Albania and North Macedonia: the Evolution of the Electricity System Under the Scope of Climate Change

Albania and North Macedonia: The evolution of the electricity system under the scope of climate change

Author: Ioannis Thermos – [email protected] Student MSc Sustainable Energy Engineering

Supervisor: Youssef Almulla – [email protected]

Master of Science Thesis

KTH School of Industrial Engineering and Management

Energy Technology TRITA-ITM-EX 2019:420

Division of Energy Systems Analysis

SE-100 44 STOCKHOLM

1

Master of Science Thesis TRITA-ITM-EX 2019:420

Albania and North Macedonia:

The evolution of the electricity system under the scope of climate change

Ioannis Thermos

Approved Examiner Supervisor

14/06/2019 Francesco Fuso-Nerini Youssef Almulla Commissioner Contact person

[email protected]

2

Abstract

Albania and North Macedonia, along with the rest of the Balkan region, have been developing since the early nineties and have achieved an upper-middle income status. Along with this development, the energy demand grew as well. However, the current electricity system in these two countries has not significantly evolved during the past 35 years since the majority of the infrastructure was built during the Soviet era. It is therefore crucial to upgrade the existing system to avoid power shortages and to reduce electricity losses. At the same time, the effects of climate change are becoming more and more obvious and pose a direct threat to the affordability of electricity generated by large hydropower plants during the last decades. This study examines the evolution of the electricity sector of Albania and North Macedonia for the next 20 years. It will put to the test the current electricity system extrapolated into the future, the changes that might be necessary to be made to tackle the effects of climate change and the nations’ commitments to reduce the impacts of a changing climate. The first step is to understand the energy system in each country, starting with their available resources, historical capacities, electricity demand etc. Both countries are almost identical in terms of sizes with each one having an electricity supply system of around 2 GW in capacity and a final electricity consumption of 5,563 GWh and 6,104 GWh in 2017 for Albania and North Macedonia respectively. On the other hand, the systems differ qualitative. To be more specific, almost 100% of Albania’s generation capacity is hydropower, while the North Macedonian system is based mainly on lignite (coal power) and to a smaller extend on hydropower. Since this study focuses on the effects of climate change on electricity produced from hydropower, a correlation was made to link the reduced precipitation with river flow and in the end hydropower generation. The correlation results show that an average decrease in precipitation of 1.6% and 1.9% can be expected in 2037 compared to current levels, that will lead to a decrease in hydropower generation of 3.3% and 4% for Albania and North Macedonia respectively. Then the cost-optimization model, using OSeMOSYS, was created to depict those changes. First, the business-as-usual scenario, used as a reference scenario, extends the current situation into the future. In a few words, Albania and North Macedonia will invest in hydropower and wind capacity respectively to cover the increasing electricity demand. Secondly the Climate Change scenario was investigated, where the decrease in precipitation was considered, but according to the model, electricity imports will increase instead of investing in additional capacity. The third scenario was the Increased Renewables scenario, where the countries fulfil their obligations to install more renewable capacity and diversify their electricity mix. This approach will reduce their vulnerability to climate change and electricity imports but will come at a great investment cost for the countries’ economy. Overall, results show that the regional power sector will be affected by climate change. However, the biggest challenge will be to tackle the annual and seasonal variation in hydropower generation rather than the general decreasing trend in precipitation over the years. To be more specific, annual hydropower generation can even double between a dry and a wet year in some cases. However, under the climate change scenario annual hydropower generation will only decrease by 5.7% and 2.7% during a wet and a dry year compared to the business-as-usual scenario respectively.

3

Acknowledgements

First, I would like to thank the supervisor of my thesis Youssef Almulla, PhD candidate in the division of Energy System Analysis (dESA), for his assistance and support. Also, I would like to express my gratefulness to Mark Howells for inspiring me to choose the track of Energy Systems Analysis during my Masters programme. Likewise, I am grateful that I have worked with Francesco Fuso-Nerini, Francesco Gardumi, Georgios Avgerinopoulos, Hauke Henke, Ioannis Pappis and the rest of the dESA team. Special credits go to Alban Kuriqi, PhD candidate in the University of Lisbon, for providing me with valuable precipitation and river flow data for Albania. Also, I would like to thank my colleges and friends for their help and companionship during this journey. Finally, I would like to deeply thank my parents who are always by my side and support me in my goals.

4

Table of Contents

Abstract ...... 3 Acknowledgements ...... 4 Table of Contents ...... 5 List of Figures ...... 7 List of Tables ...... 8 Abbreviations ...... 9 1. Introduction ...... 11 1.1. Objectives ...... 13 1.2. Tool Description ...... 13 1.3. Methodology ...... 13 2. Country Overview, Energy and Climate Situation...... 14 2.1. Albania ...... 14 2.2. North Macedonia ...... 16 2.3. Climate Change ...... 18 2.3.1. Change in Precipitation ...... 19 2.3.2. Impacts on Electricity Generation ...... 19 3. The OSeMOSYS Model ...... 21 3.1. Model Description ...... 21 3.2. Reference Energy System ...... 21 3.3. Main Parameters ...... 23 3.4. Electricity Demand ...... 23 3.5. Generation Capacity ...... 24 3.6. Electricity Generation ...... 25 3.7. Power Generation Constraints and Targets ...... 26 3.8. Power Generation Costs ...... 26 3.9. National Grid and Interconnections Assumptions ...... 28 3.10. Climate Change Impact Assumptions ...... 29 4. Scenario Description ...... 32 5. Results ...... 33 5.1. Business As Usual Scenario ...... 33 5.1.1. Albania ...... 33 5.1.2. North Macedonia ...... 35 5.1.3. Economic and Environmental Impact ...... 37 5.2. Climate Change Scenario ...... 39 5.2.1. Albania ...... 39

5

5.2.2. North Macedonia ...... 41 5.2.3. Economic and Environmental Impact ...... 43 5.3. Increased Renewables Scenario ...... 44 5.3.1. Albania ...... 44 5.3.2. North Macedonia ...... 46 5.3.3. Economic and Environmental Impact ...... 48 6. Conclusions ...... 51 7. Limitations and Future Work ...... 52 8. Bibliography ...... 53 Appendix A: Technical Parameters ...... 58 Appendix B: Electricity Demand, Hydrological and Economical Parameters ...... 77 Appendix C: Results ...... 83

6

List of Figures

Figure 1: Final electricity consumption in GWh, (World Bank, 2017a) (World Bank, 2017b)...... 11 Figure 2: Albania total primary energy supply in 2016, (IEA, 2018a)...... 14 Figure 3: Total operational capacity in MW in Albania...... 15 Figure 4: North Macedonia total primary energy supply 2016, (IEA, 2018b)...... 16 Figure 5: Total operational capacity in MW in North Macedonia...... 17 Figure 6: Average monthly precipitation in Albania and North Macedonia (World Bank, 2019). 19 Figure 7: Reference electricity system of Albania...... 22 Figure 8: Reference electricity system of North Macedonia...... 22 Figure 9: Final electricity demand projections in GWh...... 24 Figure 10: Average historical (1986-2005) precipitation and projections for Vau Dejes and Kukes stations...... 30 Figure 11: New and total capacity in Albania under the BAU scenario...... 33 Figure 12: Electricity mix in Albania under the BAU scenario...... 34 Figure 13: New and total capacity in North Macedonia under the BAU scenario...... 35 Figure 14: Electricity mix in North Macedonia under the BAU scenario...... 36 Figure 15: Aggregated discounted capital investments in million Euros under the BAU scenario...... 37 Figure 16: Total system operating cost under the BAU scenario...... 38 Figure 17: New and total capacity in Albania under the Climate Change scenario...... 39 Figure 18: Electricity mix in Albania under the Climate Change scenario...... 39 Figure 19: Hydropower generation in Albania...... 40 Figure 20: New and total capacity in North Macedonia under the Climate Change scenario...... 41 Figure 21: Electricity mix in North Macedonia under the Climate Change scenario...... 41 Figure 22: Hydropower generation in North Macedonia...... 42 Figure 23: Aggregated discounted capital investments in million Euros under the Climate Change scenario...... 43 Figure 24: Total system operating cost under the Climate Change scenario...... 43 Figure 25: New and total capacity in Albania under the Increased Renewables scenario...... 44 Figure 26: Electricity mix in Albania under the Increased Renewables scenario...... 45 Figure 27: New and total capacity in North Macedonia under the Increased Renewables scenario...... 46 Figure 28: Electricity mix in North Macedonia under the Increased Renewables scenario...... 47 Figure 29: Discounted capital investments in million Euros in Albania under the Increased Renewables scenario...... 48 Figure 30: Discounted capital investments in million Euros in North Macedonia under the Increased Renewables scenario...... 49 Figure 31: Total system operating cost under the Increased Renewables scenario...... 49 Figure 32:Losses in the distribution grid of Albania (ERE, 2016)...... 76 Figure 33: Electricity demand profile in Albania and North Macedonia...... 77 Figure 34: Average monthly values for flow and precipitation in Vau Dejes and Kukes station. . 78

7

List of Tables

Table 1: Electricity generation targets from RES in GWh approximated from North Macedonia's NREAP, (MoE, 2015) ...... 18 Table 2: Techno-economic parameters for power generation technologies (Verbund, 2008) (Xhafa, 2009) ( Causevski & Nikolova, 2010) (IEA, 2010) (MoE, 2010) (World Bank, 2013) (Devoll Hydropower, 2014)) (Mezősi & Szabó, 2015) (KESH, 2017) (Mezősi, et al., 2017) (DNV GL, 2018) (ELEM, 2018) (Cingoski & Nikolov, n.d.)...... 27 Table 3: Interconnection capacities and quantities...... 28 Table 4: Projections on precipitation, river flow and hydropower generation...... 31 Table 5: Projected capacity factors for hydropower plants...... 32 Table 6: Renewable capacity targets for Albania and North Macedonia...... 32 Table 7: Hydropower plants in Albania above 10 MW...... 58 Table 8: Hydropower Plants in Albania below 10 MW...... 66 Table 9: Hydropower plants in North Macedonia above 10 MW...... 66 Table 10: Hydropower plants in North Macedonia Below 10 MW...... 72 Table 11: Thermal and renewable installations excluding hydropower...... 72 Table 12: Existing and planned interconnections involving Albania and North Macedonia...... 73 Table 13: Specifications for major hydropower plants in Albania...... 74 Table 14: Specifications for major hydropower plants in North Macedonia...... 75 Table 15: Costs for proposed HPPs (Verbund, 2008) (Xhafa, 2009) ( Causevski & Nikolova, 2010) (MoE, 2010) (Devoll Hydropower, 2014) (KESH, 2017) (ELEM, 2018) (Cingoski & Nikolov, n.d.)...... 80 Table 16: Costs for various power plants (MoE, 2010) (Mezősi & Szabó, 2015) (Mezősi, et al., 2017) (ELEM, 2018)...... 81 Table 17: Historical electricity import and export prices...... 82 Table 18: Electricity production and trade in Albania under the BAU scenario...... 83 Table 19: Electricity production and trade in North Macedonia under the BAU scenario...... 83 Table 20: Electricity production and trade in Albania under the Climate Change scenario...... 84 Table 21: Electricity production and trade in North Macedonia under the Climate Change scenario...... 84 Table 22: Electricity production and trade in Albania under the Increased Renewables scenario.85 Table 23: Electricity production and trade in North Macedonia under the Increased Renewables scenario...... 85

8

Abbreviations

AL: Republic of Albania BAU: Business-as-Usual BG: Republic of Bulgaria Domestic Supply: Electricity generation plus imports minus exports ELEM: State owned utility in North Macedonia EU: European Union FiT: Feed-in-Tarif scheme FYROM.: Former Yugoslav Republic of Macedonia HFO: Heavy Fuel Oil HPP: Hydro Power Plants IEA: International Energy Agency IPCC: Intergovernmental Panel on Climate Change GDP: Gross Domestic Product GHG: Greenhouse Gases GR: Hellenic Republic CHP: Combined Heat and Power Plant GWh: Gigawatt hour KO: Republic of Kosovo kt: kilotons ktoe: kilotons of oil equivalent kV: kilovolt kW: kilowatt LHPP: Large (>100 MW) Hydro Power Plant mm: millimeters m/s: meters per second m2: square meter MK: Republic of North Macedonia MO: Montenegro

MtCO2: Million tons of Carbon Dioxide

MtCO2e: Million tons of Carbon Dioxide equivalent MW: megawatt

9

MWh: megawatt hour NATO: North Atlantic Treaty Organization Net electricity imports: Electricity imports minus electricity exports NG: Natural Gas NGCC: Natural Gas Combined Cycle Plant NREAP: National Renewable Energy Action Plan OSHEE: Albanian Electricity Distribution System Operator PV: Photovoltaics RES: Renewable Energy Sources ROR: Run-of-River Plants RS: Republic of Servia SHPP: Small (<10 MW) Hydro Power Plant STT: Steam Turbine Plant TAP: Trans Adriatic (Natural Gas) Pipeline TJ: Terajoule TPP: Thermal Power Plant W: Watt UN: United Nations

10

1. Introduction

Albania and North Macedonia are two neighboring countries located in the Western Balkans. Both countries have been developing since the early nineties, when they acquired their current form, and achieved an upper-middle-income status. From a combined GDP of $3.5 billion in 1993 they reached $24.5 billion in 2017. The population in Albania has decreased, due to poverty and unemployment, from 1990 by 400,000 people to 2.88 million in 2017 (Barjaba & Barjaba, 2015). On the other hand, North Macedonians have slightly increased from 1990 by 87,000 people to 2.1 million in 2017. (World Bank, 2017a) (World Bank, 2017b) The consumption of electricity has been following at a slower pace the growing trend of the GDP. Electricity consumption peaked in 2013 and 2011 for Albania and North Macedonia respectively as seen in Figure 1. The average annual electricity consumption has been growing on average with 2.35% in Albania and 0.46% in North Macedonia since 2000. However, a decline in consumption can be noticed in Figure 1 during the last years. This was the case due to the Greek economic crisis which impacted hundreds of thousands of Albanian and North Macedonian emigrants living in Greece from 2008 onwards (Sufaj, 2015). On the other hand, ministries of energy in both countries forecast an increase in annual demand ranging from 1.3% to 3.1% for Albania and from 0.7% to 2.1% for North Macedonia (MoE, 2010) (MoE, 2017) (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015) (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017).

Final Electricity Consumption (GWh) 9000 8000 7000 6000 5000 4000 3000 2000

1000

2004 2015 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2016 2017

Albania North Macedonia

Figure 1: Final electricity consumption in GWh, (World Bank, 2017a) (World Bank, 2017b).

Natural resources are necessary to cover the projected increase in energy demand. Albania has significant oil and gas reserves with 220 million barrels and 5.7 billion m3 respectively (Albpetrol, 2018). On contrary, North Macedonia does not have any known oil and gas reserves but has significant lignite reserves of 2.7 billion tons (Ekounia, n.d.). Nevertheless, both countries have renewable energy potential, mainly hydro, wind, solar and biomass (MEI, 2016a) (MoE, 2015). Despite the fact that state-support schemes are available, there is still not much progress made towards a more diversified energy mix. The combined capacity of wind, solar and biomass installations for electricity generation is below 70 MW in both countries (ELEM, 2018) (Spasić, Balkan Green Energy News, 2019) (EC, 2018) (BGEN, 2017a). On the other hand, both countries are abundant with water resources and represent some of the most water-rich nations in Europe (MM, 2017). Besides the use of water for irrigation, drinking etc., water is vital for electricity generation. As a matter of fact, all domestically produced electricity

11 in Albania was generated from hydro resources while North Macedonia generated one third of its electricity from hydropower. According to three studies there are at least 250 HPPs in Albania and North Macedonia with a combined capacity of around 2.7 GW (MM, 2017) (Lazaj & Xhelilaj, 2017) (EC, 2018). The vast majority (89%) consists of SHPP, in terms of hydropower installations, and most of them were constructed after 2005 due to the feed-in tariff scheme implemented. However, the state-support schemes are expected to stop after 2020 and therefore the interest in such investments will diminish significantly (MM, 2017). Nevertheless, the majority of the installed capacity and electricity generated is attributed to 27 medium and large size HPP, with a combined capacity of 2,236 MW, installed in Albania and North Macedonia. Most of that capacity was put into operation in the early seventies or before. It is evident that hydropower is vital for the region. It provides affordable and clean electricity to the people and helps grow the national economy. However, climate change has a profound effect on precipitation among other things. Climate change impacts are expected to range from reduced precipitation to extreme weather events, such as floods (Chenoweth, et al., 2011). Therefore, heavy reliance on hydropower, such as in the case of Albania, poses potential threats to energy security and security of energy supply (Fida, et al., 2009) (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010). At the same time, North Macedonia plans to increase its hydropower assets not only to increase energy security, but also to reduce its GHG from fossil fuel combustion (MoE, 2010).Additionally, electricity imports not only increase energy dependency but also increase the end-use electricity price (MoE, 2017). This study begins with an introduction on the current energy status of Albania and North Macedonia, as well as the current issues the national electricity system is facing and its impact currently and in the future. A more in depth and country specific analysis is conducted in chapter two. Specifically, the current electricity system situation and the availability of natural resources are provided. Also, the current electricity generation portfolio and theoretical boundaries regarding new additions are analyzed. Furthermore, this chapter focuses on emissions and the renewable energy capacity targets that these countries have set. Moreover, climate change and specifically the alternation in precipitation patterns are analyzed, while emphasizing the impacts on domestic power generation assets. Chapter three focuses on the OSeMOSYS software and the model developed. The reference electricity system of each country is presented which gives a simplified picture of the electricity system. Additionally, all the assumptions utilized in this study are presented in chapter three. Specifically, assumptions regarding the electricity demand profiles and projections are stated. Also, the assumptions regarding the technical and economical parameters of the generation, transmission and distribution technologies were provided. Chapter four includes an explanatory analysis of the three alternative scenarios designed for this study. The business-as-usual scenario (reference scenario) projects the current state of affairs into the future. The Climate Change scenario takes into account a reduction in precipitation through the modelling period according to the national climate change scenarios. Finally, under the Increased Renewables scenario, the energy policy targets for new renewable capacity will be achieved, while dealing with the effects of climate change. The results obtained from the OSeMOSYS model are presented and analyzed in chapter five. These include, additions to the generation portfolio, variations in the generation mix, electricity trade, investment and operational costs and the environmental impact of power generation. Chapter six draws conclusions according to the results extracted and the issues discussed in the introduction. Also, it provides an outlook of the future electricity sector in Albania and North Macedonia. Finally, chapter seven focuses on the limitations and difficulties that occurred during this study as well as the opportunities for future research.

