CEER, 2017). In order to approximate the demand for the period 2020-2035, an extrapolation of historical values was performed. 1.3.7 Other Renewable Power sources in Serbia The number of sun hours in Serbia amounts to just below 2000 in the northern parts of the country and 2300 hours in the south. The solar power potential represents 16,7% of the total renewable energy potential in Serbia. Compared to central Europe, the energy potential of solar irradiation is 30% higher in Serbia. Average daily solar irradiation in the winter season ranges from 1,0 kWh/m2 in the Northern regions and 1,7 kWh/m2 in Southern Serbia. During the summer season, these numbers range from 5,4 kWh/m2 and 6,9 kWh/m2 respectively. Comparing the solar potential of Serbia with Germany, it can be observed that the average irradiation in Germany is 1000 kWh/m2 while the same figure is 1400 kWh/m2 for Serbia (Lambić, 2011). Average intensity of the solar radiation varies through the country, with 1200 kWh/m2/year in the Northern parts and up to 1550 kWh/m2/year in South-Eastern Serbia (Energy Portal, 2019). This shows that if utilized properly, solar power could help the transition away from the coal dependence the Republic of Serbia has today. Serbia has a continental climate with an average wind power potential. The greatest wind potential can be found in the Southern Banat located in Eastern Serbia according to (Chamber of Commerce and Industry of Serbia, 2019c). The area of , the Pešter plateau, together with the mountain passes, are also included as the area’s best suited for wind power within Serbia (Chamber of Commerce and Industry of Serbia, 2019c). In 2019, Serbia increased their previously installed capacity with 540%. Kovačica (104,5 MW) and Čibuk 1 (158 MW) are the wind power plants that contributed to the increase. The total installed wind power capacity as of 2019 is 330 MW. Wind park Kovačica will produce electricity for 60 000 households, decreasing the domestic emissions with 250 thousand tons annually. The total cost for this project was 189 million euros, giving an investment cost of 1,8 million euros per MW installed capacity (Spasić, 2019b). As of February 2020, there is no utility solar power capacity installed in Serbia.

Figure 12: Wind (left) and Solar (right) potential in Serbia (Stipić, Vidović & Momčilo, 2010) Previous studies related to the wind power potential in Serbia has found that the potential in locations suitable for construction is approximately 1300 MW. The Pannonian Basin, together with parts of Eastern Serbia and the mountain areas of Zlatibor, and Divčibare are the identified locations claimed to have the highest wind power potential within the country. The approximated yearly power production from wind power, if fully utilized, is 2300 GWh (Stipić, Vidović & Momčilo, 2010). The maps shown in figure 12 above indicate that wind and solar power potentials are low in the Drina basin compared to other parts of Serbia. The Republic of Serbia has a significant biomass potential, amounting to 3448 Mtoe per year, of which 48% is agricultural biomass and 44% wood biomass. Mountain regions in Central Serbia contain most of the wood biomass, with a high exploitation percentage of over 70%. In contrast to the wood biomass, the agricultural biomass which consists of field crop residues, as well as residues from fruit plantations and processing, have a negligible exploitation percentage of 2%. This indicates uneven exploitation of the biomass resources of the country, where only 2% of the 1,67 Mtoe potential of agricultural biomass is being used, while the forests are being widely exploited (Chamber of Commerce and Industry of Serbia, 2019a). As previously mentioned, President Aleksandar Vučić signed a statute in 2016 with the goal of promoting power generated from renewable energy sources. In addition to this, the Serbian Government reduced the VAT rates for wood pellets and briquettes in 2017, from 20% to 10%. Observing data from the period between 2011 and 2018, it is evident that these steps conducted by the government have increased the power produced from biomass in Serbia. In 2011, there was only one biogas plant in Serbia. This number increased drastically and by mid-2018, 13 biogas plants were in operation. The total capacity of these biogas powered plants is 14,22 MW, which indicates that Serbia will most likely reach their target for 2020 of 30 MW, as stated in their National Action Plan. Due to the increased demand of biomass in Serbia, the domestically produced pellets and briquettes previously used for export (85-90% of total production), are as of 2016 consumed within the country. This has lowered the export to only 30% (Chamber of Commerce and Industry of Serbia, 2019a). 1.4 Energy trade between the riparian countries The riparian countries of the Drina River Basing are interconnected with 400 kV, 220 kV and 110 kV transmission lines. The connection between Bosnia and Herzegovina and Serbia consists of a 400 kV connection from Ugljevik to Sremska Mitrovica, 220 kV connection from Višegrad to Požega and 110 kV connections from Zvornik and Janja to Lešnica and Valjevo. Montenegro has two 220 kV connections from Pljevlja to Valjevo (via Bajina Bašta) and Požega, together with one 110 kV line from Pljevlja to both Višegrad and Potpeć (Elektromreža Srbije, 2020). Bosnia and Herzegovina has one 400 kV connection to Montenegro (Trebinje – Lastva) and two 220 kV connections going from Sarajevo to Piva and Trebinje to Perućica (NOSBiH, 2020). The trends regarding trade within the basin show that Bosnia and Herzegovina consistently has a net export of electricity. Cross border flows indicate that the net positive export is achieved through trade with Croatia and Montenegro, while a net import of electricity occurs over the border with Serbia (NOSBiH, 2020). Trade between Serbia and Montenegro is possible through the 220 kV connections from Pljevlja. Data obtained from the Serbian transmission and distribution company AD Elektromreža Srbije (EMS) indicates that, in the period of 2014- 2018, Montenegro has been a net importer in the trade with Serbia (Elektromreža Srbije, 2020). Montenegro is connected to with a 400 kV transmission line from Ribarevina to Peć, although it was not clear weather this trade occurred via Kosovo or not. EPS has, since 2013, not included Kosovo in their yearly technical reports (Electric Power Industry of Serbia, 2018). Serbia has on average imported 221 GWh more than they have exported to their eight neighboring countries. The largest quantities of imported electricity to Serbia comes from Romania and Bulgaria, while the greatest export markets are Bosnia and Herzegovina and Northern Macedonia (Elektromreža Srbije, 2020) Figure 13 below shows the average yearly electricity trade in the period of 2014-2018 between the riparian countries.