12

1.1. Objectives

The aim of this study it to depict the electricity generation and supply system of Albania and North Macedonia in a time period of 2017-2037. More specifically, this study focuses on the impacts of climate change to hydropower electricity generation and alternative pathways to maintain security of electricity supply while, keeping on track with the countries’ commitments to increase the share of renewable energy in the electricity mix.

1.2. Tool Description

There are lots of tools to depict and simulate an energy system. However, this study focuses also on optimization. Optimization is the process of solving a problem according to a particular factor. One of the most common sub-categories of optimization is cost optimization. Therefore, a cost optimization tool should provide the highest or lowest system cost without neglecting the limitations and targets set. One such tool is OSeMOSYS, which stands for Open Source Energy Modeling System. It is a dynamic, bottom-up systems optimization tool, suitable for both academic and industry applications. It is primarily used for energy systems modeling but can also be used for water modeling and other applications. In this case, OSeMOSYS runs simulation to satisfy the objective function, achieve the lowest system cost in other words within a set of restrictions related to the energy system.

1.3. Methodology

To achieve this objective, a linear cost optimization model was developed using OSeMOSYS software. This model represents and optimizes the current electricity system as well as planned future additions to it for both Albania and North Macedonia. Additionally, different scenarios were developed to reflect the potential impact of climate change to the electricity supply system and test the countries’ electricity import dependency. Also, the effects of planned policy measures to the electricity mix were examined along with their contribution to reduce the environmental impact of power generation.

13

2. Country Overview, Energy and Climate Situation

2.1. Albania

The Republic of Albania is located in Southeast Europe. It is bordered by the Adriatic and Ionian Sea on the west, Montenegro to the northwest, Kosovo to the northeast, North Macedonia to the east and Greece to the south. The modern state of Albania emerged in 1912. After World War II, the communist state of People’s Socialist Republic of Albania was founded, which dissolved in 1991. Since then, the country has been developing to reach a upper-middle-income status in 2008, while advancing its European Union integration agenda (WB, 2018). Albania has an area of 28,748 km2 and a population of 2.88 million people. It has the 10th largest proven oil reserves in Europe. In 2016, Albania produced 1,056 kt of oil and 39 ktoe of natural gas. The Total Primary Energy Supply (TPES) reached 2,250 ktoe in 2016.

Albania Total Primary Energy Supply 2016

4,1% 12,0%

29,7% 54,2%

Oil Hydro Biofuel Other

Figure 2: Albania total primary energy supply in 2016, (IEA, 2018a).

The Total Final Consumption (TFC) was 1,986 ktoe in 2016, 43.5% of this amount was consumed in the transport sector, 15% was consumed in the industry sector and 41.5% was consumed in residential and other sector. (IEA, 2016) The total electricity generation was 7,782 GWh in 2016. The electricity consumption stood at 2.2 MWh per capita in 2016. (IEA, 2016) Currently, almost all domestic electricity generation comes from hydropower. Due to the variability in hydropower generation, the country still faces frequent power shortages and relies heavily on electricity imports from neighboring countries (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010). As a matter of fact, in a dry year, such as 2017, electricity generation fell by 47% compared to the previous year (INSTAT, 2018). Water resources are the most important natural resources in the country. The hydropower potential is estimated at 4,500 MW, with less than half of that being exploited. Additionally, Albania has significant solar potential assessed at 1,500-1,700 KWh/m2 per year with an average duration of 2,485 hours per year or 26 GW of photovoltaic capacity (Fida, et al., 2009) (UNDP, 2012a). Furthermore, a series of zones along the Adriatic coastline have been identified with an average annual wind speed of 6-8 m/s and energy density of 250-600 W/m2. The current capacity limit for the Albanian electricity grid to absorb and transmit electricity produced from wind turbines is estimated to be 180-200 MW. However, the total potential of wind power in Albania is estimated at 1.5-2 GW. (MEI, 2016a)

14

Total Operational Capacity (MW)

1 7

441

1488

RESERVOIR ROR SOALR WASTE

Figure 3: Total operational capacity in MW in Albania.

The hydropower capacity installed in Albania varies from 1,935 MW up to 2,069 MW depending on the source (MM, 2017) (EC, 2018) (MEI, 2016a) (Lazaj & Xhelilaj, 2017). The difference in figures could be attributed to the large number of newly constructed privately owned SHPPs during the past few years. According to the Ministry of Energy and Industry, 90 SHPPs were constructed until 2015, but only 37 were operational (MEI, 2016a). The majority (1,488 MW) of the HPPs are reservoir type, while the rest are run-of-river powerplants. In total, 162 HPPs are found to be completed as of early 2019 and were presented in Appendix A. Additionally, a photovoltaic park of 1 MW was constructed in 2014 (MEI, 2016b). However, no wind farms are reported as of early 2019. Furthermore, two waste incineration plants were recently constructed with capacities of 2.8 MW and 3.8 MW (BGEN, 2016) (BGEN, 2017a). Last of all, two thermal powerplants are connected to the grid. TPP Fier has a capacity of 186 MW and comprises of residual oil generators but stopped operating as of 2007. TPP Vlora is a 97 MW combined cycle powerplant that was constructed in 2011 but has not operated yet (KESH, 2016). However, Albania has launched a tender in 2019 to supply the plant with natural gas from TAP (Jonuzaj, Albania invites bids for PPP/concession deal on Vlora TPP, construction of gas link to TAP, 2019). Albania’s emissions represent less than 0.02% of global emissions or less than a quarter per capita emissions compared to high-income countries (Albania, 2015). Total direct GHG emissions have remained fairly stable during the last decade, 8.86 MtCO2e, 8.4 MtCO2e and 8.31 MtCO2e in 2005, 2009 and 2014 respectively (Albania, 2015) (Bruci, Islami, & Kamberi, 2016). Roughly 60% of these values represent CO2 emissions or 6.16 MtCO2 in 2016, with more than half (3.67 MtCO2) attributed to fuel combustion (Albania, 2015) (IEA, 2018a). Currently, the transport and energy sectors are the most emission-intensive sectors (Bruci, Islami, & Kamberi, 2016). However, domestic electricity production does not produce directly GHG emissions. Albania is a non-Annex I country, meaning that it does not subject to any mandatory GHG reduction. However, in the context of the EU accession process, Albania has set quantified objectives and submitted its NDC. According to that, Albania commits to reduce CO2 emissions by 11.5% until 2030 compared to 2016 levels, which corresponds to a reduction of 708 ktCO2 (Albania, 2015). As mentioned before, Albania generates 100% of its electricity from RES. However, due to its dependency on hydropower, and therefore vulnerability to climate change, the government plans to diversify the country’s electricity mix. According to the Albanian NREAP, the capacity targets until 2020 are 750 MW, 50 MW and 70 MW in SHPP, photovoltaic and wind installations accordingly (MEI, 2016a). However, the capacity target for photovoltaics has been increased to 120 MW by 2020 (PVEurope, 2018). The known installed capacity of SHPPs is 270 MW (MM, 2017) (Lazaj & Xhelilaj, 2017), according to other reports it could even be 404 MW as of early 2019

15

(EC, 2018). In any case, achieving the target for SHPP will require drastic policy measures. Even though Albania launched a tender for a 50 MW solar park with possible extension to 100 MW in August 2018 (Jovanović, Albania invites bids to build 50 MW PV power station with support measures, plus up to 50 MW without, 2018a), achieving the 120 MW target until 2020 seems very optimistic. Furthermore, Albania has granted more than 2.5 GW of licenses for construction, installation and generation of wind farms (MEI, 2016a). However, the grid can currently absorb no more than 200 MW of wind power (MEI, 2016a). The wind power target of 70 MW until 2020 seems optimistic, given the fact that Albania does not have any wind capacity installed.

2.2. North Macedonia

The Republic of North Macedonia, as of January 2019, is a landlocked country in Southeast Europe. It is bordered by Albania on the west, Kosovo to the northwest, Serbia to the northeast, Bulgaria to the east and Greece to the south. The country was part of Yugoslavia until 1991 when it declared its independence. North Macedonia is characterized as an upper-middle-income country and is a candidate country to join NATO and the EU (World Bank, 2017b).

North Macedonia has an area of 25,713 km2 and a population of 2.1 million people. It has not any known significant oil or gas reserves, but it is a lignite producer with 5,043 kt produced in 2017 (IEA, 2018b) (MAKSTAT, 2018). The Total Primary Energy Supply (TPES) reached 2,488 ktoe in 2016.

North Macedonia Total Primary Energy Supply 2016

7,1% 7,2%

8,0% 42,7%

35,0%

Oil Coal Biofuel Other RES Natural Gas

Figure 4: North Macedonia total primary energy supply 2016, (IEA, 2018b).

The Total Final Consumption (TFC) was 1,974 ktoe in 2016, 36.8% of this amount was consumed in the transport sector, 23.3% was consumed in the industry sector and 39.9% was consumed in residential and other sector. (IEA, 2018b) The total electricity generation was 5,629 GWh in 2016. The electricity consumption stood at 3.2 MWh per capita in 2016. During 2016, the majority of electricity was generated from lignite (51.4%), one third (33.7%) from hydropower, 11.9% from oil and gas and the rest 3% from other renewables (mainly wind). (IEA, 2018b) Additionally, the country relies heavily on electricity imports from neighboring countries ranging typically from 2,000 to 2,500 GWh per year (Tieman, 2010) (MAKSTAT, 2018). Lignite is today the most important resource for electricity generation in North Macedonia. However, the country has significant renewable energy potential. The hydropower potential was estimated around 5,500 GWh, with an average of 1,500 GWh being generated annually (MoE, 2017). Besides hydropower, the country has not identified the maximum technical potential for

16 other renewables. According to the UN, the technical potential for solar and wind is 24,000 MW and 400 MW respectively.

Total Operational Capacity (MW) 37 17 7 117

675 550

210 227

COAL NG CHP OIL RESERVOIR ROR WIND PV BIOGAS

Figure 5: Total operational capacity in MW in North Macedonia.

Thermal generation is the backbone of the North Macedonian grid. Lignite capacity comprises of 800 MW, 125 of which are not currently operational (ELEM, 2018). Additionally, a 227 MW natural gas combined cycle CHP plant is operating since 2011 as well as, a 210 MW residual oil plant that is on reserve due to high fuel costs. (MoE, 2017) ( Filkoski & Petrovski, 2007) The hydropower capacity installed in North Macedonia is almost 700 MW. There are 88 HPPs found as of early 2019, 79 of them are SHPP while only two are over 100 MW each. Eleven HPPs, 550 MW combined, are reservoir type, while the rest are run-of-river powerplants. (EC, 2018) (MM, 2017) The hydropower plant list is available in Appendix A. Additionally, 152 photovoltaic installations were reported in the country as of 2016 with a combined capacity of 17 MW (Bankwatch, n.d.) (Spasić, Balkan Green Energy News, 2019). Furthermore, a wind farm of 36.8 MW started operation in 2014 (ELEM, 2018). Lastly, three biogas plants with a combined capacity of 7 MW are reported to operate (Messenger, 2016) (Spasić, Balkan Green Energy News, 2019).

Total GHG emissions in North Macedonia have been fluctuating in the range of 12-14.4 MtCO2e since the nineties (MoE, 2010). The energy sector is responsible for 70%-80% of the total emissions (MoEPP, 2008). According to the business-as-usual scenario, CO2 emissions will almost double in 2030 from 9 MtCO2 to 17.6 MtCO2 (N. Macedonia, 2015). North Macedonia is a non- Annex I country without any quantified commitments for reducing GHG emissions. However, as a candidate EU country, North Macedonia intends to reduce CO2 emissions from fuel combustion by 30%, or even by 36%, until 2030 compared to the business-as-usual scenario (N. Macedonia, 2015). According to this target, CO2 emissions will be 12.4 MtCO2, or 11.4 MtCO2 in the ambitious scenario, by 2030. This target translates to an increase of 31%, or 20%, in CO2 emissions compared to 1990 (N. Macedonia, 2015).

According to North Macedonia’s NREAP published in 2015, the target was to achieve 21%, 25% and 28% share of RES in gross final energy consumption in 2020, 2025 and 2030 accordingly (MoE, 2015). Then the target for 2020 was raised to 28%, but with a share of only 18.2% in 2016 the target was lowered to 23% (Jovanović, Energy Community adopts decision lowering Macedonia’s 2020 renewables target from 28% to 23%., 2018b). The NREAP suggested that the share of RES in gross final electricity consumption should range from 25.6% in 2020 to 47.2% in 2030 (MoE, 2015). Since the target in final consumption changed, new targets for electricity production from RES have been approximated based on the 2015 values and are presented in Table 1.

17

Table 1: Electricity generation targets from RES in GWh approximated from North Macedonia's NREAP, (MoE, 2015) Electricity Generation in GWh 2020 2025 2030 LHPPs 1,692 2,557 2,841 SHPPs 552 673 748 HPPs 2,245 3,230 3,589 Wind 204 594 660 PV 41 123 137 Biomass 29 45 50 Biogas 70 79 87

It will be difficult for North Macedonia to achieve its targets for 2020 and 2025 regarding hydropower production, since no new large hydropower projects are known to have started as of early 2019 (MAKSTAT, 2018). On the other hand, the targets for wind and solar capacity can be achieved. Specifically, North Macedonia should proceed with the proposed extension of the Bogdanci wind farm, currently 36.8 MW, and/or the construction of the Miravci farm. Additionally, the construction of the Oslomej photovoltaic park, 10 MW, would help achieve the corresponding target. (ELEM, 2018)

2.3. Climate Change

Human influence on the climate system is clear, anthropogenic greenhouse gas emissions have increased since the pre-industrial era and are now higher than ever before. Continued emission of greenhouse gases is causing an increase in the mean surface temperature and result in long-lasting changes in all components of the climate system. Some of the effects are a decrease in cold temperature extremes and an increase in warm temperature extremes that has been observed since the fifties. Also, the global water cycle has changed since 1960 and the melting of ice sheets has increased. The change in precipitation and snow melting are affecting water resources both quantitative and qualitative. Additionally, an increase in extreme high sea levels and heavy precipitation events have been observed in some regions. (IPCC, 2014) To be able to measure and project the impacts of climate change, a greenhouse concentration trajectory was developed by the IPCC. The Representative Concentration Pathways describe four scenarios (RCP2.6, RCP4.6, RCP6 and RCP8.5) depending on how much greenhouse gases are emitted until the end of this century. The scenarios are named after the radiative forcing values, meaning the difference between the sunlight energy absorbed by the earth and the energy radiated back to space in the year 2100. This value is expressed in watts per square meter, a radiative force of 2.6 W/m2 corresponds to the RCP2.6 scenario, which involves a strict mitigation of emissions. Furthermore, there are two intermediate scenarios, RCP4.5 and RCP6.0, and one scenario with very high GHG emissions (RCP8.5). (IPCC, 2014)

In the near future, period until 2035, mean annual temperature is expected to increase by 0.5-1 °C compared to 1986-2005 in the Western Balkan region. During the periods 2046-2065 and 2081- 2100, mean annual temperature is expected to increase by 1.6-2.1°C and 2-4.4 °C respectively. According to the RCP4.5 scenario until 2035, temperature change is significant with an average increase of 0.8 °C and seasonally significant change during the summer and autumn months. However, there is no significance change in annual or seasonal precipitation, but a decrease during summer months can be expected. According to the RCP8.5 scenario, temperature change is significant with average increase of 1 °C, while reaching highest increase during summer. The

18 precipitation patterns are similar to the previous scenario, but with different distribution. (Vuković & Mandić, 2018)

2.3.1. Change in Precipitation

Average Monthly Rainfall 1986-2015 140 Albania 120 North Macedonia 100 80

mm 60 40 20 0

Figure 6: Average monthly precipitation in Albania and North Macedonia (World Bank, 2019).

According to historical data, mean annual precipitation in Albania is in the range of 900-950 mm (World Bank, 2019). Precipitation is the highest in the Albanian alps and the lowest in the southeast part of the country. Precipitation is the lowest during summer, with less than 40% of the annual precipitation occurring from April to September. The wet period typically occurs from October until March, with November and December being the wettest months. In North Macedonia, mean annual precipitation was around 670 mm (World Bank, 2019). Precipitation generally increases from east to west, with high precipitation values in the mountainous areas in the north and lower values in the southeast (MoEPP, 2008). Precipitation is distributed more evenly throughout the year compared to Albania. The wettest months are October, November and December followed by the spring months. Therefore, 48% of the annual precipitation typically occurs from April to September. According to the World Bank, the vulnerability of Albania to climate change is considered as high. As a matter of fact, the second highest in the whole of Europe and Central Asia (World Bank, 2009). However, the vulnerability of North Macedonia to climate change is characterized as medium (World Bank, 2009). Annual precipitation in Albania and North Macedonia is likely to decrease by up to 3% by 2050 compared to 1986-2005 (Bruci, Islami, & Kamberi, 2016).

2.3.2. Impacts on Electricity Generation

Albania still finds it difficult to meet electricity demand due to fluctuations in precipitation. During 2016, HPPs generated 7,782 GWh, whereas only 4,525 GWh were generated in 2017, a staggering decrease of 42% (IEA, 2018a) (INSTAT, 2018). The decrease in hydropower output occurred due to drastic decrease in precipitation compared to normal or wet years, a similarly dry year occurred in 2007 as well. In both cases, the electricity shortage was primarily covered from electricity imports, but blackouts were frequent also (MEI, 2016a). By 2050, annual average electricity output from LHPP and SHPP could reduce by 15% and 20% respectively (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010). In North Macedonia, the contribution of hydropower to domestic generation was about a third. During 2016, HPPs generated 1,897 GWh, whereas only 1,110 GWh were generated a year after, resulting in the same decrease percentage decrease as Albania (42%) (IEA, 2018b) (MAKSTAT, 2018). The difference was mainly covered from the extended operation of the Bitola lignite powerplant (MAKSTAT, 2018).

19

According to the World Bank, in proposed HPPs in major rivers, such as the Drin, a decrease of 20% in precipitation will result in the same decrease in generation output. Specifically, in the Drin river cascade, a reduction of water inflows by 20% in the Fierza reservoir will result in 15% decrease in electricity output. Also, for every 1% reduction in precipitation, annual runoff in Vjosa and Mati rivers decreases by 3.5%. A reduction by 20% in water flow in these rivers will result in 15% decrease in generation output. (World Bank, 2009) Other sources suggest that, a decrease of 20% in water runoff can reduce power generation by a staggering 60% (Fida, et al., 2009). In North Macedonia, annual discharge in some rivers is expected to decrease by as much as 16% and 24% by 2050 and 2100 respectively compared to 2000. Specifically, annual discharge is expected to decrease by 3.5%, 11.5% and 16% until 2050 in Treska, Vardar and Bregalinca rivers accordingly compared to 2000 (MoEPP, 2008). Furthermore, the electricity supply system is also affected indirectly by climate change and change in precipitation patterns. To be more specific, water demand for irrigation is greater during summer and therefore SHPPs compete with the agriculture sector for the limited water resources (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010). Reservoir type HPPs need to release water reserves for irrigation purposes as well (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010). On the other hand, reservoir type HPPs must contain water, therefore limiting generation, during wet months to avoid floods downstream (Dworak, Meon, Docaj, Doko, & Metaj, 2016). Another significant effect that is often neglected is the change in snowfall patterns. Specifically, increased temperatures mean that snowfall will be an even less frequent phenomenon and will drop in the form of rain. However, rainfall is typically abundant in winter and more rain will increase the risk of flood events. What is more important, is that snow acts as a form of seasonal storage, meaning that snow melts from March onwards when precipitation is lower compared to winter and thus increases water inflows to the reservoirs (Fida, et al., 2009). Additionally, higher temperatures due to climate change might reduce the demand for heating during winter but will increase the demand for cooling during summer were HPP generation is the lowest. Moreover, rising temperatures reduce the efficiency of transmission and distribution lines by 1% until 2050. The same or even higher decrease in efficiency can be expected for TPPs due to the increased temperature of water used for cooling purposes. However, climate change could have a positive impact on solar power output with an estimated increase of up to 5% due to reduced cloudiness. (Ebinger, Albania’s Energy Sector: Vulnerable to Climate Change, 2010)

20

3. The OSeMOSYS Model

3.1. Model Description

This thesis aims to identify the most cost-optimal electricity mix until 2037 for Albania and North Macedonia in the light of climate change. To achieve this, a model of the electricity supply and demand system was built using OSeMOSYS software. OSeMOSYS, or “Open Source Energy Modelling System” is a linear cost optimization tool for long-term energy planning. It was the first full energy optimization modelling framework with open source code, environment and solver. Unlike other energy systems models, such as MARKAL/TIMES, MESSAGE and PRIMES, OSeMOSYS requires a smaller time commitment to build and operate. Also, OSeMOSYS requires no upfront financial investment, therefore it is easily available to students, analysts, government officials and researchers (Howells, et al., 2011).

3.2. Reference Energy System

The Reference Energy System (RES) is a simple qualitative schematic representation of a country’s energy system which is designed prior to the modelling process. It depicts the flow of energy starting from the available resources, going through various transformation technologies to reach final energy consumption. The RES is usually separated in four levels, primary, secondary, tertiary and final energy level. Specifically for this study, the RES depicts only the electricity system of the countries in question. The extraction or import of fuel resources define the primary energy level. Then fuels are supplied to the corresponding power plants in the second energy level. Power plants transform the energy of fuels and generate electricity and heat (in some cases). Electricity will be transmitted through the transmission network to the tertiary energy level to be distributed and finally reach the final energy level or demand. It should be noted that, expected or planned power plants are also included in the RES. Additionally, electricity imports and exports flow in and out of the transmission network, while small scale technologies, such as distributed photovoltaic installations, are connected directly to the distribution network. Final electricity consumption is divided to residential and other, including industry, commercial etc., according to the available data. The RES of Albania and North Macedonia are presented in Figures 7 and 8 accordingly. The electricity system of both countries is fairly simple compared to more developed and larger economies. It should be noted that the final electricity demand follows the aggregation into “Households” and “Others” according to the methodology followed by both the Albanian and North Macedonian authorities.

21

Figure 7: Reference electricity system of Albania.

Figure 8: Reference electricity system of North Macedonia.

22

3.3. Main Parameters

This study aims to investigate the period from 2019-2037. However, the time frame of the model spanned from 2017 to 2040. This is the case because this project started in early 2019 and data for 2018 was either fully or partly unavailable. Therefore, base year selected is 2017. On the other hand, the final model year is extended beyond the study period by three years to avoid bearing the investment associated cost without enjoying the results. To make estimations more accurate, each year is divided in months and the average day of each month is divided in day and night creating 24 time slices (January Day, January Night, February Day etc.). It is considered that, each month’s day includes hours from 07:00 to 19:00, while each month’s night includes hours from 00:00 to 07:00 and 19:00 to 00:00.

3.4. Electricity Demand

The current electricity demand is described in chapter 1. When projecting the future electricity demand, the first thing to consider is that both countries in the past anticipated strong growth in future electricity demand that has not occurred so far. As seen in Figure 1, electricity consumption fluctuated heavily in Albania due to the variability in hydropower generation. According to the Ministry of Energy and Industry in 2015, final electricity consumption in 2017 would range between 5,820-6,687 GWh with an estimated annual growth above 2% from 2015 to 2020 (MEI, 2016a). However, the final electricity consumption stood at 5,563 GWh in 2017. According to (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015), final electricity consumption could grow at an average annual rate of 2.3- 3.1% until 2030. The North Macedonian Ministry of Economy has projected that final electricity consumption would grow by 2-2.5% annually from 2006 until 2020 (MoE, 2010). As seen in Figure 1, final electricity consumption peaked in 2011 at 8,047 GWh and has been decreasing since then reaching 6,104 GWh in 2017. Even recent reports have projected strong growth in electricity consumption. Specifically, the Ministry of Economy projected in 2017 that the annual growth rate of electricity consumption will be around 1.8% until 2035, resulting in 6,910 GWh and 8,513 GWh in 2020 and 2035 respectively (MoE, 2017). It is evident that both countries in the past projected higher growth in electricity consumption than the one achieved. Also, electricity consumption has peaked in 2011 and 2013 for North Macedonia and Albania accordingly and has been decreasing since then. However, all reports examined for the purpose of this study foresee an increase in electricity consumption in the future. Therefore, it was decided to utilize the most conservative annual growth values for electricity demand projections. To be more specific, the annual growth in consumption for Albania and North Macedonia will be 1.3% and 0.7% respectively (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017). The projected final electricity consumption is available in Figure 9.

23

Final Electricity Consumption Projections (GWh) 8000

7500

7000

6500

6000

5500 Albania North Macedonia

5000

2037 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2038 2039 2040

Figure 9: Final electricity demand projections in GWh.

The electricity demand profile used, comprises of the average values between 2016-2018. It was acquired from ENTSOE and included accuracy to hourly level (ENTSOE, n.d.). The hourly values are converted into 24 time slices as explained in chapter 3.3. The electricity demand profile is assumed to be the same every year until 2040 and is available in the Appendix B. Also, both the Albanian and the North Macedonian statistical agencies provided the final consumption disaggregated in residential and other consumption, including industrial, commercial, agricultural etc. demand. It should be noted that the share between each country’s residential and other demand is assumed to remain stable until 2040.

3.5. Generation Capacity

A general image of the power generation technologies, capacities and fuels is provided in both the reference energy system (RES) representation (Figures 7 and 8) as well as in Figures 3 and 5 for Albania and North Macedonia accordingly and in Appendix A. Additionally, Table 2 includes all techno-economic parameters for all generation technologies (MoE, 2010) (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015) (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017) (ELEM, 2018). Also, it indicates the operational life of power plants (Pomykacz, Olmsted, & MAI, 2014), with most of them expected to operate over the period of this study. The actual or expected emissions of the plants are based on (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017) and (MoEPP, 2008). To begin with, it should be noted that due to the lack of relevant data and the insignificant capacities, the biogas and waste plants, approximately 7 MW each, are not included in the modelling process. Also, the disaggregation of solar plants into utility and small scale, as seen in Figures 7 and 8, is not followed in the OSeMOSYS model due lack of relevant data. Albania did not have any operational thermal power plants as of early 2019. TPP Vlora, NGCC 97 MW, was constructed in 2011 but has not operated yet (KESH, 2016). However, it is assumed that TPP Vlora will come online in 2020. As mentioned in chapter 2.1, the installed hydro capacity of Albania is calculated at 1,939 MW. However, the 11 oldest SHPPs out the 146 SHPPs were found not to be operating, resulting in an active capacity of 1,929 MW that will last beyond 2040 (ERE, 2016). Additionally,

24 reservoir HPP Moglice (192 MW) is expected to go online in 2019 (Devoll Hydropower, 2014), while Kalivac reservoir HPP (120 MW) in the Vjosa river is expected in mid-2020 (BGEN, 2018). Also, Shala reservoir HPP (83.5 MW) should be commissioned in 2021 (AEA, 2017) (Spasić, EUR 300 million investments in renewable energy projects in Albania, 2017). The one and only Albanian PV park (1 MW) was constructed in 2014 and therefore will go offline in 2039 (ERE, 2016). Regarding North Macedonia, the Negotino oil plant (210 MW) is currently in reserve and used only to cover peaks in electricity demand. Therefore, it is assumed to go completely offline in 2022. Most of the current fleet of HPPs in North Macedonia will remain available after 2040. However, there is evidence of one ROR plant in North Macedonia that was constructed in 1927 and was operating as of 2015 (MM, 2017). Therefore, it is assumed that five ROR plants, 16 MW in total, built before 1960 will go offline in 2025 in North Macedonia (MM, 2017). Despite a lot of proposed hydro projects, there is only one known planned HPP, Gradiste 0.6 MW, that will come online in North Macedonia in 2020 (Spasić, Balkan Green Energy News, 2019). At least 17 MW of PV were installed in North Macedonia (EC, 2018). However, there is no specific data regarding the commissioning date of those installations, except 8 with a total capacity of 1.5 MW, built from 2009-2012 (EA, 2011). Therefore, it is assumed that all existing PV installations in North Macedonia will go offline in 2035. Also, the Bogdanci wind farm in North Macedonia was commissioned in 2014 and therefore expected to go offline in 2039.

3.6. Electricity Generation

Despite initial thoughts to segregate hydropower plants into LHPPs and SHPPs or reservoir and run-of-river, all plants are aggregated into one category. This is the case because certain data, such as the historical electricity production, was very limited or non-existent for SHPPs. On the other hand, monthly historical data was available either for some LHPPs or for the country’s total hydropower portfolio. Since this study emphasizes on hydropower production and its variation, it would not make sense to assume the same production, on a yearly or monthly basis, throughout the modelling period. Therefore, consistent monthly data on hydropower production is vital for at least a couple of consecutive years. However, Albanian data for hydropower generation ranges from very detailed (year 2015) to almost non-existent (year 2016). The data that is finally utilized was based on the Drin cascade production, which represents almost three-quarters of the total installed capacity in Albania, and is available on a monthly basis from 2012-2017 (ERE, 2016) (KESH, 2017). The situation is more or less the same for North Macedonia. Data is available on a monthly basis from 2012-2018 for the country’s large and medium hydropower plants (ELEM, 2016) (MAKSTAT, 2018). Taking all of the above into consideration, it is decided that the capacity factors from the Drin cascade and from the large/medium plants in North Macedonia would be utilized for the total hydropower capacity of the corresponding country. Since, data is available for 6 consecutive years, it is decided that those 6 years would be repeated until 2040. For instance, the capacity factors of 2012 would appear in 2024, 2030 and 2036. The same stood for the capacity factors from 2013- 2017. In that way, a more realistic result will be achieved that included dry, median and wet years. The rest of the capacity factors will remain the same throughout the modelling period and between day and night, except photovoltaic factors that equal zero during night. The capacity factors for both wind and solar installations in North Macedonia are calculated as the monthly average values from historical production between 2015-2018 and 2012-2018 accordingly. This is also the case for the lignite and CHP plants (MAKSTAT, 2018). On the other hand, the capacity factors for solar power in Albania are only available for 2015 and 2017 (ERE, 2016) (INSTAT, 2018). Since no wind power is installed in Albania, the theoretical capacity factors are exported from (Renewables Ninja, 2019). Specifically, capacity factors are extracted from 10 locations across the country, 5 along the coast and 5 inland locations, and then the average value is calculated. The efficiency of

25

NGCC plants is based on generic values (Breeze, 2016), while the efficiency of North Macedonian lignite plant is assumed to be the same as the one of similar Greek lignite plants (Kavouridis, Roumpos, & Galetakis, 2007). Also, the efficiency of Negotino oil plant in North Macedonia is provided from ( Filkoski & Petrovski, 2007).

3.7. Power Generation Constraints and Targets

The theoretical potential for most technologies is provided in chapter 2. The limits on total capacity/production are 4.5 GW and 5,500 GWh for hydro power in Albania and North Macedonia accordingly. Despite both countries have a solar potential of over 20 GW, a limit of 100 MW is set for 2019 which will grow each year by 100 MW reaching 2.2 GW until 2040. Also, the wind potential for Albania is estimated up to 1.5 GW, but only 200 MW could be exploited in 2015 due to grid restrictions (MEI, 2016a). Therefore, it is assumed that this limit remains until 2021 and each year after it grows linearly reaching a wind capacity limit of 1.5 GW in 2040. In North Macedonia, the wind limit is calculated at 400 MW (UNDP, 2012b). Since some wind capacity existed in North Macedonia, the total wind limit is set at 137 MW in 2020 and then will grow linearly until 2023 reaching 400 MW. Additionally, a limitation is set for new installations during the past years of 2017 and 2018. As discussed in chapter 2, the targets for new renewable capacity were short sided and outdated. According to the latest Albanian NREAP, targets were set until 2020 for small hydropower (750 MW), solar (120 MW) and wind (70 MW) capacities (MEI, 2016a) (PVEurope, 2018). However, it is extremely unlikely that any of the targets set will be achieved on time. Therefore, the target for SHPP is prolonged until 2025 with 70 MW of new SHPPs added every year. The target for 120 MW of photovoltaics is assumed to be achieved until 2022 since an ongoing tender exists and an additional target to reach a total of 200 MW until 2030 is assumed. The deadline for 70 MW of wind power is also moved to 2022 and an additional target to reach 150 MW of wind capacity by 2030 is assumed. Despite that the North Macedonian NREAP had a vision until 2030, the targets were estimated before 2010 (MoE, 2015). The country has fallen a bit behind on some targets so far, but the targets presented in Table 6 are utilized in this study.