Figure 13: Average electricity trade (GWh) between 2014-2018 between the riparian countries (NOSBiH, 2020; Elektromreža Srbije, 2020) The transmission system in Serbia is well-connected with the countries in the region. New investments in the transmission network is expected to accommodate for higher RES integration. Future increases in peak load in Serbia will also benefit from cross-border electricity trade. In 2016, the recorded peak load was 5775 MW, while it is projected to increase to 6392 MW by 2030. Investment plans for the transmission system include construction of a new 400 kV line with Montenegro and Bosnia and Herzegovina. This will consequently require investments in the domestic medium and high voltage transmission and distribution lines (SEERMAP, 2017). Dragoslav Ljubičić, the Independence Union chief commissioner, stated in an interview with Istinomer that, apart from party employment within the EPS, it tolerates electricity imports caused by negligence of the management and huge losses due to what he claims is electricity theft (Istinomer, 2017). The statement could possibly explain the massive losses in the transmission and distribution system of about 20% in 2013 and 17,1% in 2017, found in the energy balance of Republic of Serbia for the years 2013-2018 (Republički zavod za statistiku, 2020). In order to gain a better understanding of how the trade between the riparian countries is being performed, two interviews were conducted with employers of the Montenegrin electricity market operator (COTEE) and the independent system operator in Bosnia and Herzegovina (NOSBIH). The first interview was conducted with Slaven Ivanović, head of service at COTEE, where the main question investigated how the current cooperation between the riparian countries is performed with regards to trade and control of waterflows of the Drina river and its tributaries. In the interview, Ivanović stated that due to new technologies and EU regulations to which the states of Bosnia and Herzegovina, Montenegro and Serbia have turned, fundamental changes in the energy policies of these countries has occurred. The area has opened to foreign investors, which has created a situation where there currently are no major state funded projects within the energy sector. This is, according to Ivanović, precisely what is needed for regional integration of the energy systems in the Western Balkan region. Regarding the control of the Drina hydro potential on the BA/CG/RS route, he states that the political situation in the region no longer plays an important role, especially as technologies have gone towards renewables. In the region, all forces are focused on market integration (market coupling, Day-ahead and intraday) as well as cross-border balancing issues, especially due to the large increase in RES in the region. They are done bilaterally (stand-alone initiatives by states) or through initiatives of the European Commission (Energy Community) (Ivanović, 2020). The second interview was conducted on the 27th of December 2019, in Sarajevo with Semir Hadžimuratović, a senior engineer at NOSBIH. Hadžimuratović stated that the cooperation regarding control of the waterflows of the Drina river and its tributaries between Bosnia and Herzegovina and its neighboring countries Montenegro and Serbia works in a satisfactory way. It does, according to Hadžimuratović, not include any well-developed cooperation, but it is fair enough when it comes to control of the water flows. The main hydropower plant to consider when the topic of cooperation is highlighted is the Piva hydropower plant, since it has a large accumulation of water behind its dam (Hadžimuratović, 2019).

The transformation system operators of Bosnia and Herzegovina (NOSBIH), Montenegro (CGES) and Serbia (EMS) are all member companies of the European Transmission System Operators (ENTSO-E). They are part of the Continental South East (CSE) region, which covers the Balkan area and Italy. Figure 14 below illustrates the CSE region of the ENTSO-E.

Figure 14: ENTSO-E Continental South East Region(Maire, 2015) Albania, shown in grey in the picture above, became a member of the ENTSOE in March 2017 (Entsoe, 2017). Turkey, shown in grey in figure 14, has the status of an observing member, and is therefore not yet an ENTSO-E member. The Turkish transmission system is, however, connected in parallel synchronous operation to the Continental Europe Synchronous Area (CESA). Despite CSE being quite extended geographically, it only represents approximately 16 % of the total electricity generation within the ENTSOE zone. The network within the CSE is sparse, resulting in limited transfer capacities. Figure 15 below demonstrates the Net Transfer Capacities (NTCs) is the region (Maire, 2015).

Figure 15: Illustration of Net Transfer Capacities in CSE region (2013)(Maire, 2015) A maximum total exchange between two interconnected power systems, which are available for commercial purposes, during a given period and direction of active power flow is called Net Transfer Capacity or NTC. It is obtained by subtracting the Transmission Reliability Marking (TRM) from the Total Transfer Capacity (TTC). The NTC values change during the year for a given border with unchanged grid components. Table 1 below illustrates the expansion of the interconnections in the Continental South East region of the ENTSO-E area. The connection between Montenegro and Italy was commissioned in 2019, while the map in the top right corner of the table shows the expansion of that connection from Pljevlja to Obrenovac, South-East of Belgrade. This would increase the possibility of electricity trade between Italy and the Western Balkans. Table 1: Expansion of interconnections in the region (Entsoe, 2018)

Under construction In Permitting

Planned but not yet permitting Under consideration

1.5 Aim and Objectives The objective of the created energy model is to provide answers the following research questions: - How will the countries reach the targets set under the UNFCCC Nationally Determined Contributions, including the renewable energy penetration within the Drina Basin countries as well as the future electricity generation mix? - The penetrations of non-hydro renewable energy sources during the modelling period, including changes in the generation mix? - Enforcement of the Emission Trading Scheme, how will the generation mix change and how will the total emissions of the system change? Although research addressing the power sector in the DRB has been conducted in earlier studies (Almulla et al., 2018; World Bank Group, 2017), a research gap still exists within the field. The research questions stated above aim to fill the current research gap with new insights relating to the power sector in the riparian countries and the power potential of the DRB. 2. Methodology This chapter describes the modelling tool used, the model set up and the scenario analysis conducted during the creation of the energy model. The model was created using the Open Source Energy Modelling System (OSeMOSYS). Input parameters for the model were obtained through information gathering based on literature reviews, interviews with local experts and reviews of policy documents such as the submitted NDC’s. The reference energy system shown in figure 16 below indicates the structure of the energy model. The model was set up using the MoManI interface, together with OSeMOSYS and the GLPK solver.

Figure 16: Reference Energy System representing the OSeMOSYS model

2.1 Short description of OSeMOSYS OSeMOSYS is an optimization model used for long-run energy planning. It is open source and, due to the absence of upfront financial costs, it is broadly employed as a training and dissemination tool. OSeMOSYS has a variety of applications when it comes to modelling, such as creation of models for villages, countries or even regions. In this study, it was used to make the regional model comprising of the energy systems of Bosnia and Herzegovina, Montenegro and Serbia. MoManI is a browser-based open source interface used to operate OSeMOSYS, giving users the possibility to construct models, add and remove data and design and analyse scenarios (OSeMOSYS, 2020). 2.2 Scenario definition and key assumptions In order to answer the stated research questions using OSeMOSYS, a scenario-based analysis was performed including four different scenarios. These include the business as usual (BAU), nationally determined contribution (NDC), Renewable Energy scenario (RE) and the emission trading scheme (ETS) scenario. The ETS scenario included a sensitivity analysis with up to three different levels of implementation. The scenarios, together with assumptions associated with them, are presented in the section below.