3.8. Power Generation Costs

The capital and fixed operational costs in generation technologies decrease for all technologies, except hydropower according to the IEA, along the modelling period as seen in Table 2 (IEA, 2010) (DNV GL, 2018). Due to the heavy fluctuation in fossil fuel prices, predictions on fuel costs are not made and therefore the variable cost of thermal power plants remained the same along the modelling period. The capital and variable operational costs for fossil plants in North Macedonia are provided by the Ministry of Economy (MoE, 2010). In Albania, Mezősi et al. provide the capital and only the fuel part of the variable cost (37.5 Euro/MWh), therefore the missing variable cost is assumed equal to the North Macedonian value of 2.3 (Euro/MWh). The HPP capital costs are estimated based on studies for proposed or recently completed projects for Albania (Verbund, 2008) (Xhafa, 2009) (World Bank, 2013) (Devoll Hydropower, 2014) (KESH, 2017) and North Macedonia (MoE, 2010) ( Causevski & Nikolova, 2010) (ELEM, 2018) (Cingoski & Nikolov). On the other hand, data is not enough for the operational costs and IEA data is used instead (IEA, 2010).The capital costs for solar and wind installations in Albania are provided by (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015) and (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017). In North Macedonia the capital costs are provided by (MoE, 2010) (ELEM, 2018). On the other hand, IEA data is used for the operational costs (IEA, 2010).

26

Table 2: Techno-economic parameters for power generation technologies (Verbund, 2008) (Xhafa, 2009) ( Causevski & Nikolova, 2010) (IEA, 2010) (MoE, 2010) (World Bank, 2013) (Devoll Hydropower, 2014)) (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015) (KESH, 2017) (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017) (DNV GL, 2018) (ELEM, 2018) (Cingoski & Nikolov).

Capital Cost Fixed Cost Variable Cost Life Efficiency Capacity Emissions Technology Country (Euro/kW) (Euro/kW) (Euro/MWh) (years) (%) Factor (%) (kg CO2 /MWh) Year 2017 2040 2017 2040 2017 2040 Albania NG CC 1000 900 23 21 39,8 39,8 30 60 n/a 367 Albania Hydro 2233 2233 35 35 - - 40 n/a 36,3 - Albania Wind Onshore 1500 1196 43 36 - - 25 n/a 19,6 - Albania Photovoltaic 1100 782 35 16 - - 25 n/a 26,3 - N. Macedonia HFO STT n/a n/a 35 30 44 44 30 32 n/a 776 N. Macedonia NG CHP 1205 1013 22 22 48,5 48,5 30 60 41,9 421 N. Macedonia NG CC 650 585 23 21 48,5 48,5 30 60 n/a 421 N. Macedonia Coal 1200 1045 35 30 15,6 15,6 30 30 57,4 1276 N. Macedonia Hydro 1943 1943 35 35 - - 40 n/a 26,7 - N. Macedonia Wind Onshore 1511 1204 43 36 - - 25 n/a 33,2 - N. Macedonia Photovoltaic 900 639 35 16 - - 25 n/a 15,9 -

27

3.9. National Grid and Interconnections Assumptions

Even though OSHEE has managed to reduce distribution grid losses over the past few years, as seen in Appendix A, 23.1% of distribution losses is still considered as a high value compared to international standards. On the other hand, the distribution losses in North Macedonia are 11.9%. Transmission losses stood at 2.1% and 1.6% for Albania and North Macedonia accordingly. It should be noted that transmission and distribution grid losses are not considered to decrease and are kept stable along the modelling period (MoE, 2017) (INSTAT, 2018). The planned 400 kV interconnection line between Albania and North Macedonia is assumed to come online in 2022, while an additional 400 kV interconnection between North Macedonia and Kosovo is assumed to be completed in 2025 (MoE, 2017). All operating and planned interconnection lines can be seen in Appendix A. The capital cost for the Albania-North Macedonia interconnection is estimated at €70 million (Mejdini, 2016). However, the estimated cost of the new North Macedonia-Kosovo interconnection is not available and therefore assumed the same. The import/export capacities and quantities represent the average values based on historical data between 2012-2018 (ERE, 2016) (MAKSTAT, 2018) (SEECAO, 2019). It should be noted that, for the case of North Macedonia the only available capacity is the one with Greece, therefore it is assumed that the same capacity is allocated to/from North Macedonia with Bulgaria and Kosovo. Also, it is assumed that the capacity allocation between Albania and North Macedonia, when the interconnection is complete, will be 200 MW. Lastly, it is assumed that the new interconnection line between North Macedonia and Kosovo will raise the allocated capacity from 150 MW to 300 MW from 2025 onwards.

Table 3: Interconnection capacities and quantities.

Capacity Quantity Interconnection (MW) (GWh) AL_KO 200 198 KO_AL 200 182 AL_GR 150 212 GR_AL 150 1119 AL_MO 200 142 MO_AL 200 1222 AL_MK n/a n/a MK_AL n/a n/a MK_BG 150 0 BG_MK 150 1313 MK_GR 150 153 GR_MK 150 155 MK_KO 150 24 KO_MK 150 1066

Variable costs, meaning electricity imports and exports, came at a great cost for both Albania and North Macedonia. In 2006, North Macedonia produced electricity at the cost of 21 Euro/MWh, while the cost of imported electricity was 45.5 Euro/MWh. Additionally, this cost increased in 2007 by 55% at 70 Euro/MWh (Tuneski). According to the Albanian Energy Regulatory Authority, the annual average electricity import price ranged from 30.2 Euro/MWh in 2003 to 79 Euro/MWh

28 in 2008 (Aliko, 2010). Therefore, it is evident that in both countries, electricity imports fluctuated significantly from year to year. Unfortunately, segregated prices per interconnection are not available. Therefore, it is assumed that countries import and export electricity at fixed prices, as seen in Appendix B, regardless of the interconnection. Specifically, the average historical import price is 51.8 Euro/MWh and 53.6 Euro/MWh for Albania and North Macedonia respectively (ERE, 2016) (Balkan Energy, 2017) (Serbia Energy, 2017) (Jonuzaj, Albania’s KESH invites bids for power exports for April 23-30 delivery, 2018) (Bejtullahu). Additionally, data on electricity exports is even more limited. Specifically, this data is available for only two years for Albania (28 Euro/MWh) and none for North Macedonia. Therefore, the import/export price ratio is calculated for Albania and by utilizing the North Macedonian average import price resulted in an export price of 29 Euro/MWh for North Macedonia.

3.10. Climate Change Impact Assumptions

The estimation of the impacts of climate change on electricity generation is perhaps the most challenging task in this study. This is the case mainly due the lack of relevant data and the uncertainty involved in the projection of physical phenomenon over years. According to the literature review in chapter 2.3, a connection should be established between precipitation and hydropower generation, this is achieved by utilizing the river flow. However, river flow depends on a handful of parameters besides precipitation, including basin and terrain characteristics such as inclination, absorbability and the like. Therefore, a completely different approach and hydrological model would be necessary for each river and stream utilized for power generation. On the other hand, this study focuses on electricity and not water modelling. Additionally, specific data about river flow and precipitation is only available for a few hydrological and meteorological stations located in the Drin basin. Having all of the above in mind, it is decided that the climate impacts on river flow and power generation should be estimated for the Drin and Black Drin river and then being applied to the total hydropower portfolio of Albania and North Macedonia respectively. Since, more than half of the installed combined capacity, and electricity generation, of HPPs is located along the river Drin, the “average” results extracted will correspond up to a large percentage to reality. As mentioned before, data is very limited. Specifically, precipitation data is available for only eight stations in the Drin basin. River flow data is only available for only four and three stations for the Drin and Black Drin rivers respectively. However, data from those stations does not match, geographically or chronologically, except for the two stations that are finally utilized. For the Drin river, the precipitation and river flow data utilized is from the Vau Dejes station, where the downstream HPP of the Drin cascade is located. For the Black Drin river, historical data is obtained from the Kukes station, where the Black and White Drin join. The station in Kukes is in Albania, located east near the border with Kosovo and North Macedonia, where the Black Drin enters Albania. Therefore, it is considered the best alternative to approximate the change in power generation for North Macedonia. The first step is to extract the average values from the Vau i Dejes and Kukes hydrological and meteorological stations. Then correlations are made between precipitation and river flow. To be more specific, R2 is 73% and 78% for the Vau Dejes and Kukes values respectively as seen in Appendix B. Next, predictions regarding precipitation change for Albania are obtained from the Third National Communication Report on Climate Change for Albania. It is decided to utilize the projections only for Albania and not North Macedonia for two main reasons. First, Kukes station, used for the Black Drin/North Macedonia, is situated in Albania close to the border with North Macedonia. Second, it is unclear which methodology did the Ministry of Environment and Physical

29

Planning of North Macedonia followed to develop its projections in the National Communication Report on Climate Change (MoEPP, 2008). Therefore, the Third National Communication Report on Climate Change for Albania provides the average monthly change in precipitation until 2050. Since one of the objectives of this study is to explain the impact of climate change on hydropower generation, the RCP8.5 scenario, worst case scenario, is chosen. However, the impacts under the RCP4.5 scenario are also tested. According to the report, an annual reduction of 2.9% in precipitation is to be expected in 2050 compared to 1986-2005 average precipitation levels under the RCP8.5, high emission, scenario. However, decrease in precipitation can reach even 16% during summer and/or increase by 3% during winter. (Bruci, Islami, & Kamberi, 2016)

Monthly Precipitation Profile 250 Vau Dejes Historical 230 Kukes Historical 210 190 Vau Dejes 2050 RCP8.5 Scenario 170 Kukes 2050 RCP8.5 Scenario 150 mm 130 110 90 70 50 30

Figure 10: Average historical (1986-2005) precipitation and projections for Vau Dejes and Kukes stations.

Through the correlation that is established between precipitation and river flow, it is then possible to estimate the change in river flow for the Drin and Black Drin rivers until 2050. However, it is not possible to establish a correlation between river flow and hydropower generation, due to the lack of relevant power generation data, that matched chronologically the river flow data, for these two rivers. On the other hand, Ebinger et al. have managed to establish such a correlation for the Drin river. Specifically, a reduction in river flow of 20% will result in a reduction in hydropower generation of 15% (World Bank, 2009). Therefore, the decrease in hydropower production could be calculated for every year. The results under a climate change case are available in Table 4 for two years (2019 and 2037). First of all, the figures for hydropower production in Albania represent only the Drin cascade and not the country total production since, the total capacity installed in past years is not available. On the other hand, hydro capacity installed in North Macedonia from 2012 onwards is available and Table 4 represents the total hydropower production for North Macedonia. As described in chapter 3.6, a repetition occurred in hydropower generation every six years according to historical data. Therefore, the reduction in generation due to climate change is applied every year but based to the corresponding year in the past. This is the reason that 2019 and 2037 were chosen to display. Specifically, generation in year 2025 will decrease compared to 2019, generation in year 2031 will decrease compared to 2025 and generation in year 2037 will decrease compared to 2031. This is the case for all modelling years.

30

Table 4: Projections on precipitation, river flow and hydropower generation.

Projections for Vau Dejes Station-Drin River Hydropower Generation Precipitation (mm) River Flow (m3/s) (GWh) 2019 2037 Change 2019 2037 Change 2019 2037 Change January 138,2 140,5 827,4 840,9 589,1 604,7 2,6% 1,66% 1,63% February 140,9 143,2 843,3 857,1 470,3 483,3 2,8% March 111,9 108,7 673,1 654,4 561,7 540,4 -3,8% April 147,6 143,4 -2,84% 883,0 858,4 -2,78% 700,9 660,1 -5,8% May 107,2 104,1 645,3 627,4 751,0 724,6 -3,5% June 70,4 64,9 429,1 396,8 596,4 554,8 -7,0% July 48,0 44,3 -7,82% 297,8 275,7 -7,54% 402,7 378,6 -6,0% August 54,1 49,9 333,4 308,5 361,7 335,2 -7,3% September 129,8 127,2 777,9 762,8 267,4 254,0 -5,0% October 169,3 165,9 -1,99% 1010,2 990,4 -1,95% 282,1 259,5 -8,0% November 223,8 219,4 1330,7 1304,6 312,7 289,0 -7,6% December 237,2 241,1 1,66% 1409,0 1432,1 1,64% 449,8 470,9 4,7% Annual 1578,4 1552,7 -1,63% 9460,3 9309,1 -1,60% 5745,7 5555,1 -3,32% Projections for Kukes Station-Total Hydropower in North Macedonia Hydropower Generation Precipitation (mm) River Flow (m3/s) (GWh) 2019 2037 Change 2019 2037 Change 2019 2037 Change January 75,6 76,8 224,0 228,1 60,7 62,3 2,6% 1,66% 1,84% February 76,6 77,9 227,5 231,7 86,5 89,4 3,3% March 64,5 62,7 187,6 181,6 231,5 223,0 -3,7% April 78,6 76,3 -2,84% 233,8 226,5 -3,21% 246,6 236,5 -4,1% May 62,6 60,9 181,5 175,7 245,7 236,9 -3,6% June 47,3 43,6 131,2 119,1 123,1 111,0 -9,8% July 38,5 35,5 -7,82% 102,3 92,4 -9,26% 147,2 134,8 -8,4% August 40,9 37,7 110,2 99,7 157,0 142,2 -9,4% September 71,7 70,2 211,1 206,5 67,8 63,7 -6,1% October 87,2 85,5 -1,99% 262,3 256,6 -2,21% 74,2 70,7 -4,8% November 108,7 106,6 332,8 325,7 80,9 77,4 -4,4% December 114,6 116,5 1,66% 352,0 358,2 1,77% 164,7 170,3 3,4% Annual 866,9 850,2 -1,92% 2556,3 2501,7 -2,14% 1686,0 1618,1 -4,03%

31

4. Scenario Description

A scenario cannot predict the future. It can however contribute to the explanation of how certain changes impact the electricity system. Through the developed scenarios, this study would provide economical and technical insights to decision makers to inform them about how to improve the current electricity system and plan for the future. For this purpose, three scenarios were created, the Business As Usual (BAU) scenario, the Climate Change (CC) scenario and the Increased Renewables (IR) scenario. According to the Business As Usual scenario, the current electricity system is extended into the future without any changes besides the ones mentioned in chapter 3. These changes include an increase in electricity demand, a decline in capital and/or operation costs for different generation technologies due to technological advancement as well as the planned construction and decommission of power plants and interconnections. Also, the hydropower generation varies between dry, median and wet years according to monthly historical data from 2012 to 2017, meaning that every six years hydropower generation is the same. The Climate Change scenario is based on the BAU scenario. However, the effects of climate change taken into consideration are more severe compared to the BAU scenario. As described in chapter 3.10, a repetition occurs in hydropower generation every six years according to historical data. In this case, the reduction in generation due to climate change is applied every year but based to the corresponding year in the past. For example, hydropower production in North Macedonia in years 2018, 2024, 2030, 2036 will be the same (1,164 GWh) under the Business As Usual scenario but under the climate change scenario it will reduce to 1,132 GWh in 2024, 1,116 GWh in 2030 and 1,101 GWh according to the correlations established in chapter 3.10.

Table 5: Projected capacity factors for hydropower plants.

2018 2019 2020 2021 2022 2023 2035 2036 2037 2038 2039 2040 Albania BAU 34,1% 49,2% 28,8% 37,8% 43,3% 25,0% 25,0% 34,1% 49,2% 28,8% 37,8% 43,3% Albania CC 33,7% 48,6% 28,4% 37,4% 42,8% 24,8% 24,3% 32,6% 47,0% 27,5% 36,2% 41,5% N. Macedonia 22,3% 31,5% 23,0% 32,0% 32,4% 19,0% 19,0% 22,3% 31,5% 23,0% 32,0% 32,4% BAU N. Macedonia 22,0% 31,1% 22,7% 31,7% 32,0% 18,8% 18,5% 21,1% 29,8% 21,9% 30,8% 30,9% CC

The Increased Renewables scenario is based on the CC scenario, meaning that the possible effects on hydropower generation are taken into consideration. In addition to the previous scenario, national governments must meet their targets on renewable energy as stated in their National Renewable Energy Action Plan. These targets are described in chapters 2.1 and 2.2 for Albania and North Macedonia accordingly. Since Albania was very optimistic about most of its capacity targets, the deadlines were moved ahead by some years and new targets were assumed in Table 6 until 2030 as discussed in chapter 3.7.

Table 6: Renewable capacity targets for Albania and North Macedonia.

Total Installed Renewable Capacity Targets (MW) Albania North Macedonia 2020 2025 2030 2020 2025 2030 HPPs 2381 2812 2812 750 959 1398 Wind - 100 150 50 150 300 Solar - 150 200 24 45 90

32

5. Results

In this chapter the results of the three scenarios described earlier will be presented. The findings will also be analyzed and compared between the different scenarios. The results and analysis focused on:

 Historical and new generation capacity.  Fuel share in the electricity mix (generation per technology).  Electricity imports and exports.  Costs associated to capacity investments and system operation cost.  Carbon dioxide emissions. To make the results easier to follow, the findings of three years according to precipitation (dry, median and wet) will be presented out of the rotation of six years plus the base (2017) and end (2037) years. To be more specific, 2023, 2029 and 2035 represent the dry years, 2021,2027 and 2033 represent the median years and 2019, 2025 and 2031 along with 2037 represent the wet years. Due to the smaller hydropower capacity in North Macedonia, compared to Albania, there is not significant difference between median and wet years. In this case, all years will be referred as normal years except the dry years (2023, 2029 and 2035) for North Macedonia.