2.2.1 A business as usual (BAU) scenario: This was the foundation of the model from which different scenarios were created. Reflecting the historical production and consumption of electricity within the riparian countries, as well as trade with countries outside of the DRB, the BAU scenario aimed at making a projection based on past investments, trends and policies. The scenario assumes that future investments in RES technologies, including hydropower, are to be realized in the same phase as historical trends show. Due to this assumption, the model was limited in the amount of RES it could install each year to match the past trends of investment. Another assumption was that existing coal fired thermal power plants were to be decommissioned according to the national plan, since current plants are reaching the end of their operational life. Old TPPs are to be replaced by new TPP additions, with higher efficiencies at around 40% compared to the old power plants that ranged between 27 and 32%. This change in energy efficiency throughout the modelling period is also present when it comes to the transmission and distribution losses, which decrease during the whole modelling period. What the BAU scenario shows is how the energy mix could look like in the upcoming years, if no changes in the trends of investments within the power sector are made.

2.2.2 The nationally determined contribution (NDC) scenario This scenario is based on the emission reduction pledges made by the riparian countries in their NDC’s submitted in 2015. In order to emulate an investment path according to the proposed investment strategies and action plans of the riparian countries, forced investments were made into the model. The premises of the scenario were that new capacity additions regarding RES would be limited to the stated capacities according to country specific plans. The technology types and allowed capacities would therefore not be chosen by the model based on a least cost solution basis. An assumption was made that if the future demand was not met by new additions in RES, it would be satisfied by investments in new thermal power plants. Efficiency improvements in new thermal power plants and the transmission and distribution network followed the same assumptions as in the BAU scenario. By investing according to the country specific plans, the goal was to evaluate if the countries will meet their NDC goals submitted to the UNFCCC. In addition to these findings, information about the changes in the energy mix during the modelling period were also of interest.

2.2.3 The renewable energy (RE) scenario: As mentioned above, the BAU and NDC scenarios included limitations in the rate of investments of RES according to either historical trends or planned investments according to the NDC’s. The renewable energy (RE) scenario was created in order to allow the model to more freely invest in the technologies that were economically feasible at any given time during the modelling period. By structuring the scenario in this way, the model would be able to perform an optimization based on input values and equations within OSeMOSYS. The aim of this scenario is to show the potential emissions and energy mix by 2035, based on price competitiveness of technologies and not current or past policies. This scenario is the basis for the ETS scenarios described below. 2.2.4 Emission Trading Scheme (ETS) scenarios: Based on the shown willingness from the EU and the Drina basin countries to incorporate the countries of the Western Balkans into the European Union, an assumption was made that an entering into the EU would happen during the modelling period. Since EU member states are subject to the emission trading scheme (ETS), while the basin countries do not comply under these regulations, an assumption was made that by joining the EU the ETS would be imposed on the power sector of Bosnia and Herzegovina, Montenegro and Serbia, and thus increase the cost of power production from thermal power in the Western Balkan region. In order to account for this in the model, an emission penalty was added on the CO2 emitting technologies. Since the date of possible entry into the EU is unknown, an assumption was made that Montenegro and Serbia will join in 2025, while Bosnia and Herzegovina will become a member state in 2027. According to projections made by Pöyry, the CO2 price could range from 21.8 euro per ton in 2021 to 48,2 euro per ton in 2035 (CEE Balkanwatch Network, 2017). A sensitivity analysis was conducted in order to define what level of CO2 pricing would, according to the energy model created, render the coal fired thermal power plants unfeasible. In order to perform the sensitivity analysis, three scenarios were created (ETS 5, ETS 10, ETS 20). The goal with these scenarios is to determine the amount of CO2 pricing that will affect the power production from thermal power plants in a major way. Information of interest from this scenario are the energy mix and emission levels if the ETS is implemented in the Drina basin countries. 3. Model Results and Discussion In this chapter, the results obtained from the model are presented and discussed. Parameters that have been chosen as relevant for this study are the energy mix in the period 2020-2035, the total emissions generated form each power system (BA/ME/RS), the share of RES within the DRB in relation to the total RES capacity, as well as trade between the riparian countries. All these parameters are shown for the four scenarios, providing a representation of what the differences in outcome are for the given scenarios. Since all scenarios have the same energy mix in 2020, which is considered the base year in the model, it is shown only once in the graphs regarding power production.

Power production by technology type in Bosnia and Herzegovina for the base year of 2020, as well as the four scenarios, are shown in figure 17. Additions in wind power capacity can be observed through all scenarios, with higher shares represented in the RE and ETS scenarios. Expansion of the current thermal power capacity is only present in the BAU and NDC scenarios, however the current thermal capacity is completely phased out by 2035 in all scenarios except the BAU.

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Figure 17: Power production by technology type for all scenarios – Bosnia and Herzegovina Power production shown in the graph above represents, not only power produced to meet the electricity demand of Bosnia and Herzegovina, but also electricity for export to its neighbouring countries. The ratio between hydropower and thermal power production remains close to constant in the BAU scenario, with TPPs producing 61,7% by 2025 and 62,1% by 2035. This ratio shifts in all other scenarios, most evidently in the ETS 10 scenario where TPPs account for 47,7% by 2025 and 36,7% by 2035. Results obtained from the model indicates that solar power is not price competitive in relation to the other available technologies during the modelling period. The results suggest a very reserved increase in RES in the NDC scenario compared to the BAU. When the NDC was submitted in 2015, the proposed new capacity additions were unambitious, since additions in especially wind power in the period up until 2020 already accounted for approximately 30% of the planned capacity addition by 2030 in Bosnia and Herzegovina. The ETS 10 scenario implies that thermal power will account for only a minor share of the total electricity mix by 2035. This insight raises questions for discussion. How will Bosnia and Herzegovina handle cutdowns in a sector that employs so many (in mines and TPPs), while still complying with EU regulations if the country enters the EU by then? Future studies relating to this topic could be just as relevant for Serbia and other coal dependent countries in the region.

Emissions considered in the model are those associated with power production from coal power plants. In order to account for emissions in the model, an Emission factor was assigned to all the power producing technologies. An assumption was made that the emissions from the power sector are produced solely in TPPs, i.e. no emissions associated with coal extraction or other energy technologies. The emission factor for existing thermal power plants was calculated by dividing the total emissions from the power sector with the power produced. In the case of BiH and RS, the emission factor for existing TPPs was 0,456 and 0,389 MtCO22eq per PJ respectively. For TPPs in ME this figure was 0.356 (Mt/PJ). New TPP additions were assumed to produce less emissions due to better filtering processes for the exhaust gases and lower fuel consumption due to higher efficiencies. The emission factor for new TPPs in BA and RS was set to 0,36, and 0,335 (Mt/PJ) for ME (Elektroprivreda Crne Gore, 2019d; Almulla et al., 2018). Figure 18 below illustrates the emissions from the TPPs in BiH during the modelling period. Emissions are constant in the BAU scenario during the period 2020-2035 despite the power demand increase. As expected, the BAU scenario contributed to the largest quantity of CO2eq emissions. Investments in RES according to the NDC contribute to a lowering of emissions during the modelling period compared to the BAU scenario with 20,2 Mt CO2eq or 7,51% of total emissions. Emissions in the NDC scenario increase by the end of the modelling period and by 2035, they are 1,16% lower compared to the BAU scenario. Emissions associated with the RE, ETS 5 and ETS 10 scenarios seem to follow the decommissioning rate of the current thermal power capacity in Bosnia and Herzegovina. The post 2030 investments in new thermal power in the RE and ETS 5 scenario does however contribute to much greater emissions compared to those in the ETS 10. Emissions in the ETS 10 scenario are 91,67% lower compared to the BAU scenario in 2035.