5.1. Business As Usual Scenario

5.1.1. Albania

New and Total Capacity (MW) 3000

2500 1 1 1 1 1 1 1 1 1 1 2000 1 1500 2324 2324 2324 2324 2324 2324 2324 2324 2324 1000 1929 2121 500 203

0 192 9797 97 97 97 97 97 97 14111 111

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

NGCC HYDRO PV

Figure 11: New and total capacity in Albania under the BAU scenario.

Figure 11 depicts the total operational capacity in Albania as well as the expected new capacity. The operational capacity of Albania consists mainly of hydropower reaching almost 2 GW in capacity. The share of solar (1 MW) and waste incineration installations is only marginal, with the latter not considered at all in this study. Albania will extend its reservoir plant fleet in the near future, since three new HPPs are being constructed. HPP Moglice (192 MW) should be completed in 2019, HPP Kalivac (120 MW) is expected in 2020 and HPP Shala (83.5 MW) should be commissioned in 2021. In total 396 MW of new reservoir HPPs will be added until 2037 resulting

33 in 1,884 MW of reservoir HPPs. Therefore, the total hydro capacity of Albania will reach 2,324 MW in 2021 and remain the same until 2037. As discussed in chapter 3.5, the Vlora combined cycle plant (97 MW) was completed in 2011 but has not operated yet. Therefore, it is assumed to become operational in 2020, after completing the connection with the Trans Adriatic Pipeline. Some additional gas capacity, only 14 MW, will be required in 2035 as seen in Figure 11. On the other hand, it seems that the techno-economic characteristics of new non-hydro renewable technologies do not favor them against established technologies for power generation. To conclude, the total operational installed capacity in 2037 in Albania will be almost 2.5 GW, out of which 95.4% or 2.32 GW will be hydro capacity. Thermal capacity will reach 4.6% of the total capacity, while the share of solar capacity is insignificant. Taking all of above into consideration, hydropower will remain the backbone of the Albanian electricity system for the next 20 years. However, it should be noted that the vast majority of new capacity was “forced” to be built since it represents ongoing projects. If those projects are not operable in the near future, the capacity generation portfolio of Albania could be slightly different.

Electricity Mix 100%

80%

60%

40%

20%

0%

-20% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

NGCC HYDRO WIND PV NET TRADE

Figure 12: Electricity mix in Albania under the BAU scenario.

The uncertainty involved in a system hugely dependent on hydropower is depicted in Figure 12. Total domestic supply is clearly dominated by hydropower, with the shares of solar and thermal power being insignificant along the modelling period. As a matter of fact, solar production is below 1 GWh annually while the NGCC plant will only operate in 2033 and 2035 producing just 32 GWh of electricity annually. The extremely low utilization rate of the plant means that it is only used to cover peaks in electricity demand that cannot be covered from hydropower or electricity imports. Therefore, a new interconnection line would make more sense economically instead of an idling gas-fired plant. On the other hand, annual hydropower production will range from 5,000 to 10,000 GWh including the new installed capacity. During wet years, hydropower production surpasses 9,000 GWh meaning that net electricity exports reach almost 1,800 GWh in 2025. Electricity exports will increase due to the new hydro capacity in 2025 compared to 2019. However, as the electricity demand increases and no significant new capacity is built after 2021, total net electricity exports will decrease to 1,134 GWh and 438 GWh in 2031 and 2037 accordingly. During median years, hydropower production will be over 7,000 GWh, but still Albania will need to import electricity. Despite the fact that net electricity imports will be only 118 GWh in 2021, they will gradually increase due to the increase in electricity demand to 745 GWh and 1,423 GWh in 2027 and 2033 accordingly. Hydropower production will

34 drop to around 5,000 GWh during dry years despite the extra 396 MW of hydro capacity. Therefore, the country will be forced to import electricity which can even reach 45% of its gross electricity demand or 4,216 GWh of net electricity imports in 2035. Total domestic supply was 7,390 GWh in 2017 and is expected to grow to 9,571 GWh in 2037. The final electricity consumption will be 7,203 GWh in 2037, meaning that almost one-quarter of the electricity produced is lost due to technical and non-technical losses. On the other hand, the country’s reliance on hydropower possess great threat to energy security and when dry years occur consumers have to pay for imported electricity at high prices. The total system cost could skyrocket from 15 €/MWh during wet years to more than 70 €/MWh during dry years and will be further analyzed in chapter 5.1.3.

5.1.2. North Macedonia

New and Total Capacity (MW) 2500

2000 17 17 17 17 17 17 3717 3717 17 237 400 400 400 400 400 400 400 400 1500 667 668 668 668 652 652 652 652 652 652 652 1000 228 228 210 210 228 228 228 228 228 228 228 228 228 500 675 675 675 675 675 675 675 675 675 675 675 200

0 1 163

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV

Figure 13: New and total capacity in North Macedonia under the BAU scenario.

Figure 13 shows the total operational and expected new capacity in North Macedonia. At the moment, installed operational capacity is a bit over 1.8 GW. Lignite-fired plant Bitola (675 MW) is and will be the cornerstone of the electricity system for the foreseeable future under the BAU scenario. The Negotino oil-fired plant (210 MW) is only used to cover peaks in electricity demand and assumed to be decommissioned in 2020. Despite a lot of proposed hydro projects, no major project is expected to be launched soon. Therefore, the fleet of reservoir plants, 550 MW in capacity, will remain the same until 2037. As discussed in chapter 3.5, the only planned hydro project found is SHPP Gradiste (0.6 MW) which is expected to be completed in 2020. On the other hand, it is assumed that five of the county’s oldest HPPs, built before 1960, will go offline in 2025. The decommissioning of those plants will result in a total operational capacity of 652 MW for HPPs until 2037. Wind power will soon become competitive in North Macedonia due to the favorable techno- economic parameters of wind turbines. Besides the completed Bogdanci wind farm (36.8 MW), new wind installations will be completed from 2020 onwards. As a matter of fact, North Macedonia will reach its wind limit potential (400 MW) as of 2023. In case of an increase in wind potential, more wind farms could be installed in the future. On the other hand, no new photovoltaic installations are expected in North Macedonia under the BAU scenario. The currently installed 17

35

MW of solar power should be refurbished by 2035 due to the operational life limit. In terms of capacity installed, North Macedonia will have almost 2 GW of operational generation capacity as of 2037 compared to 1.8 GW currently. Thermal capacity will be responsible for up to 46% (lignite 34.5% and natural gas CHP 11.7%) of the total installed capacity and hydropower for up to a third, 28.1% reservoir and 5.2% ROR. The share of wind will be 20.5% as of 2037.

Electricity Mix 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV NET TRADE

Figure 14: Electricity mix in North Macedonia under the BAU scenario.

The Bitola lignite-fired plant will continue to provide over one-third of North Macedonia’s gross electricity demand with production ranging from 2,315 GWh to 3,049 GWh annually. The operation of the plant will vary depending on the production from hydropower, new wind capacity and electricity trade. To be more specific, the new interconnection line with Kosovo planned for 2025 would increase net electricity imports and reduce lignite-generated electricity to 2,315 GWh. The electricity generation from the CHP plant is assumed stable at 750 GWh annually, but with high seasonal variation due to the heating load, while the Negotino oil-fired plant will produce less than 30 GWh annually to cover demand peaks until its decommissioning in 2020. The biggest change in electricity supply will come from wind power, which will achieve a share of 15% in the electricity mix or 1,166 GWh annually from 2023 onwards compared to around 107 GWh currently. Solar production will remain roughly the same (18 GWh) since no new capacity will be added. During a normal year, hydropower production ranges from 1,800 GWh to 1,900 GWh, while on dry year it will drop to roughly 1,100 GWh annually. The share of hydropower in the electricity mix is 21-26% for normal years but drops to 15% during dry years. Net electricity imports are currently over 1,500 GWh on average annually. However, the installation of new wind power will reduce net electricity imports by 300-400 GWh annually in the short-term. On the other hand, after 2025 electricity imports will gradually increase to cover the increasing electricity demand since no new major generation capacity planned to be installed. In 2035, low hydropower production combined with high electricity demand will increase net electricity imports to over 1,900 GWh achieving a share of 24%. Total domestic supply was 7,039 GWh in 2017 and is expected to grow by 15% to 8,094 GWh in 2037. The final electricity consumption will be 7,018 GWh in 2037 meaning that around 1,000 GWh are lost in the transmission and distribution grid due to technical and non-technical losses. The increase in electricity demand will primarily be covered from wind power and electricity imports. Despite new generation capacity additions, electricity imports will still account for about

36 a quarter of the total domestic supply. The option to build a natural gas combined cycle plant will reduce electricity imports, while increasing natural gas imports, but high fuel costs prevented the model from using this option.

5.1.3. Economic and Environmental Impact

Discounted Capital Investments (million Euros) 100% 90% 127 80% 119 70% 60% 50% 390 55 173 18 5 231 40% 30% 153 20% 10% 83 0% 2019 2020 2021 2022 2023 2025 2035

NGCC HYDRO WIND INTERCONNECTION

Figure 15: Aggregated discounted capital investments in million Euros under the BAU scenario.

It should be noted that almost all investments will take place before year indicated in Figure 15. As a matter of fact, most of hydro and natural gas plant investments have already taken place before the model’s start year (2017). The majority of new capacity investment will occur within the first five modelling years. Based on the modeling assumptions, Albania will invest more than €770m in new hydro capacity whereas North Macedonia will invest just over a million Euros. On the other hand, North Macedonia will invest €419m to install over 360 MW of new wind capacity. The cost of the Albania-North Macedonia interconnection is assumed to be equally shared between the countries at around €27m each. This is also the case in the interconnection between North Macedonia and Kosovo, since the electricity system of Kosovo is not considered, Figure 15 displays only the cost (€18m) for North Macedonia. In total, Albania will invest almost €890m during the next 20 years, whereas North Macedonia will invest €465m.

37

Total System Operating Cost 120

100

/MWh) 80 €

60

40

20 Operating Cost (

0 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

Albania North Macedonia

Figure 16: Total system operating cost under the BAU scenario.

It is clear, especially in the case of Albania, that the operating cost of the system totally depends on the fluctuation of hydropower generation. As described above, low hydropower generation results in increased electricity imports. Electricity imports come at a higher cost, over 50 €/MWh, especially when compared to the very low operational costs of HPPs (35 €/kW). In the case of Albania, the operating cost can even quadruple between wet and dry years. Additionally, there is a decreasing trend in the cost during the first modelling years. In Albania, new hydropower capacity, combined with high precipitation, pushes operational costs even below 20€/MWh. In North Macedonia, new wind capacity provides low operational cost and at the same time reduces electricity imports. Even though North Macedonia has a higher system operating cost compared to Albania, it also has a more stable and therefore predicable cost profile. The electricity import price is calculated based on historical data and assumed stable along the modelling period. If the import cost increases, the impact will be much more significant to Albania compared to North Macedonia. It is also evident that, the system operating cost in Albania will increase in the long term by more than 20€/MWh. The opposite will happen in North Macedonia with costs decreasing by more than 15€/MWh. The future economic landscape, in terms of electricity cost, might be more favorable for North Macedonia, but this is not the case for the environmental landscape. To be more specific, Albania under the BAU scenario will have an almost 100% carbon-free domestic electricity generation system. The only exception to this will be the limited operation of the NGCC plant, the indirect emissions produced from HPPs and of course the electricity generated outside the country which is mostly based on coal-fired plants. On the other hand, lignite is and will be the cornerstone of the North Macedonian system. Despite, the shutdown of the Oslomej lignite-fired plant in 2015, North Macedonia will emit 3.3-4.2 MtCO2 annually. The emissions from the CHP plant are considered stable through the years, whereas the contribution from the oil-fired plant, operating until 2020, are insignificant. Therefore, most of the emissions are attributed to the Bitola lignite- fired plant whose operation varies according to rainfall and electricity imports. To be more specific, the lowest emissions (3.2 MtCO2) are observed in 2025 when the new interconnection line becomes operational and hydropower generation is high.

38

5.2. Climate Change Scenario

5.2.1. Albania

New and Total Capacity (MW) 3000 2500 1 1 1 1 1 1 1 1 1 1 2000 1 1500 2324 2324 2324 2324 2324 2324 2324 2324 2324 1000 1929 2121 500 203

0 192 9797 97 97 97 97 97 97 33130 130

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

NGCC HYDRO WIND PV

Figure 17: New and total capacity in Albania under the Climate Change scenario.

When comparing Figure 11 with Figure 17 it is evident that climate change will not affect the electricity system in terms of generation capacity. The reason is, as mentioned before, that the 395 MW and 97 MW of new hydro and gas capacity are already in the construction or delivery phase leaving little room to add new capacity in the future. The only difference between the BAU and Climate Change scenarios, in terms of capacity, is that 35 MW of new gas capacity will be added in 2035 instead of 14 MW under the BAU scenario. Therefore, the share of gas capacity will slightly increase to 5.3% in 2037, but hydropower will remain dominant with 2.32 GW of generation capacity.

Electricity Mix 100%

80%

60%

40%

20%

0%

-20% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

NGCC HYDRO WIND PV NET TRADE

Figure 18: Electricity mix in Albania under the Climate Change scenario.

The general trend depicted in Figure 18 is not much different compared to the BAU scenario. The variation in precipitation highly affects electricity supply. However, under the Climate Change scenario the annual precipitation will reduce from year to year. To be more specific, in a wet year, such as 2037, hydropower production will be reduced by 444 GWh compared to the BAU scenario.

39

In a dry year, such as 2035, electricity production will decrease from 5,078 GWh to 4,942 GWh between the BAU and Climate Change scenarios accordingly.

Hydropower Generation in BAU and CC Scenarios 12000

10000 208 319 444 94 8000 83 167 242 6000 0 47 92 136 8994 9756 9669 9564 4000 7581 7500 7422 6133 5031 4986 2000 4942

0 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

Additional hydro generation under the BAU scenario AnnualHydropower Generation(GWh) Hydro generation under the Climate Change scenario

Figure 19: Hydropower generation in Albania.

All of the above, indicate that Albania will not only have to face the alternation between dry, median and wet years but also tackle an overall decreasing trend in precipitation over the years. This trend is clear when comparing Figure 12 and Figure 18. In a few words, Albania will gradually import more electricity during dry years and export less electricity during wet years compared to the BAU scenario. In 2019, net exports will decrease from 1,426 GWh (19%) to 1,339 GWh (17%). In a median year, such as 2027, net electricity imports will increase from 745 GWh to 912 GWh. Year after year the effects of climate change become more obvious and more severe. Therefore, the dry year of 2035, the last dry year modelled, net electricity imports will increase to 4,343 GWh compared to 4,216 GWh between the Climate Change and BAU scenarios. In that year, almost half (47%) of the gross electricity supply will need to be imported, with the share of hydropower dropping to only 53%. It is equally important to notice that due to the combined effects of climate change and increased electricity demand, Albania will be a net electricity importer in 2037, by just 9 GWh, despite that year being a wet year. This means that from 2037 onwards Albania will be a net electricity importer every year regardless of the amount of precipitation if the country does not invest in new generation capacity. The production from solar power is still insignificant, below 1 GWh annually, as in the BAU scenario. The Vlora natural gas plant will have the same role as in the BAU scenario, to cover peaks in electricity demand. However, in this scenario it will operate in 2029 and 2035 compared to 2033 and 2035 under the BAU scenario. In 2029, the production will only be 2 GWh, since the allocated interconnection capacity cannot cover the demand. The extra capacity added in 2035, compared to the BAU scenario, will only provide only 6 GWh more, 38 GWh instead of 32 GWh, to cover peaks in electricity demand. The above show that, during dry years existing and planned capacity and electricity imports will be unable to cover the demand in the near future. In the BAU scenario, this will be the case in about 15 years. However, under the Climate Change scenario it can be as early as 2029.

40

5.2.2. North Macedonia

New and Total Capacity (MW) 2500

2000 17 17 17 17 17 17 17 17 37 37 23717 400 400 400 400 400 400 400 400 1500 667 668 668 668 652 652 652 652 652 652 652 1000 228 228 210 210 228 228 228 228 228 228 228 228 228 500 675 675 675 675 675 675 675 675 675 675 675

0 1 200 163

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV

Figure 20: New and total capacity in North Macedonia under the Climate Change scenario.

There is no difference in the generation capacity between the BAU and Climate Change scenarios. New wind and hydro capacities are expected in the short-term. While oil, solar and part of the hydro capacity portfolio will be decommissioned. These changes will result in North Macedonia having almost 2 GW of operational generation capacity as of 2037 compared to 1.8 GW currently. Thermal capacity will be responsible for up to 46% of the total installed capacity and hydropower for up to a third, leaving wind power with a share of 20.5% as of 2037.

Electricity Mix 100%

80%

60%

40%

20%

0% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV NET TRADE

Figure 21: Electricity mix in North Macedonia under the Climate Change scenario.

Climate change will impact the North Macedonian electricity supply system, but at a lesser degree compared to the Albanian case. Just like the BAU scenario, the Bitola lignite-fired plant will generate during most years 3,049 GWh of electricity annually, operating at the maximum capacity factor set. However, increasing electricity demand, interconnections and hydropower production impact the operation of the plant. For instance, in 2025 the plant will operate less due to a normal year, concerning precipitation, and the new interconnection line with Kosovo. However, the amount of precipitation is decreasing year after year compared to the BAU scenario. Therefore, the plant will operate less compared to other years, but at the same time it will operate more compared to the corresponding year in the BAU scenario. In a few words, the plant will produce

41 annually 50-100 GWh more compared to the same years under the BAU scenario, meaning 2025, 2027, 2031 and 2037, due to reduced precipitation.