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Figure 18: CO2eq emissions from the power sector in Bosnia and Herzegovina Emissions from the power sector in Bosnia and Herzegovina in the BAU and NDC scenario do not show any significant trend shifts even though the demand increases during the modelling period. The main reason behind this is that higher efficiency TPPs replace the current inefficient once. Losses in the transmission and distribution network also decrease with time, requiring less production to meet the same demand. Comparing the emissions with the NDC goal of having a 20% increase over the 1990 levels by 2030 (Government of Bosnia and Herzegovina, 2015) in a BAU case quickly show significant discrepancies between the goal value and the modelled outcome. If Bosnia and Herzegovina increased their emissions with 20% over the 1990 levels, the total emissions from the power sector would amount to 27,72 MtCO2eq, which is much higher than the 17,23 MtCO2eq showed by the model. There are several different factors capable of affecting these projections. One important factor is the demand projection for the period. In 2015, when the INDC was submitted, the projection had to consider 15 years of demand projections, compared to 10 years projected in this study. Longer projection horizons contribute to higher uncertainties. Bosnia and Herzegovina has had a negative population growth since 2006, and the population decreased with 4,13% between 2015 and mid-2020 according to UN data (UN Data, 2019). Demand projections in this model were based on the “base scenario” proposed in the Indicative Production Development Plan 2020-2029 (NOSBiH, 2019). The plan also proposes a “higher scenario”, with a demand that is 12,8% higher by 2030, compared to their “base scenario”. An additional factor to lower future demand than previously projected is the unplanned shutdown of the Aluminiji d.d. aluminium extrusion plant, which was projected to consume 2010 GWh per annum according to the IPDP 2020-2029 (NOSBiH, 2019), but is now no longer a direct consumer. These factors, together with the methodology of projecting demand and future emissions, contribute to differences between the emission levels indicated in the NDC and the model. For these reasons, Bosnia and Herzegovina meet their NDC goals in all scenarios, including the BAU scenario. Represented in figure 19 below is the power production by technology type in Montenegro. In contrast to the results obtained for BiH, results for the BAU and NDC scenarios Montenegro show an increase in wind power capacity additions compared to the RE, ETS5 and ETS10 scenarios.

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Figure 19: Power production by technology type for all scenarios– Montenegro Instead of considering wind power, the RE, ETS5 and ETS10 scenarios indicate a great expansion of hydropower in the upcoming years. The NDC and BAU scenarios are the only outcomes where coal is still part of the energy mix by 2035, except form a tiny production rate from coal in the ETS 10 scenario. Power produced in figure 19 includes the electricity for export. Additions in photovoltaic solar power was forced in the NDC scenario in order to follow the investment strategy. It was, however, not chosen as a feasible option from an economic standpoint in other scenarios. The obtained results for Montenegro in the period 2020-2035 clearly indicate that there are potentials in both wind- and hydropower that could meet the current and future electricity demand of the country.

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Figure 20: CO2eq emissions from the power sector in Montenegro Emission curves presented in figure 20 above are different, since Montenegro is heavily reliant on electricity imports. Scenario ETS 5 and ETS 10 indicate zero emissions in 2025/2026, followed by an increase in emissions. The underlying reason being that the ETS is enforced in Bosnia and Herzegovina from 2027 onwards. This limits the possibility of electricity exports from BiH to Montenegro, resulting in a need to engage the existing thermal power plants to meet the demand. As capacity additions are made in all the riparian counties, the need of electricity form the Pljevlja power plant decreases once more and by 2031, the emissions in the ETS 5 scenario are at zero once again. Montenegro pledged to decrease their emissions with 30% compared to the levels of 1990, according to their NDC (Government of Montenegro, 2015). The pledged reduction is met through investments according to the NDC, as shown in the results obtained from the NDC scenario. It is important to access the possibility of building large hydropower plants in Montenegro that could contribute substantially to the power production, like the Piva and Peručica plants do. Small hydropower plants have met a lot of resistance in the past years, and in order to satisfy future demand and decrease the reliance on imports, it is vital to make use of the power potential found within the country. Adding additional cost to the coal power plant in Pljevlja, as shown by the ETS 5 and 10 scenarios, makes the question about feasibility more relevant than ever. The Pljevlja power plant is shut down approximately 50% of the modelling period in the ETS 5 scenario, which indicates the small margins of feasibility the plant is operating at. Since higher cost of electricity production from thermal plants is applied to all DRB countries, additional production from the Pljevlja power plant is needed in the ETS 10 scenario in order to export electricity to BiH and RS. An outcome like this is highly unlikely in the future since the model based the exports on a variable cost equal to zero. Results indicated in figure 20 regarding the RE and ETS 5 scenarios show that Montenegro could be a net zero emitter from their power sector by the early 2030’s. Power production by technology type for Serbia is presented in figure 21. In contrast to Bosnia and Herzegovina and Montenegro, results obtained indicate that coal power will be a substantial part of the energy mix in all scenarios. This is due to different prices of RES technologies in Serbia, and a less radical rate of decommissioning of existing thermal power plants. Since the amount thermal power production did not decrease in the ETS 5 and ETS 10 scenarios compared to the RE, an additional scenario was created, i.e. ETS 20. It was just as in the previous ETS scenarios, implemented in 2025 for Serbia. The outcome of having a 20-euro emission penalty per ton of emitted CO2eq was that current thermal capacity was decommissioned in 2025. At the same time, the results indicate that this capacity shortage is going to be replaced with new, more efficient thermal power. Capacity additions regarding photovoltaic solar and wind power (both inside and outside of the DRB), are present in the ETS 20 scenario.

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Figure 21: Power production by technology type – Serbia Emissions from the power sector in Serbia are illustrated in figure 22. The emission levels are constant in the BAU scenario. Pledges made in the NDC do lower the emissions in comparison. Scenario RE, ETS 5 and ETS 10 have almost identical emissions. An explanation to this is the price competitiveness of coal. By implementing an ETS of 20 euros, the coal competitiveness of older, already existing, plants were decreased which caused a proposed decommissioning in 2025. Since new thermal plants are more efficient and thus produce less emissions, they are still more economically feasible compared to wind and solar power additions. 35

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Figure 22: CO2eq emissions from the power sector in Serbia Serbia, being considerably more populated compared to BiH and Montenegro, has a substantially larger installed thermal power capacity leading to comparatively high emissions. During the modelling period, the emissions increased from approximately 27 500 to 30 000 MtCO2eq in 2030. The emission increase is small compared to the increase in demand. Reasons behind this include a much-improved grid over time which was an assumption when the model was constructed. Currently, Serbia has much higher losses compared to other European countries, indicating the room for improvement in this segment in the upcoming years. In the scenario analysis it can be observed that the existing thermal power capacity is price competitive in all scenarios except the ETS 20. Adding a 20-euro price tag on every ton of CO2eq emissions, makes power production from renewable energy sources a more feasible option. Photovoltaic solar power was in this scenario also considered a possible option to invest in. Solar PV additions would, according to the ETS 20 scenario, represent a higher installed capacity in Serbia by 2025 than all the solar PV and wind power currently installed. These solar investments are in line with the investments of the NDC, but at a larger scale. The 1990 emission levels that stand as the base year in Serbia’s NDC is, just as in the case of BiH, a specific time in the country’s history. 1990 was the last year before the outbreak of the Yugoslav and Bosnian wars, started in the early 90’s. The power and industry output, as well as population, was vastly different compared to the situation in the time period that followed. Between the mid 1990’s and today, the economies and power production in the above stated countries have increased drastically, working towards reaching the levels already obtained in 1990. This gives a somewhat unfair starting point compared to countries in Western Europe, countries that spent thirty years in development. Stating a 9.8% decrease as the government of Serbia did in their NDC, or a 20% increase proposed from BiH, means that these countries had 20 years of catching up to past levels of power production and emissions.

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Figure 23: Total emission reductions per scenario compared to the BAU in 2035 Figure 23 above shows the total emission reductions achieved in the analyzed scenarios. As previously mentioned, the ETS 20 addition is only applied to Serbia. The biggest percentual decrease between two scenarios can be observed between the NDC and RE scenario, where the model was less restricted when it comes to investments in RES. The sensitivity analysis made in the ETS scenario indicates that a 5-euro addition does not make any significant improvements, while 10 euros lower the emissions by an additional 13,7%. Since Serbia has the largest installed TPP capacity, the 20-euro ETS applied decreases the overall emissions for the basin countries with 7,4 % compared to the ETS 10 that was applied in all three countries. The total achieved emission reduction in the ETS 20 scenario by 2035 amount to 50,56% compared to the BAU. Aiding the reduction of emissions is the increased share of hydropower. The share of hydropower in the energy mix shifts from 41% in the BAU scenario in 2035, to 55% in the ETS 10 scenario. The rest is achieved through improved energy efficiency and additions of other RES technologies.

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Figure 24 – Share of RES located within the DRB in relation to total installed RES capacity Figure 24 illustrates the share of RES within the DRB compared to the total installed RES capacity by 2025 and 2035 in the analysed scenarios. Additionally, the figure shows the yearly power production per technology type for each RES technology in the DRB. The average share of RES in the NDC scenario during the modelling period is 44,9%, and as high as 58% in the ETS 10 scenario. These numbers indicate that the economically feasible potential for RES in the DRB is significant, considering that the basin area accounts for approximately 12,8% of the total area of the riparian countries. Another acquired insight from figure 24 is the fact that the RE, ETS 5 and ETS 10 scenario indicate a higher share of RES within the DRB in relation to the total installed RES capacity, if compared to the BAU and NDC scenario, despite having a larger overall installed RES capacity. Trade between the riparian countries is exemplified in the graphs below. Imports made to the transmission network of Bosnia and Herzegovina in order to meet the demand throughout the scenarios are shown in figure 25. Imports from Montenegro increase drastically in all scenarios compared to the BAU, while imports from Serbia vary between the scenarios.

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Figure 25: Average annual electricity imports to Bosnia and Herzegovina 2020-2035 Figure 26 below indicates the same numbers for Montenegro. A radical decrease in dependence on electricity from Bosnia and Herzegovina is indicated for all scenarios compared to the BAU. Imports from Serbia are negligible in all scenarios except the BAU scenario. 1000

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Figure 26: Average annual electricity imports to Montenegro 2020-2035 Obtained results indicate that Serbia will have a higher reliance on electricity imports from especially Montenegro, but also Bosnia and Herzegovina. Imports from BA are only lower in the NDC scenario compared to the BAU, while the imports from Montenegro increase in all scenarios.

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Figure 27: Average annual electricity imports to Serbia 2020-2035 Electricity trade among the riparian countries, as presented above, does not reflect the historical trends nor future trade projections. It can be observed that the amounts of traded electricity are far less compared to previous years. Another interesting observation is the direction of the power trade. Results obtained in the model indicate that Montenegro would be a net exporter with regards to its trade with Bosnia and Herzegovina and Serbia. This contradicts the current and past position Montenegro has had as a net importer. Reasons behind this type of trade patterns could be explained in the way the model was set up. Trade with countries outside the Drina River Basin was forced into the model and constrained to a level of trade corresponding to past volumes of power exchange over the borders. Another reason could be that the variable cost parameter for the trade conducted within the DRB was set to zero, allowing the model to fill the potential shortages in satisfying the demand in neighbouring countries. Table 2: Average imports and exports between the riparian countries and the rest of the region in the period between 2014-2018 (NOSBiH, 2020; Elektromreža Srbije, 2020) Imports to Serbia (GWh) Exports from Serbia (GWh) Hungary 699 632 Romania 2157 159 Bulgaria 1929 95 North Macedonia 215 1911 Albania 475 136 Montenegro 738 959 Bosnia and Herzegovina 441 1354 Croatia 92 1253 Imports to Bosnia and Exports from Bosnia and Herzegovina (GWh) Herzegovina (GWh) Serbia 1353 441 Montenegro 558 1937 Croatia 1398 3958 Imports to Montenegro Exports from Montenegro (GWh) (GWh) Serbia 959 738 Bosnia and Herzegovina 1937 558

Trade between the riparian countries and the rest of the region are shown in table 2 above. Since the trade was constrained to these values in the energy model, there were no changes between the scenarios or during the modelling period. For this reason, they were chosen not to be included in the graphs shown in section 3.