Hydropower Generation in BAU and CC Scenarios 2000 26 19 1800 50 37 74 54 97 1600 1400 0 1200 9 1000 18 26 1824 1848 1786 1768 800 1756 1733 1709 1451 600 1102 1068 1059 400 200 0 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

Additional hydro generation under the BAU scenario AnnualHydropower Generation(GWh) Hydro generation under the Climate Change scenario

Figure 22: Hydropower generation in North Macedonia.

On the other hand, the electricity production from wind, solar, natural gas and oil will remain the same with the BAU scenario as seen in Figure 21. However, the impact of climate change on hydropower generation can be described as measurable but small. During dry years, hydropower generation will only decrease by 9-26 GWh annually compared to the same years in the BAU scenario. Whereas during normal years, it will decrease by 19-97 GWh compared to the BAU scenario. Of course, smaller values correspond to the short term while larger values correspond towards the end of the modelling period. For instance, the decrease by 26 GWh and 97 GWh compared to the BAU scenario correspond to the years 2035 and 2037 accordingly. However, the decrease in hydropower generation does not necessarily result in an increase of electricity imports. During the years that Bitola lignite-fired plant will not operate on its maximum capacity factor, lignite can substitute for the lower production from hydropower. For instance, hydropower production will decrease by 50 GWh in 2025, but this amount can be covered from the Bitola plant instead of electricity imports. As a result, North Macedonia will import 50 GWh less compared to the BAU scenario despite the decrease in hydropower production. This is also the case during 2027 and 2031. However, during the rest of the modelling period the decrease in hydropower generation results in an increase of electricity imports ranging from 10 GWh to 54 GWh compared to the BAU scenario.

42

5.2.3. Economic and Environmental Impact Discounted Capital Investments (million Euros) 100% 90% 127 80% 119 70% 60% 50% 390 55 173 18 13 231 40% 30% 153 20% 10% 83 0% 2019 2020 2021 2022 2023 2025 2035

NGCC HYDRO WIND INTERCONNECTION

Figure 23: Aggregated discounted capital investments in million Euros under the Climate Change scenario.

Generation capacity has not changed significantly in the Climate Change scenario compared to the BAU scenario. The only difference is the extension of the natural gas plant, 33 MW instead of 14 MW, which will cost €13m instead of €5m. This will result in Albania investing almost €900m before and during the modelling period, while North Macedonia will invest only €465m.

Total System Operating Cost 120

100

80

60

40

20 Operating Cost (Euro/MWh) 0 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

Albania North Macedonia Albania BAU North Macedonia BAU

Figure 24: Total system operating cost under the Climate Change scenario.

The system operating cost follows the same trend as the cost under the BAU scenario as seen in Figure 24. The variation in the cost between dry and wet years is clearly visible especially for Albania. During dry years the operating cost increases due to the dependence on electricity imports, whereas during wet years very low costs are achieved because of the low operating costs of HPPs. The significant decrease in the amount of precipitation, under the Climate Change scenario, will drive system costs higher. Not only Albania has to import more and more electricity but also the operating costs of HPPs, mainly fixed costs, remain the same while generation output reduces. Under this scenario, operation costs will increase between 0.6-2 €/MWh and 0.9-5 €/MWh for dry

43 and wet years respectively compared to the corresponding years in the BAU scenario. Smaller values refer to the short term while bigger values are valid towards the end of the modelling period. For instance, the system operating cost will increase to 48 €/MWh in 2037 compared to 43 €/MWh under the BAU scenario. Accordingly, the cost will increase to 78.1 €/MWh in 2023 compared to 77.5 €/MWh under the BAU scenario. As stated earlier, the impact of climate change to North Macedonia is much smaller compared to Albania and this is also depicted in the total system operating cost. Besides the fact that the cost trend is decreasing for North Macedonia, results show that price volatility to climate change is reduced. However, operation costs will slightly increase between 0.4-1.6 €/MWh and 0.2-0.5 €/MWh for dry and normal years respectively compared to the corresponding years in the BAU scenario. On average, operating costs will increase by 0.7 €/MWh for North Macedonia, whereas the value for Albania is 2 €/MWh until 2037 compared to the BAU scenario. Additionally, the system operating cost gap between Albania and North Macedonia is closing in favor of the latter as shown in Figure 24. To conclude, Albania will retain its domestic electricity supply almost 100% carbon-free, with emissions from the Vlora natural gas plant being insignificant due to its limited operated. However, indirect greenhouse emissions are released through the operation of the HPPs and the electricity generated outside the country but utilized inside its borders. On the other hand, there is an upward trend for emissions generated in North Macedonia compared to the BAU scenario, attributed mainly to the operation of the Bitola lignite-fired plant and the Skopje CHP plant. Even though emissions from the CHP are stable, emissions from Bitola have increased slightly during the years that the plant is not operating at its maximum capacity factor. To be more specific, lower hydropower production resulted in extended operation of the Bitola plant which lead to increased emissions. For instance, year 2025 is the year with the lowest direct emissions from North Macedonia as explained previously. However, emissions increased from 3.27 MtCO2 under the BAU scenario to 3.39 MtCO2 in this scenario.

5.3. Increased Renewables Scenario

5.3.1. Albania

New and Total Capacity (MW) 3500 170 190 200 200 200 200 3000 100150 120 140 150 150 150 150 13080 3550 2500 1 2000 1 1500 2812 2812 2812 2812 2812 2812 2812 2535 2675 1000 1929 2191 500 3549 344 4580 20

0 262 9797 14097 13797 2097 2097 1097 97 97 97

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

NGCC HYDRO WIND PV

Figure 25: New and total capacity in Albania under the Increased Renewables scenario.

44

Major changes will occur in the generation portfolio of Albania under the Increased Renewables scenario compared to the previous scenario. Besides the planned 192 MW of new hydro capacity planned for 2019, another 70 MW should be added until the end of the year. As a matter of fact, 70 MW of hydro capacity will be added every year until 2025 in addition to the hydro capacity planned. Therefore, Albania will achieve its target for 750 MW of SHPPs in 2025. In total, Albania will increase its hydro capacity by 46% compared to the current fleet or by 21% compared to the previous scenarios. At the same time, new wind and solar capacity should become operational from 2020 to achieve the national targets of 70 MW and 120 MW by 2022 respectively. New installations will become available from 2023 onwards, at a slower pace, to achieve the final 2030 targets for 350 MW of wind and solar installations. Therefore, Albania will reach 350 MW of wind and solar capacity compared to 1 MW of solar capacity in the previous scenarios. On the other hand, the Vlora natural gas plants will become operational, as planned, in 2020, but no additional gas capacity will be necessary in the future. This is the case because over 800 MW of new renewable capacity will be installed compared to the previous scenarios. To conclude, the total operational installed capacity in 2037 in Albania will be almost 3.3 GW, out of which 86.3% or 2.81 GW will be hydro capacity. Therefore, the Albanian generation portfolio will become slightly more diversified (by 9%) compared to the previous scenarios, while thermal capacity will reduce to a share of 3%. It should be noted that the share of solar and wind capacity combined will exceed 10% with shares of 6.1% and 4.6% respectively. Despite the significant changes that will occur under the Increased Renewables scenario, hydropower will remain the cornerstone of the Albanian electricity system for the foreseeable future.

Electricity Mix 100%

80%

60%

40%

20%

0%

-20% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 -40%

NGCC HYDRO WIND PV NET TRADE

Figure 26: Electricity mix in Albania under the Increased Renewables scenario.

New solar and wind capacities will not only decrease Albania’s dependency on hydropower but will also reduce electricity imports during dry years. More specifically, solar energy will surpass 100 GWh annually from 2027 onwards and will even reach 128 GWh compared to less than 1 GWh produced under the Climate Change scenario. Likewise, wind power will gradually add 257 GWh annually to the Albanian electricity grid. From 2029 onwards, the share of wind and solar in gross electricity supply will be 2.7% and 1.3% until the end of the modelling period. On the other hand, the limited operation of the gas-fired plant will become even more limited under this scenario due to the extra renewable capacity. To be more specific, Vlora plant will produce just 3 GWh of electricity in 2035 compared to 38 GWh produced under the Climate Change scenario.

45

At the same time, the addition of 882 MW of new hydropower capacity will increase annual hydropower production along the modelling period. To more specific, during 2035, the driest year, 5,977 GWh will be produced compared to 4,942 produced under the Climate Change scenario. The same stands for 2025, the wettest year, with a production of 11,501 GWh compared to 9,756 GWh produced under the Climate Change Scenario. On average, an additional 1,366 GWh per year will be produced domestically instead of being imported compared to the Climate Change scenario. This value is lower, 766 GWh in 2021, for the short term, where the difference in installed capacity is small, and higher in the long term reaching an additional 2,230 GWh. This difference is clearly depicted in net electricity trade as well. During the eleven modelling years examined, Albania turned out to be a net electricity exporter by 3,729 GWh, while under the Climate Change scenario Albania will be a net electricity importer by 11,271 GWh. In other words, Albania will be a net electricity importer for 4 and 8 years under the Increased Renewables and Climate Change scenarios respectively. As seen in Figure 26, net electricity exports peaked in 2025 with a gross domestic supply share of 43% (3,556 GWh) compared to a share of 19% (1,558 GWh) achieved in the Climate Change scenario. On the other hand, net electricity imports will be the highest in 2035 with a share of 32% (2,961 GWh) compared to 47% (4,343 GWh) under the Climate Change scenario.

5.3.2. North Macedonia

New and Total Capacity (MW) 3000 80 90 90 73 73 2500 60 400 400 400 400 400 35 45 343 2000 343 343 3717 3717 13725 1398 1398 1398 1398 1500 667 737 1129 1299 830 870 959 1000 228 228 210 210 228 228 228 228 228 228 228 228 228 500 675 675 675 675 675 675 675 675 675 675 675 1008 20610 15 5720

0 70 93 40 10510 170 170 9910

New New New New New New New New New New New

Total Total Total Total Total Total Total Total Total Total Total 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV

Figure 27: New and total capacity in North Macedonia under the Increased Renewables scenario.

Lignite-fired capacity will remain a vital part of the North Macedonian electricity system. However, hydro capacity will double until 2030, compared to both the current situation and the previous scenarios, to achieve the targets set by the government. In total, 731 MW of new hydro capacity will be installed until 2030, compared to just 1 MW installed in the previous scenarios, and 16 MW will be decommissioned. On the other hand, no significant changes are expected for the Skopje CHP plant and the Negotino oil-fired plant compared to the previous scenarios. It is important to notice that new hydro and solar installations will slow down the growth of wind installations as seen in the previous scenarios. To be more specific, the need for new generation capacity, under the first two scenarios, boomed construction of wind farms because of their competitive techno-economic characteristics. In this case, capacity targets “force” more generation

46 capacity, hydro and solar, to be built irrelevant of their economic viability since it will be subsidized. Therefore, instead of adding wind capacity of 100 MW annually in 2020, 2021, 2022 and 63 MW in 2023, 100 MW will be built in 2020, 206 MW in 2023 and 57 MW in 2029. One way or another the total wind capacity potential of 400 MW will be saturated, including the existing Bogdanci wind farm (36.8 MW), and the target of 300 MW will be surpassed under all scenarios. The unambitious photovoltaic capacity target of 90 MW until 2030 will easily be achieved with installations ranging from 4 MW to 10 MW annually. The currently installed 17 MW of solar power should be refurbished by 2035 due to the operational life limit. In terms of total capacity installed, North Macedonia will have 2,774 MW of operational generation capacity as of 2037 compared to 1,834 MW currently. The thermal capacity share will drop from 46% to 32.6% with the individual shares of lignite and natural gas being 24.3% and 8.2% respectively. The share of hydro will skyrocket to 50.4% from one-third currently, while the shares of wind and solar will increase to 14.4% and 2.6% respectively.

Electricity Mix 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

COAL OIL NG CHP HYDRO WIND PV NET TRADE

Figure 28: Electricity mix in North Macedonia under the Increased Renewables scenario.

It is evident that the share of lignite will significantly be reduced from 2025 onwards to around 20% during normal years due to the increasing new renewable capacity installed and to a smaller extend due to the new interconnection line with Kosovo. As a matter of fact, 2,399 GWh will be produced from lignite on average annually, compared to 2,930 GWh in the Climate Change scenario. In other words, the lowest lignite share will be 19% or 1,467 GWh in 2031 compared to 34% or 2,675 GWh under the Climate Change scenario. However, increasing hydropower capacity by double to 1.4 GW will increase the variation in hydropower generation between normal and dry years. The shortage occurred from low hydropower production will primarily be covered from the Bitola lignite-fired plant and to a lesser extend from electricity imports. To be more specific, 2,272 GWh will be generated from hydropower in 2035 resulting in a deficit of 1,522 GWh compared to 2033, the majority of which (1,363 GWh) will be covered from the extended operation of the Bitola plant, while the rest will be imported. To continue, the annual average hydropower production will be 2,588 GWh compared to 1,555 GWh under the Climate Change scenario. Meaning that on average more electricity will be produced from hydropower compared to lignite. On the downside, annual hydropower production will range from 1,437 GWh to 3,794 GWh while in the Climate Change scenario it only ranges from 1,059 GWh to 1,848 GWh. As explained earlier, installed wind capacity will be the same, between the Climate Change and Increased Renewables scenarios, from 2030 onwards, but it will

47 grow at a slower pace in this case. Specifically, 168-292 GWh less will be produced annually from wind compared to the previous scenarios between 2020 and 2028, in most cases hydropower will compensate for the electricity deficit. Solar produced electricity will gradually increase from 18 GWh annually, currently and under the previous scenarios, to 95 GWh in 2030. Still the share of solar power in gross electricity supply will only be 1.2%. On the other hand, the change in electricity trade is much more important than the contribution of solar power to the electricity mix. In almost all modelling years net electricity imports have decreased by 519 GWh on average per year compared to the Climate Change scenario. The biggest decrease in net imports, compared to the previous scenario, will occur during dry years such as 2029 and 2035, where the reduction will be 999 GWh and 1,255 GWh respectively. Therefore, the share of net electricity imports, in gross electricity supply, during 2035 will be only 9% compared to 24%. This can be attributed to the fact that hydropower capacity has doubled, even though production per MW will be the same between the two scenarios. Overall, new renewable capacity will decrease net electricity imports from 18% to 12% of the gross electricity supply on average.

5.3.3. Economic and Environmental Impact

Discounted Capital Investments (million Euros) 100% 41,8 27,4 7,5 7 6,6 90% 10,6 9,9 9,4 41,5 80% 56 6,2 5,8 5,5 5,1 4,8 70% 60% 366,5 39,2 50% 0,4 530,6 116,6 111,1 101,2 40% 282 30% 8,8 8,3 7,9 7,4 7 122,5 20% 10% 82,6 0% 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

NGCC HYDRO WIND PV INTERCONNECTION

Figure 29: Discounted capital investments in million Euros in Albania under the Increased Renewables scenario. The majority of capacity investments in Albania will occur until 2025 as seen in Figure 29. The total amount will reach €2b out of which 80% or €1.6b will comprise of hydropower investments. Wind and solar installations will each attract €150m or 7% of the total amount, leaving behind the thermal power and interconnection investments with a combined value of €110m. Albania will more than double its investment on new HPPs compared to previous scenarios, with €1.6b compared to €770m. All other investments will attract more than €400m compared to €120m mainly due to the new wind and solar installations.

48

Discounted Capital Investments (million Euros)

100% 4,9 1,2 3,1 2,9 2,5 4,8 4,5 4,2 3,9 90% 17,8 80% 2,7 42,9 70% 60% 218,6 126,7 27,4 50% 31,9 93,4 127,9 55,2 106,5 101,4 96,6 102 40% 85,2 30% 92 20% 10% 58 21,8 3 0% 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

HYDRO WIND PV INTERCONNECTION

Figure 30: Discounted capital investments in million Euros in North Macedonia under the Increased Renewables scenario. Likewise, North Macedonia will triple its investment during the modelling period compared to the previous scenarios, from €465m to €1.4b. Its investment plan is more equally distributed throughout the modelling period compared to Albania’s as seen in Figure 30. However, the majority of investments will be made on hydropower with €972m or 67% of the total investments. Wind investments will attract €388m or 27% of the total amount, compared to €419m invested under the previous scenarios for the same wind capacity. This will occur because wind investments will take place at a later year, compared to the previous scenarios, and will therefore benefit from the reduced capital costs due to technological progress. Solar and interconnection investments will only achieve a share of 5.7% or €83m combined.