4. Conclusion Bosnia and Herzegovina, Montenegro and Serbia are changing their policies in order to align with EU regulations and emission standards associated with the power sector. However, no emission trading schemes, or carbon taxes are yet in place to reduce the emissions from the power sector in any of the above-named countries. Reconstructions and modernizations of thermal power plants have been conducted in all riparian countries, including projects for SO2 emission reductions and efficiency improvements. New power plants, with higher efficiency standards compared to the existing installed thermal capacity, are either under construction or in the planning phase. However, these efforts are still not in line with the EU goals. Thermal power plants are an investment that will last for at least 40 years. Even if the process of integrating the Western Balkan countries into the EU takes more time than previously planned, they are still highly likely to join the EU within the next four decades. For this reason, emissions and possible costs associated with ETS within the power sector must be taken into consideration even today, when new plants are in the planning phase. Evaluation of current policies indicate that the NDC goals do contribute to lower emissions for all the analysed countries. However, the reductions could be much greater if more effort was put towards increasing the share of RES and taking advantage of the hydropotential of not just the Drina river basin, but the whole hydropower potential found in the riparian countries. The Drina river and its tributaries play a vital role in reducing the dependence on coal and, provided with new interconnections between the countries, increased net transfer capacities could lead to more electricity being traded. Increased trade, as a result of higher shares of RES in the system in an integrated approach between the riparian countries, can keep the system costs manageable since this allows for more resource sharing across the borders. The analysis finds that, without energy policies such as the NDC goals, or emissions trading schemes, the emissions form the power sectors of Bosnia and Herzegovina, Montenegro and Serbia will not be in line with the EU Roadmap 2050, where an 80% reduction in GHG emissions is expected compared to the 1990 levels. The policy implications derived from the results shows that the strategies for reaching the NDC goals do contribute to lowered emissions, compared to the BAU. This indicates the importance of continued investments and implementations of RES technologies, in accordance with the country specific NDCs. In order to accelerate the decarbonization of the power sector in the basin countries, it is important to adopt the ETS as soon as possible, since the results found in this study confirm that added costs associated with emissions, increases the competitiveness of renewable energy sources.

5. Limitations and Future work Limitations in this study involve modelling of water flows in order to further investigate the effects climate change has on the water availability for hydropower plants within and outside the Drina River Basin. A more detailed analysis on the water availability could increase the certainty of estimation of available hydropower resources, considering seasonal variations and precipitation levels. As mentioned in the section regarding the trade between the DRB countries, the trading patterns with the neighbouring countries in the region were constrained in this model. Future work on this topic could, for this reason, include more realistic trading patterns, as well as site specific costs for power plants for each of the DRB countries. Additionally, research regarding the effects the ETS could have on the economy and unemployment rate within the DRB countries could be further investigated. Bosnia and Herzegovina, Montenegro and Serbia employ thousands of workers within the mining sector, as well as the power sector involving coal fired TPPs. Since the ETS is projected to have an impact on the shutdown of TPPs, the scheme could lead to increased unemployment in a region already characterized by high unemployment rates. As stated in the conclusion, the increase of RES in the power mix leads to increased trade and resource sharing across the borders. The question of energy security could therefore be further investigated, since increased shares of RES in the power mix of the DRB countries would reduce the dependence on coal, consequently decreasing the energy security of the riparian countries.

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7. Appendix A1. Thermal Power Plants in Bosnia & Herzegovina Planne El. Prod. Year of Installed d Power 5-year commission Capacity factor Capacit decom Fuel Type Owner Plant average and (CF) % y (MW) missio (GWh) reconstruction n EU require 1985, RiTE ment: reconstructed Ugljevi 300 1628,7 2030 Brown coal ERS 61,97 in 2010 and k RS 2013 plan: 2039 RiTE 300 1534.1 1983 2030 Lignite ERS 58,37 Gacko TE Kakanj 110 598 1969 2019 Brown coal EPBIH 62,05 Block 5 TE Kakanj 110 312 1977 2027 Brown coal EPBIH 32,37 Block 6 TE Kakanj 230 1342 1988 2030 Brown coal EPBIH 66,61 Block 7 TE Lignite/ Tuzla 110 473 1966 2023 EPBIH 49,08 Brown Coal Block 3 TE Lignite/ Tuzla 200 1196 1971 2024 EPBIH 68,26 Brown Coal Block 4 TE Lignite/ Tuzla 200 1004 1977 2027 EPBIH 57,31 Brown Coal Block 5 TE Lignite/ Tuzla 223 1160 1978 2030 EPBIH 61,59 Brown Coal Block 6 EFT – Rudnik i TE Termoelektrana 300 1887,5 2016 N/A Lignite 71.82 Stanari Stanari” d.o.o Stanari (Z.P. ‘RUDNIK I TERMOELEKTRANA UGLJEVIK’ A.D. UGLJEVIK, 2018a, 2018b) (ZP ‘Rudnik i Termoelektrana Gacko’ AD, 2018) (Centar za istraživačko novinarstvo, 2015b) (ETF - Rudnik i Termoelektrana Stanari d.o.o, 2018) (EPBIH, 2016) (NOS BIH, 2019)

A2. Planned Thermal Power Plants in Bosnia & Herzegovina Electricity Installed production Planned year Power Plant Capacity Fuel Type Owner per year of commission (MW) (GWh) Construction start 2017 (not KTG Zenica TE-To Zenica 300 1560 Brown Coal yet d.o.o commissioned) Construction start 2016 (not Lignite/ Comsar Energy TE Ugljevik 3 600 3371 yet Brown Coal RS d.o.o commissioned) Construction TE Tuzla start 2019 (not 450 2756 Lignite EPBIH Block 7 yet commissioned) Construction RiTE Rudnici mrkog start 2018 (not Lignite/ Banovići 350 1758 uglja “Banovici” yet Brown Coal Block 1 d.d. commissioned) TE Kakanj Construction 300 1755 Brown Coal EFBIH Block 8 start 2022 TE Kakanj A Construction kombi ciklus 200 1196 Brown Coal EPBIH start 2020 gasne turbine Announced Gacko II 350 N/A Lignite ERS construction (Centar za istraživačko novinarstvo, 2015b) (Balkan Energy Prospect, 2018b) (Čuta J. Galop P., 2016)

A3. Hydro Power Plants in Bosnia & Herzegovina 5-year Installed average Capacity Year of HPP capacity power River factor commission (MW) production (CF) % (GWh) 1965/2013 Trebinje I 171 400,4 Trebišnjica 64,06 (reconstructed) 1965/2013 Dubrovnik (G2) 126 707,1 Trebišnjica 64,06 (reconstructed) Čapljina 440 257,3 1979 Trebišnjica 6,99 170 659,3 1968 Neretva 47,04 Jablanica 180 716,1 1947-1958 Neretva 45,41 Grabovica 114 268,8 1982 Neretva 26,92 Salakovac 210 410 1977 Neretva 22,28 5-year Installed average Capacity Year of HPP capacity power River factor commission (MW) production (CF) % (GWh) Mostar 72 230,2 1987 Neretva 34,50 Jajce I 60 256,7 1957 Vrbas 48,83 Jajce II 30 84,8 1954 Vrbas 32,27 Bočac 110 275,8 1981 Vrbas 28,62 Bočac II 8.76 38,4 2018 Vrbas 50,00 Višegrad 315 974,2 1989 Drina 35,30 Mostarsko blato 60 98,9 2010 Lištica 18,82 Peć mlini 30.6 64,9 2004 Tihaljina 24,69 Total 2097,36 5424,9 (Hidroelektrane na Vrbasu a.d., 2019) (Elektroenergetika, 2019) (JP Elektroprivreda BiH, 2015) (HE na Drini, 2019) (JP Elektroprivreda HZHB, 2014) (Svetlana Jovanović, 2018b) (HEP Proizvodnja d.o.o., 2016) (NOSBiH, 2019)

A4. Planned Hydro Power Plants in Bosnia & Herzegovina Projected Installed Capacity Capital power Year of HPP capacity River factor cost production commission (MW) (CF) % M$/GW (GWh) Ustikovina 60,48 236,8 2021 Drina 44,7 2525 Vranduk 19,63 102 / Bosna 59,3 3216 Janjići 15,75 77,26 / Bosna 55,9 3943 Kovanići 9,1 46,2 / Bosna 57,9 4690 Una Kostela 13,7 73,5 / Una 61,3 1350 15 Small HPP on 24,5 99,9 / Neretvica 45,5 2040 Neretvica Modro Oko 3,74 12,22 / Tihaljina 37,3 2676 Klokun 3,25 12 / Tihaljina 42,1 2910 Koćuša 4,85 18,4 / Mlade 43,3 3016 4,99 21,81 / Trebižat 49,9 3020 Stubica 2,95 12,75 / Trebižat 49,3 2945 Dubrava 5 12,1 / Lištica 27,6 2706 Pumped power plant 64 242,96 2023 Šuica 43,3 1531 Vrilo (RENEXPO BIH, 2020) (Kozar & Livnjak, 2015)

A5. Wind Power Plants in Bosnia & Herzegovina Capacity Average factor Installed yearly Wind Power Year of (%) and capacity power Owner Plants commission Capital (MW) generation Cost (GWh) (M$/GW) Currently commissioned VE 37,26% 50,6 165,17 2018 EPHZHB Mesihovina 1782 Planned wind power plants 102 (10x3MW Relaks d.o.o VE Relaks / 2014 1402 and Vinjani, Posušje 36x2MW) 2014, 41,06% Poklečani 72 259 / delayed 1650 67,77% Velika Vlajna 32 190 / EPHZHB 1821 32,92% Borova Glava 52 150 / / 1650 30,73% Slovinj 130 350 / / 1650 32,62% Gradina 42 120 / / 1728 39,18% Derala 100,5 345 / / 952 38,05% Oštric 28,2 94 / / 1365 Eol prvi d.o.o Trusina 49,5 160 2019 36,89% Nevesinje Hrgud 48 125,7 2020 ERS 29,89% Koncig d.o.o Debelo Brdo 54 120-150 2020 28,53% Posušje HB Wind d.o.o Orlovača 42,9 120 2015 31,93% Livno - Baljci 48 / 2015 Kupres d.o.o / Tomislavgrad Balkan Energy Muščevača 63 / 2015 / Wind d.o.o Livno VE Ivonik d.o.o Ivovik 84 / 2015 / Sarajevo G&G Energija Derale 87 / 2015 / d.o.o Bihać JP Elektroprivreda Podveležje 48 119,8 2016 28,49% BIH d.d. Sarajevo Capacity Average factor Installed yearly Wind Power Year of (%) and capacity power Owner Plants commission Capital (MW) generation Cost (GWh) (M$/GW) JP Elektroprivreda Vlašić 50 / 2018 / BIH d.d. Sarajevo Vran-Dukić d.o.o Gradina 70 / 2019 / Tomislavgrad SUZLON WIND Ivan Sedlo 25.2 / 2019 ENERGY BH / d.o.o. Sarajevo F.L. Wind d.o.o Jelovača 36 85,68 2020 27,17% Tomislavgrad F.L. Wind d.o.o Tušnica 40 / / / Tomislavgrad WBL City Škadimovac 110 / / / project d.o.o. Kamen-dent Pakline I 48 / / / d.o.o. Kamen-dent Pakline II 48 / / / d.o.o. Pločno 36 / / Energy 3 d.o.o. / TLG d.o.o Galica 50 / / / Kameni-dent Kupres 1 48 / / / d.o.o Total Capacity 1695 / / / / (MW) (Centar za istraživačko novinarstvo, 2015a) (FERK, 2012) (EPHZHB, 2018) (Svetlana Jovanović, 2018a) (M. Čigoja, 2017) (Sarajevo Construction Agency, 2018) (Leo Jerkić, 2015) (NOSBiH, 2018) (Vrisak.info, 2019) (Vrisak.info, 2020) (RENEXPO BIH, 2020)

A6. Thermal Power Plants in Montenegro Year of El. Prod. Installed commission Planned Power 7-year Capacit and decomm Fuel Type Owner Plant average y (MW) reconstructio ission (GWh) n 1982, TE 225 1310 reconstructed N/A Lignite EPCG Pljevlja in 2009 (EPGC, 2019) (Elektroprivreda Crne Gore, 2019a)

A7. Hydro Power Plants in Montenegro 7-year Installed average Year of HPP capacity power River commission (MW) production (GWh) HPP Perućica 307 931 1960 Perućica HPP Piva 342 753 1976 Piva Small HPPs 5,7 46 1952-1955 Zeta (Elektroprivreda Crne Gore, 2019c)

A8. Planned hydropower plants in Montenegro Theoretical Theoretical Capital power power Year of cost HPP River potential generation commission (M$/GW) (MW) (GWh) HPP Komarnica 162 232 No info Komarnica 1615 HPP Bukovica 3,2 14,2 N/A Komarnica / HPP Ibrištica 3,1 13,8 N/A Morača / HPP Štitarička 0,9 2,9 N/A Tara / (Vlada Crne Gore, 2015) (Spasić, 2019a) A9. Wind power plants in Montenegro Average Installed yearly power Year of Wind Power Plants capacity Capacity Factor (%) generation commission (MW) (GWh) Currently commissioned VE Možura 46 120 2019 29,77 VE Krnovo 72 200 2017 31,7 Planned wind power plants No current plans on wind power plant expansion (Ministry of Economy CG, 2019) A10. Solar power plants in Montenegro Average Installed Solar Power yearly power capacity Year of commission Owner Plants generation (MW) (GWh) Currently commissioned Currently no installed power plants connected to the grid Planned solar power plants Construction starts 2020, 18-month construction time for Fortum & EPCG Briska Gora 250 450 the first installation of (49% each), 2% 50MW and 36-month Sterling & Wilson construction time for the additional 200MW. (Balkan Green Energy News, 2019)