Total System Operating Cost 120

100

80

60

40

20 Operating Cost (Euro/MWh) 0 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037

Albania North Macedonia Albania CC North Macedonia CC

Figure 31: Total system operating cost under the Increased Renewables scenario. The system operating cost will follow the same trend as the cost under the Climate Change scenario as seen in Figure 31. The first thing to notice is that new generation capacity will reduce electricity imports and therefore the overall system cost along the modelling period. The variation in the cost between dry and wet years is clearly visible especially for Albania but also for North Macedonia unlike the previous scenarios. This is the case because North Macedonia will double its hydro

49 capacity portfolio and become more fragile to the fluctuation between dry and normal years. Therefore, one could argue that North Macedonia should invest less in hydropower and turn towards other renewables and/or energy storage to avoid the variation in hydropower produced electricity. On the other hand, the total cost for electricity in North Macedonia will decrease significantly in this scenario. On average, North Macedonia will reduce its system cost, compared to the Climate Change scenario, by 8.4 €/MWh achieving an average price of 78.8 €/MWh. This is the case due to reduction of electricity imports as explained previously. Also, it should be noticed that the savings are greater during normal years compared to dry years. For instance, price reduction will be 20.4 €/MWh in 2033 and only 4.9 €/MWh in 2035 compared to the Climate Change scenario. This will occur because the lignite-fired plant will operate significantly less, compared to the previous scenario, due to the high hydropower production during a normal year such as 2033. However, in 2035 the lignite-fired plant will operate at the maximum of its given capacity factor, not to mention the additional amount of electricity to be imported to cover the demand. Despite the fact that North Macedonia will decrease its system cost from current levels, in Albania the system cost will increase but a much slower pace compared to the previous scenarios. As a matter of fact, the average system cost will be reduced by 11.8 €/MWh reaching a value of 40.6 €/MWh compared to the Climate Change scenario. Again, this is the case because electricity imports will be reduced. However, the reduction in cost compared to the Climate Change scenario is more linear since the country’s dependency on hydropower variation is slightly smaller. Despite the new capacity installations, Albania will retain its domestic electricity supply almost 100% carbon-free, with emissions from the Vlora natural gas plant being insignificant due to its limited operated. However, indirect greenhouse emissions are released through the operation of the HPPs and the electricity generated outside the country but utilized inside its borders. The environmental impact of the North Macedonian electricity supply sector will definitely be reduced under the Increased Renewables scenario. Emissions will be stable at 4.2 MtCO2 until 2021 even though 271 MW of new renewable capacity will be installed. This is the case because new renewable capacity will substitute electricity imports and not the operation of the lignite-fired plant. However, as more and more renewable will be installed the operation of the plant will be reduced, especially during normal, concerning precipitation, years. During those years, such as 2031, emissions will reduce to even 2.2 MtCO2. On the other hand, annual emissions will be as high as 4.2 MtCO2 during dry years such as 2029 and 2035. On average, annual emissions will be reduced by 17% to 3.4 MtCO2 compared to the Climate Change scenario that exceeded 4 MtCO2.

50

6. Conclusions

The Western Balkan region is still facing challenges compared to the European Union not only in terms of energy transition but also concerning matters of security of energy supply with frequent blackouts still occurring especially in Albania. To be able to plan the supply side of the electricity system, a short-term forecast of the electricity demand should be conducted first. However, it seems that both state and third-party reports have projected growth in electricity demand, due to strong economic growth, that has not occurred so far or has not occurred in such a degree. Taking into account the above, the electricity consumption of the past years as well as the most recent reports on electricity demand, resulted in an annual growth of electricity demand of 1.3% and 0.7% for Albania and North Macedonia respectively. To be more specific, total final electricity demand will increase from 5,564 GWh to 7,488 GWh and from 6,104 to 7,166 GWh between 2017 and 2040 for Albania and North Macedonia respectively. To be able to cope with the increased electricity demand both countries will invest in new generation capacity. Albania will rely on its planned and under construction hydropower projects, while technoeconomic parameters seem to favor wind power in the case of North Macedonia. However, net electricity imports will increase in the near future leading to a status of reduced energy security. Even though electricity production from HPPs in Albania can be reduced by more than 400 GWh annually, under the Climate Change scenario, there will be no significant change in the country’s generation portfolio. Instead, the country will increase its electricity imports where necessary which will increase the energy dependency. This will also be the case for North Macedonia. However, the impact of climate change on the North Macedonian electricity system will be minimal for the next 20 years. On the other hand, net electricity imports will decrease significantly if both countries will achieve, even with a delay, their renewable electricity goals. However, this will come at an additional investment cost of €1.1b and €1b for Albania and North Macedonia respectively. Furthermore, the decrease in electricity imports will reduce import dependency, while at the same time the electricity cost will be reduced. Overall, climate change will influence the countries’ electricity system. However, it seems that a linear decrease in annual precipitation is not the biggest problem. The major challenge to tackle, is that the variation from dry to wet years, and seasons, will increase in the future. Additionally, both Albania and North Macedonia should proceed faster with their electricity market unbundling in order to attract investments for new generation capacity. Additionally, new investments should also be made on the electricity transmission and distribution infrastructure to reduce losses especially in the case of Albania. These changes along with a considerable share of renewable electricity will definitely have a positive impact during the countries’ European Union integration negotiations.

51

7. Limitations and Future Work

Every study conducted has certain limitations and assumptions and this study is not any different. To begin with, reliable and accurate data was hard to find. For instance, the electricity demand profile used was the average of only three past years and the installed capacity for small scale renewables, mainly hydro and solar, was outdated. Furthermore, many local technoeconomic parameters such as operational costs, electricity export prices, efficiencies, emissions etc. were not available and generic values were used instead. Not to mention the big gap in terms of precipitation and river flow measurements, where major assumptions were made that might not accurately reflect the impacts of climate change on these countries. In most cases, such data is available in various state ministries and agencies, but access is limited to third parties. Additionally, it seems that both Albania and North Macedonia do not have a solid energy strategy to be able to plan and be better prepared for future challenges. To be more specific, Albania has not published any official energy strategy report, besides the NREAP in 2015. Likewise, North Macedonia has published their NREAP in 2015 as well as an energy strategy report back in 2010 and a statement on energy security in 2017. Based on the preceding work, future work could include a more precise hydrological model executed for the major rivers in the region, given the fact that reliable data will be available. Furthermore, someone could test how fluctuating electricity import prices will affect the system price and/or new generation capacity to be installed. Also, a carbon price implementation, as part of a future EU admission, would drastically alter the generation mix of North Macedonia.

52

8. Bibliography

Causevski, A., & Nikolova, S. (2010). Contribution of Hydro Potential in Macedonian Power System. Ohrid. Filkoski, R. V., & Petrovski, I. J. (2007). Options for reactivation of 210 MWe oil-fired power plant. 6. AEA. (2017). Albania Energy Association. Retrieved February 13, 2019, from https://aea- al.org/albanias-shala-river-is-also-granted-concession-hpp-100-million-usd-investment/ Albania. (2015). Intended Nationally Determined Contribution (INDC) of the Republic of Albania following decision 1/CP.19 and decision 1/CP.20. Tirana: Republic of Albania. Albpetrol. (2018). Oil Production. Retrieved February 20, 2019, from https://www.albpetrol.al/en/prodhimi-i-naftes-nder-vite/ Aliko, A. (2010). RREGULATED TARIFFS FOR SHPP-S IN ALBANIA. Tirana: Albanian Energy Regulatory Authority. Balkan Energy. (2017). KESH sold 8,700 MWh of electricity for 16-18 December delivery. Retrieved March 7, 2019, from https://balkanenergy.com/kesh-sold-8700-mwh-electricity-16-18- december-delivery-albania-18-december-2017/ Bankwatch. (n.d.). The energy sector in Macedonia. Retrieved January 25, 2019, from https://bankwatch.org/beyond-coal/the-energy-sector-in-macedonia Barjaba, K., & Barjaba, J. (2015). Embracing Emigration: The Migration-Development Nexus in Albania. Retrieved 05 24, 2019, from https://www.migrationpolicy.org/article/embracing- emigration-migration-development-nexus-albania Bejtullahu, N. (n.d.). Common Electricity Market Kosovo-Albania. Pristina: Kosovan Transmission System & Market Operator. BGEN. (2016, November 18). Waste-to-energy plant to be built in Albania. Retrieved from Balkan Green Energy News: https://balkangreenenergynews.com/waste-energy-plant-built- albania/ BGEN. (2017a, May 9). First waste-to-energy plant inaugurated in Albania. Retrieved February 07, 2019, from Balkan Green Energy News: https://balkangreenenergynews.com/first-waste-to- energy-plant-inaugurated-in-albania/ BGEN. (2017b). Albania forced to import 80 percent of electricity due to drought. Retrieved December 5, 2018, from https://balkangreenenergynews.com/albania-forced-to-import-80-percent- of-electricity-due-to-drought/ BGEN. (2018). Albania won arbitration against Hydro S.R.L. over Kalivac HPP. Retrieved February 11, 2019, from https://balkangreenenergynews.com/albania-won-arbitration-italian-hydro-s- r-l-kalivac-hpp/ Breeze, P. (2016). Gas-Turbine Power Generation. Amsterdam: Academic Press. Bruci, E. D., Islami, B., & Kamberi, M. (2016). Third National Communication of the Republic of Albania under the United Nations Framework Convention on Climate Change. Tirana: Ministry of Environment.

53

Chenoweth, J., Hadjinicolaou, P., Bruggeman, A., Lelieveld, J., Levin, Z., Lange , M. A., . . . Hadjikakou, M. (2011). Impact of climate change on the water resources of the eastern Mediterranean and Middle East region: Modeled 21st century changes and implications. Water Resources Research, 47(W06506), 18. Cingoski, V., & Nikolov, I. (n.d.). Reduction of the development cost for SHPP utilizing a container-type mini hydropower plants. Skopje and Stip. Devoll Hydropower. (2014). Devoll hydropower project overview. Retrieved February 4, 2019, from http://www.devollhydropower.al/new/?page_id=7419 DNV GL. (2018). Energy Transition Outlook 2018: A global and regional forecast to 2050. Oslo: DNV GL. Dworak, T., Meon, G., Docaj, E., Doko, A., & Metaj, M. (2016). POTENTIAL OF MULTIPURPOSE-USE OF THE HYDROPOWER RESERVOIRS OF THE DRINI CASCADE IN ALBANIA. Deutsche Gesellschaft fur Internationale Zussamenarbeit. EA. (2011). Skopje: Energy Agency of the Republic of North Macedonia. Ebinger, J. (2010). Albania’s Energy Sector: Vulnerable to Climate Change. The World Bank. EC. (2018). Annual Implementation Report. Vienna. Ekounia. (n.d.). Macedonia General Information. Retrieved February 20, 2019, from http://eko- unia.org.pl/en/situation-macedonia/ ELEM. (2016). Hydroenergy. Retrieved February 18, 2019, from http://www.elem.com.mk/wp- content/uploads/2015/hidroenergija_en.html ELEM. (2018). Development and Investment Plan 2018-2022. Skopje: ELEM Macedonian Power Plants. ENTSOE. (n.d.). Monthly Hourly Load Values. Retrieved February 02, 2019, from https://www.entsoe.eu/data/power-stats/hourly_load/ ERC. (2019). PRICING - OIL AND OIL DERIVATIVES. Retrieved February 15, 2019, from http://www.erc.org.mk/pages_en.aspx?id=161 ERE. (2016). Report of the Electricity Market Operation year 2015. Tirana: Albanian Energy Regulatory Authority. ETSAP. (n.d.). MARKAL. Retrieved March 1, 2019, from https://iea- etsap.org/index.php/etsaptool/model-generators/markal Eurostat. (2018). Gas prices, First semesters of 2016-2018 (EUR per kWh). Retrieved February 10, 2019, from https://ec.europa.eu/eurostat/statistics- explained/index.php?title=File:Gas_prices,_First_semesters_of_2016- 2018_(EUR_per_kWh).png Fida, E., Islami, B., Bruci, E. D., Baraj, B., Kamberi, M., Mucaj, L., & Ndini, M. B. (2009). Security of the Energy Sector in Albania in the Face of Climate Change. Tirana. Howells, M., Rogner, H., Strachan, N., Heaps, C., Huntington, H., Kypreos, S., . . . Bazillian, M. (2011). OSeMOSYS: the open source energy modeling system: an introduction to its ethos, structure and development. Energy Policy, 39(10), 5850-5870. IEA. (2010). Energy Technology Perspectives. Paris: International Energy Agency.

54

IEA. (2018a). Albania: Balances for 2016. Retrieved November 27, 2018, from https://www.iea.org/statistics/?country=ALBANIA&year=2016&category=Key%20in dicators&indicator=TPESbySource&mode=chart&categoryBrowse=false&dataTable=B ALANCES&showDataTable=true IEA. (2018b). FYROM: Balances for 2016. Retrieved November 27, 2018, from International Energy Agency: https://www.iea.org/statistics/?country=FYROM&year=2016&category=Coal&indicat or=CoalProdByType&mode=chart&dataTable=COALANDPEAT INSTAT. (2018). Balance of Electric Power. Retrieved February 03, 2019, from http://www.instat.gov.al/en/themes/environment-and-energy/energy/#tab3 IPCC. (2014). Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Geneva, Switzerland: IPCC. Jonuzaj, K. (2018). Albania’s KESH invites bids for power exports for April 23-30 delivery. Retrieved March 7, 2019, from https://renewablesnow.com/news/albanias-kesh-invites-bids-for- power-exports-for-april-23-30-delivery-609817/ Jonuzaj, K. (2019). Albania invites bids for PPP/concession deal on Vlora TPP, construction of gas link to TAP. Retrieved February 22, 2019, from https://seenews.com/news/albania-invites- bids-for-pppconcession-deal-on-vlora-tpp-construction-of-gas-link-to-tap-638450 Jovanović, S. (2018a). Albania invites bids to build 50 MW PV power station with support measures, plus up to 50 MW without. Retrieved January 19, 2019, from https://balkangreenenergynews.com/albania-invites-bids-to-build-50-mw-pv-power- station-with-support-measures-plus-up-to-50-mw-without/ Jovanović, S. (2018b). Energy Community adopts decision lowering Macedonia’s 2020 renewables target from 28% to 23%. Retrieved January 29, 2019, from https://balkangreenenergynews.com/energy-community-adopts-decision-lowering- macedonia-2020-renewables-target-from-28-to-23/ Kavouridis, K., Roumpos, C., & Galetakis, M. (2007). THE EFFECT OF POWER PLANT EFFICIENCY, LIGNITE QUALITY AND INORGANIC MATTER ON CO2 EMISSIONS AND COMPETITIVENESS OF GREEK LIGNITE. KESH. (2016). TEC Vlora. Retrieved from Albanian Power Corporation: http://www.kesh.al/info.aspx?_NKatID=1197 KESH. (2017). KESH Activity Report 2013-2016. Tirana: KESH. Lazaj, L., & Xhelilaj, R. (2017). Mapping of hydropower plant in Albania, using Geographic Information System. CSO. MAKSTAT. (2018). Balance of Electrical Energy. Retrieved February 05, 2019, from Republic of Macedonia State Statistical Office: http://www.stat.gov.mk/PrethodniSoopstenijaOblast_en.aspx?id=117&rbrObl=21 MEI. (2016a). National Action Plan for Renewable Energy Resources in Albania 2015-2020. Tirana: Ministry of Energy and Industry. MEI. (2016b). Renewable Energy Sources Albania. Vienna: Ministry of Energy and Industry.

55

Mejdini, F. (2016). New Power Line to Link Albania to Macedonia. Retrieved March 11, 2019, from https://balkaninsight.com/2016/07/26/albania-ready-to-start-the-interconnection-line- with-macedonia-07-25-2016/ Messenger, B. (2016). First Anaerobic Digestion Biogas Plant Opened in Macedonia. Retrieved January 30, 2019, from https://waste-management-world.com/a/first-anaerobic-digestion-biogas- plant-opened-in-macedonia Mezősi, A., & Szabó, L. (2015). Decarbonisation modelling in the electricity sector Albania. Regional Centre for Energy Policy Research. Mezősi, A., Szabó, L., & al., e. (2017). South East Europe Electricity Roadmap Country Report Albania. MM. (2017). REGIONAL STRATEGY FOR SUSTAINABLE HYDROPOWER IN THE WESTERN BALKANS. Mott Macdonald. MoE. (2010). Strategy for Energy Development in the Republic of Macedonia until 2030. Skopje: Ministry of Economy. MoE. (2015). RENEWABLE ENERGY ACTION PLAN FOR THE REPUBLIC OF MACEDONIA UNTIL 2025 WITH VISION UNTIL 2030. Tirana: GOVERNMENT OF THE REPUBLIC OF MACEDONIA MINISTRY OF ECONOMY. MoE. (2017). STATEMENT ON SECURITY OF ENERGY SUPPLY REPUBLIC OF MACEDONIA. Skopje: Ministry of Economy. MoEPP. (2008). Second National Communication on Climate Change. Skopje: Ministry of environment and physical planning. N. Macedonia. (2015). Submission by the Republic of Macedonia Intended Nationally Determined Contributions. Skopje: Republic of North Macedonia. Pomykacz, M., Olmsted, C., & MAI. (2014). The Appraisal of Power Plants. Chicago: Appraisal Institute. PVEurope. (2018). Albania increases renewable energy targets. Retrieved February 28, 2019, from https://www.pveurope.eu/News/Markets-Money/Albania-increases-renewable-energy- targets Renewables Ninja. (2019). Renewables Ninja. Retrieved April 05, 2019, from https://www.renewables.ninja/ SEECAO. (2019). Coordinated Auction Office in South East Europe. Retrieved February 14, 2019, from http://seecao.com/yearly-result?Year_selective=2017 Serbia Energy. (2017). Macedonia: ELEM will import electricity at 36.4 euros/MWh. Retrieved March 7, 2019, from https://serbia-energy.eu/macedonia-elem-will-import-electricity-36-4- eurosmwh/ Spasić, V. (2017). EUR 300 million investments in renewable energy projects in Albania. Retrieved February 6, 2019, from https://balkangreenenergynews.com/eur-300-million-investments-in- renewable-energy-projects-in-albania/ Spasić, V. (2019). Balkan Green Energy News. Retrieved January 20, 2019, from https://balkangreenenergynews.com/voith-to-supply-equipment-for-small-hydropower- plant-gradiste/ Sufaj, D. (2015). Global Financial Crisis of 2007: The Case of Albania. Mediterranean Journal of Social Sciences, 6(4), 130-137.