A11. Total capacity and electricity production in Serbia 2009-2017 Electricity Electrici sold Bought Installed Total ty sold Coal outside of electricity from Year capacity productio in EPS production (t) EPS outside of EPS (MW) n (GWh) Serbia Serbia Serbia (GWh) (GWh) (GWh) 2017 7355 34004 39064457 33533 1941 1492 2016 7326 36461 37652520 33371 3998 919 2015 7304 35661 37029091 33729 2957 1042 2014 7124 31963 29204294 33575 1114 2611 2013 7124 37433 39513474 34009 4641 2207 7124 34509 33589 (8359 (39892 (39239 2012 37513241 No data No data with with with Kosovo) Kosovo) Kosovo) 7124 36050 34450 (8359 (41284 (40215 2011 40290397 No data No data with with with Kosovo) Kosovo) Kosovo) 7124 35855 34073 (8359 (40980 (39819 2010 37195145 No data No data with with with Kosovo) Kosovo) Kosovo) 7124 36112 33292 (8359 (41122 (38920 2009 37778600 No data No data with with with Kosovo) Kosovo) Kosovo) (Electric Power Industry of Serbia, 2018)

A12. Commissioned thermal power plants in Serbia Year of El. Prod. Installed commission Power 9-year Capacity Factor Capacit and Fuel Type Plant average % y (MW) reconstructio (GWh) n B1: 1970 TE B2: 1970 Nikola B3: 1976 Tesla A 1622 9706 Lignite 69,37 B4: 1978 (6 B5: 1979 blocks) B6: 1979 TE Nikola B1: 1983 Tesla B 1220 7604 Lignite 74,83 B2: 1985 (2 blocks) B1: 1956 TE B2: 1957 Kolubar 216 852 B3: 1961 Lignite 45 a (5 B4: 1961 blocks) B5: 1979 TE 108 475 1969 Lignite 50,3 Morava TE Kostola B1: 1967 281 1928 Lignite 78,3 c A (2 B2: 1980 blocks) TE Kostola B1: 1987 632 3882 Lignite 70,1 c B (2 B2: 1991 blocks) Average working hours on the Total 4079 24449 / / grid per block: 173 615 (Electric Power Industry of Serbia, 2018)

A13. Planned thermal power plants in Serbia Year of El. Prod. Installed commission Planned Power 9-year In the Drina Capacit and decomm Fuel Type Plant average river basin y (MW) reconstructio ission (GWh) n Planned plants TE Kolubar 700 N/A 2021 N/A Lignite No a B TE Nikola 350 N/A 2026 N/A Lignite No Tesla B3 Power plants under construction TE Kostola 350 N/A 2026 N/A Lignite No c B3 (Balkan Energy Prospect, 2018a)

A14. Hydropower plants in Serbia 9-year average Installed Capacity power Year of Within HPP capacity River Factor production commission the basin (MW) % 2009-2017 (GWh) HPP Đerdap 1 1113 5396 1970-1972 Danube No 56 1985-1987 HPP Đerdap 2 270 1531 1998 Danube No 64,7 2001 Vlasinske HPP 129 301 1954-1978 Vrla No 26,6 Visočica, Gostuška HPP Pirot 80 111 1990 reka, No 15,8 Belska reka HPP Bajina 420 1500 1966-1968 Drina Yes 40,7 Bašta PHE Bajina 614 641 1982 Drina Yes 11,9 Bašta HPP Zvornik 111 464 1955-1958 Drina Yes 51,4 HPP 18 63 1954-1957 Morava No 60,66 Elektromorava HE Potpeč 51 201 1967-1970 Lim Yes 45 9-year average Installed Capacity power Year of Within HPP capacity River Factor production commission the basin (MW) % 2009-2017 (GWh) Bistrica HPP Bistrica 1960 and HPP Kokin 124 401 Lim Yes 36,9 Kokin Brod Brod 1962-1967 HPP 36 60 1979 Lim Yes 19 Small HPPs 20 43 N/A N/A N/A 1348 MW installed Total 2986 10714 N/A N/A capacity / within the basin (45,46%) (Electric Power Industry of Serbia, 2018)

(Electric Power Industry of Serbia, 2007)

A15. Wind power plants in Serbia Installed Average yearly Solar Power Year of capacity power generation Owner Plants commission (MW) (GWh) Currently commissioned Devreč 0,5 / 2012 Hydrowind Čibuk 1 158 475 2019 Tesla Wind Košava 1 69 189 2019 MK FINTEL Kovačica 104,5 300 2019 SOLAVERIS IZBISTE 6.6 / 2016 MK FINTEL 8 25 2018 ELICIO Kula 9,9 / 2016 Vetropark Kula (Balkan Energy Prospect, 2020) (Jovanović, 2019a) (Jovanović, 2019b) Planned Wind Power Plants Košava 2 52 / / MK FINTEL Maestral 572 / / MK FINTEL Ring Lipar 1 10 / / MK FINTEL Lipar 2 10 / / MK FINTEL (Poslovni dnevnik, 2019)

A16. Incentives for power production from renewable energy sources in Republic of Serbia. Maximum Type of power Installed Incentive effective Number producing capacity P purchase price operating time technology (MW) (c€/kWh) (h) Hydropower 1 / / plants 1.1 / Up to 0,2 12,60 1.2 / 0,2-0,5 13,933-6,667*P 5000 in the year 1.3 / 0,5-1 10,60 of the incentive 1.4 / 1-10 10,944-0,344*P period 1.5 / 10-30 7,5 On the existing 1.6 distribution Over 30 6 network Power plants 2 / / biomass 8600 in the year 2.1 / Up to 1 13,26 of the incentive 2.2 / 1-10 13,82-0,56*P period 2.3 / Over 10 8,22 Biogas Power 3 / / Plants 8600 in the year 3.1 / 0-2 18,333-1,111*P of the incentive 3.2 / 2-5 16,85-0,370*P period 3.3 / Over 5 15 Landfill gas and gas from 8600 in the year 4 municipal / 8,44 of the incentive wastewater period treatment plants 9000 in the year Wind Power 5 / 9,2 of the incentive Plants period 6 Solar Power Plants / / On buildings, 6.1 / 14,60-80*P 1400 in the year up to 0,03 of the incentive On buildings, 6.2 / 12,404-6,809*P period up to 0,03-5 6.3 / On the ground 9 8600 in the year Geothermal Power 7 / 8,2 of the incentive Plants period Power plants with 8600 in the year high efficiency 8 / / of the incentive combined period production of Maximum Type of power Installed Incentive effective Number producing capacity P purchase price operating time technology (MW) (c€/kWh) (h) electricity and total natural gas 8.1 / Up to 0,5 8,2 8.2 / 0,5-2 8,447-0,493*P 8.3 / 2-10 7,46 8600 in the year Waste Power 9 / 8,57 of the incentive Plants period (Vučić, 2016)

TRITA TRITA-ITM-EX 2020:69

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