56

Tieman, A. (2010). The Electricity Sector in FYR Macedonia. International Monetary Fund. Tuneski, A. (n.d.). ELECTRICITY IMPORT AND FISCAL ISSUES IN THE REPUBLIC OF MACEDONIA. Skopje: Macedonian Transmission System Operator. UNDP. (2012a). Renewable Energy Snapshot: Albania. United Nations. UNDP. (2012b). Renewable Energy Snapshot: The Former Yugoslav Republic of Macedonia. United Nations. Verbund. (2008). VERBUND Signs Ashta Power Plant Contract with Albanian Government. Retrieved February 4, 2019, from https://www.verbund.com/en-de/about-verbund/news- press/press-releases/2008/09/30/vertrag-ashta Vuković, A., & Mandić, M. V. (2018). Study on climate change in the Western Balkans region. Sarajevo: Regional Cooperation Council. World Bank. (2009). Adapting to Climate Change in Europe and Central Asia. Washington: World Bank. World Bank. (2009). CLIMATE VULNERABILITY ASSESSMENTS: An Assessment of Climate Change Vulnerability, Risk, and Adaptation in Albania’s Power Sector. Energy Sector Management Assistance Programme. World Bank. (2010). The Former Yugoslav Republic of Macedonia Climate Change and Agriculture Country Note. Washington: World Bank. World Bank. (2011). Albania Climate Change and Agriculture Country Note. Washington: World Bank. World Bank. (2013). Public-Private Partnership Impact Stories Albania: Ashta Hydropower. Washington: World Bank. World Bank. (2014). Electric power transmission and distribution losses (% of output). Retrieved February 15, 2019, from https://data.worldbank.org/indicator/EG.ELC.LOSS.ZS?end=2014&locations=EU&st art=1999 World Bank. (2017a). Albania. Retrieved November 27, 2018, from https://data.worldbank.org/country/albania World Bank. (2017b, October 5). FYR Macedonia Overview. Retrieved January 15, 2019, from The World Bank: http://www.worldbank.org/en/country/fyrmacedonia/overview World Bank. (2019). Climate Change Knowledge Portal. Retrieved February 21, 2019, from http://sdwebx.worldbank.org/climateportal/index.cfm?page=country_historical_climat e&ThisCCode=ALB Xhafa, B. (2009). Financial Appraisal on a Hydropower Plant. A Case Study in Albania. Gazimağusa: Eastern Mediterranean University.

57

Appendix A: Technical Parameters

Reservoir AVG Basin/(Sub)River Capacity Started Design Plant River Type Storage Volume Turbine Output Basin (MW) Operation CF (%) (million m3) (GWh) Fierza/Drin Cascade Drin Drin-Bune DAM 2350 500 Francis 4*125 1976 1466 35,3 Komani/Drin Cascade Drin Drin-Bune DAM 188 600 Francis 4*150 1985 1794,4 32,8 Vau Dejes/Drin Cascade Drin Drin-Bune DAM 310 250 Francis 5*50 1970 952,4 40,2 Bistrica 1 & 2 cascade Bistrica Bistrica ROR n/a 22,5 n/a 1962 128,7 60,7 Ulza Ulzes Mat DAM 10 25,2 Kaplan 4*6,25 1954 111,2 47,7 Shkopeti Shkopeti Mat DAM 124 25 Kaplan 2*12,5 1956 70,8 33,4 Ashta 1 Drin Drin-Bune ROR n/a 22,2 45*0,438 2013 216,3 36 Ashta 2 Drin Drin-Bune ROR n/a 34,2 45*0,6338 2013 0 55,1 Vlushe Corovode Osumi ROR n/a 14,2 Pelton Vert 2*7,1 2014 12,2 36 Sllabinje (Fterre Sarande) Shkumbin Shkumbin ROR n/a 13,8 1*13,8 2012 31 36 Martanesh (Bulqize) Okshtunit n/a ROR n/a 10,5 n/a 2012 15 36 Pobreg Luma Drin ROR n/a 12,7 n/a 2013 28,1 36 Liapaj Bushtrica Drin ROR n/a 13,62 Pelton 2*6,81 2012 36,1 36 Bele 2 Luma Drin ROR n/a 11 Francis 3*3,7 2015 0 36 Tervol Holte Devoll ROR n/a 12 n/a 2012 32,9 36 Okshtun+Temove+Lubalesh 1 Okshtunit Drin DAM 10,7 15 Pelton 3*5 2016 n/a 36 Lubalesh 2+Gjorice Okshtunit Drin ROR n/a 10,9 Francis 3*3,7 2014 n/a 36 Banja Devoll Seman DAM n/a 73 Francis 3*24,3 n/a n/a n/a Total - - - - 1666 - - - - Table 7: Hydropower plants in Albania above 10 MW.

58

Output Design Basin/(Sub)River Capacity Started in Plant Operator River Type Output Basin (MW) Operation 2015 (GWh) (GWh) Tirana n/a n/a n/a n/a n/a 1951 n/a 0,00 Selita n/a n/a n/a n/a 5,00 1952 n/a 0,00 Queparo n/a n/a n/a n/a n/a 1960 n/a 0,00 Theth (Theti) Shala Energy Thethit Drin n/a n/a 1966 n/a 0,00 Bistrica I and II Hec Bistrica 1 dhe Bistrice Vjosa ROR 5,00 1967 36,7 0,00 cascade /Bistrica 2 2 sha Curraj-Epshem n/a Curraj Drin n/a n/a 1969 n/a 0,00 Dragobia (Dragobi) n/a Valbone Drin n/a n/a 1969 n/a 0,00 Cerem (Ceremi) T-Plani shpk Valbone Drin n/a n/a 1969 n/a 0,00 Bradazhnice n/a n/a n/a n/a n/a 1975 n/a 0,00 Kelcyre (Kelcyra) n/a Vjosa Vjosa n/a n/a 1978 n/a 0,00 Labinot-Mal Ansara shpk Zaranikes Shkumbin ROR 0,25 2008 1,3 0,00 (Elbasan) Gjanc Spahiu Gjanc shpk. Osumi/Leshnje Seman n/a 2,96 2010 n/a 8,20 Albanian Green Smokthine Smokthine Vjosa n/a 9,20 2010 n/a 32,10 Energy shpk Bene Marjakaj sh.p.k n/a n/a n/a 1,00 2010 n/a 1,20 Selce Selca Energji sh.p.k n/a n/a n/a 1,60 2010 n/a 2,20 Bogove (Skrapar) Wonder Power Bogove Seman n/a 2,50 2010 n/a 7,70 Xhyre (Librazhd) AMAL n/a n/a n/a 0,25 2010 n/a 2,00 Vithkuq (Korce) FAVINA I n/a n/a n/a 2,72 2010 n/a 10,90 Orenje (Librazhd) Juana n/a n/a n/a 0,88 2010 n/a 1,10 Bishnica 2 HEC BISHNICA 1,2 Bistrica Vjosa n/a 2,50 2010 12,91 11,30

59

“Dishnica Energy” Dishnica Dishnice Seman n/a 0,20 2010 0,8 0,60 shpk Elektro Lubonje Lubonje Lubonje Shkumbin n/a 0,30 2010 n/a 0,30 shpk Gizavesh Dosku Energy shpk n/a n/a n/a 0,50 2011 n/a 2,50 Carshove ERMA MP shpk Carshove Vjosa n/a 1,50 2011 n/a 3,60 Sasaj (Sarande) Energo - Sas shpk n/a n/a n/a 7,00 2011 n/a 25,00 Malido-Energji Klos (Mirdite) Fan Mat n/a 1,95 2012 n/a 2,80 shpk Peshku (Burrel) PESHK Licone/Lene/Theken Mat n/a 3,43 2012 n/a 12,20 Kumbull- Merkurth DN & NAT Kumbulles Mat n/a 0,83 2012 n/a 1,40 (Mirdite) Energyshpk Dardhe Wenerg shpk Dardhe Drin n/a 5,80 2012 n/a 9,30 Selishte Selishte shpk Madh Drin n/a 2,00 2012 n/a 5,70 Picar 1 Peshku Picar 1 Reza e Kolonjes n/a n/a 0,20 2013 1,2 0,50 (Gjirokaster) shpk Qafzeze ÇAUSHI ENERGJI Shtikes Seman n/a 0,40 2013 2,87 1,80 Mollaj ENERGJI XHAÇI Dunavec Shkumbin n/a 0,60 2013 1,98 1,00 Bekim Energjitik Kryezi 1 Madh Mat n/a 0,60 2013 n/a n/a shpk Bekim Energjitik Kryezi i Eperm Madh Mat n/a 0,20 2013 n/a n/a shpk Euron Energy Bele 1 Lumi Luma Drin n/a 5,00 2013 n/a n/a Group shpk Euron Energy Topojan 2 Lumi Luma Drin n/a 5,80 2013 n/a n/a Group shpk Energy partners Al Shkalle Benjit Mat n/a 1,60 2013 n/a n/a shpk

60

Energy partners Al Cerunje 1 Benjit Mat n/a 2,30 2013 n/a n/a shpk Energy partners Al Cerunje 2 Benjit Mat n/a 2,80 2013 n/a n/a shpk Energy partners Al Klos n/a n/a n/a 2,30 2013 n/a n/a shpk Energy partners Al Rrype n/a n/a n/a 3,60 2013 n/a n/a shpk Shemri Erald Energy Leproit Drin n/a 1,00 2013 n/a n/a Mgulle Erald Energy Leproit Drin n/a 0,80 2013 n/a n/a Koka1 SNOW ENERGY Licones Mat n/a 3,20 2013 n/a 5,20 Tucep HEC TUCEP Tucepit Drin n/a 0,40 2013 n/a 1,00 C&S Construction Rapuni 1 Rapun Shkumbin n/a 4,10 2013 n/a n/a Energy shpk C&S Construction Rapuni 2 Rapun Shkumbin n/a 4,00 2013 n/a n/a Energy shpk Lu & Co Eco Energy Ostreni i Vogel Tucepit Drin n/a 0,32 2014 1,85 0,80 shpk Hec Qarr & Qarr n/a n/a n/a 1,00 2014 n/a n/a Kaltanjshpk Hec Qarr & Kaltanj n/a n/a n/a 0,50 2014 n/a n/a Kaltanjshpk Idro Energia Pulita Langarica 3 Langarice Vjosa n/a 2,20 2014 n/a 1,48 shpk Idro Energia Pulita Gostivisht n/a n/a n/a 1,30 2014 n/a n/a shpk Idro Energia Pulita Ura e Dashit n/a n/a n/a 1,20 2014 n/a n/a shpk

61

Hidro Energy Sotire Sotira 1&2 Sotire Seman n/a 2,20 2014 8,58 5,90 shpk Murdhar 1 HydroEnergy shpk Zallit Drin n/a 2,68 2014 n/a n/a Murdhar 2 HydroEnergy shpk Zallit Drin n/a 1,00 2014 n/a n/a Kozel E.T.H.H. shpk Kozeli Seman n/a 0,50 2014 n/a n/a Helmes 1 E.T.H.H. shpk Kozeli Seman n/a 0,80 2014 n/a 1,11 Helmes 2 E.T.H.H. shpk Kozeli Seman n/a 0,50 2014 n/a 0,38 ZALL HERR ENERGJI Cekrez 1 Lumi Terkuze Ishem/Erzen n/a 0,43 2014 n/a n/a 2011 ZALL HERR ENERGJI Cekrez 2 Lumi Terkuze Ishem/Erzen n/a 0,23 2014 n/a n/a 2012 Trebisht SA-GLE KOMPANI Trebisht Drin n/a 1,78 2014 8,05 1,30 Radove MTC ENERGY Carshove Vjosa n/a 2,50 2014 11,6 7,64 Topojan 1 ALB ENERGY Lumi Luma Drin n/a 2,90 2015 n/a 0,00 Orgjost I Ri Energal shpk Lumi Luma Drin n/a 4,80 2015 n/a 13,70 Perrollaj FATLUM n/a n/a n/a 0,50 2015 n/a 0,21 Truen TRUEN Truen Drin n/a 2,50 2015 n/a 2,90 Stravaj STRAVAJ ENERGY Frangovisht Shkumbin n/a 3,60 2015 16,32 7,64 Kacni KISI BIO ENERGJI Peshkut Drin n/a 3,87 2015 n/a 1,69 Shutine SHUTINA Shutines Fan n/a 2,40 2015 n/a 0,84 GURSHPAT Gurshpate 1 Gur Shpat Shkumbin n/a 0,84 2015 n/a 6,30 ENERGY GURSHPAT Gurshpate 2 Gur Shpat Shkumbin n/a 0,83 2015 n/a n/a ENERGY Hurdhas 1 KOMP ENERGJI Hurdhas Mat n/a 1,71 2015 n/a 2,82 Hurdhas 2 KOMP ENERGJI Hurdhas Mat n/a 1,30 2015 n/a n/a Hurdhas 3 KOMP ENERGJI Hurdhas Mat n/a 1,20 2015 n/a n/a Treska 2 Hec-Treske shpk Nikolices Seman n/a 0,62 2015 n/a n/a

62

Treska 3 Hec-Treske shpk Nikolices Seman n/a 0,40 2015 n/a n/a Treska 4 Hec-Treske shpk Nikolices Seman n/a 3,60 2015 n/a 2,58 Borove DITEKO shpk Okshtunit Drin n/a 1,92 2015 n/a n/a Zabzun DITEKO shpk Okshtunit Drin n/a 0,30 2015 n/a n/a Sebishte DITEKO shpk Okshtunit Drin n/a 2,84 2015 n/a n/a Prodan 1 DITEKO shpk Okshtunit Drin n/a 0,38 2015 n/a n/a Prodan 2 DITEKO shpk Okshtunit Drin n/a 0,80 2015 n/a n/a Okshtun Ekologjik DITEKO shpk Okshtunit Drin n/a 0,45 2015 n/a n/a Ternove DITEKO shpk Liqeni I Zi Drin n/a 0,92 2015 n/a n/a Lubalesh 1 DITEKO shpk Okshtunit Drin n/a 4,60 2015 n/a 9,71 Lubalesh 2 DITEKO shpk Okshtunit Drin n/a 5,10 2015 n/a n/a Gjorice DITEKO shpk Okshtunit Drin n/a 4,18 2015 n/a n/a Lengarica & Energy Lengarica Langarice Vjosa n/a 8,94 2015 n/a 1,40 sh.p.k MESOPOTAM Driza Bence Vjosa n/a 3,41 2015 n/a 0,31 ENERGY Bistrica 3 Energy Bistrica 3 n/a n/a n/a 1,53 2015 n/a 0,53 shpk Strelce Strelca Energy shpk n/a n/a n/a 1,5 2015 n/a 0,34 Projeksion Energji Treska 1 n/a n/a n/a 0,13 2015 n/a 0,08 sh.a. Lanabregas 1+2 HPP Lanabregas Lumi I Lanes Ishem/Erzen n/a 5,00 n/a 37 n/a Borshi (also Borsh) BGE shpk Borsh Vjosa n/a 0,25 n/a n/a n/a Bulqize BGE shpk Hutres Drin n/a 0,60 n/a n/a n/a Funares BGE shpk Lurnikut Shkumbin n/a 1,92 n/a n/a n/a Lunik BGE shpk Lunik Shkumbin n/a 0,20 n/a n/a n/a Nikolica (also BGE shpk Nikolices Seman n/a 0,70 n/a n/a n/a Nikolice)

63

Vithkuq Favina 1 shpk Shtyllasit Seman n/a 0,00 n/a n/a n/a Orgjost BGE shpk Orgjost Drin n/a 1,20 n/a n/a n/a Lekbibaj BGE shpk Curraj Drin n/a 1,40 n/a n/a n/a Velcan BGE shpk Velcanit Shkumbin n/a 1,20 n/a n/a n/a Zerqan BGE shpk Zalli Bulqizes Drin n/a 0,63 n/a n/a n/a Leshnice (also BGE shpk Leshnice Vjosa n/a 0,38 n/a n/a n/a Leshnica) Shoshan (Shoshaj) BGE shpk Valbone Drin n/a 0,00 n/a n/a n/a Kerpice BGE shpk Kerpice Shkumbin n/a 0,42 n/a n/a n/a Barmash BGE shpk Barmash n/a n/a 0,63 n/a n/a n/a Homesh BGE shpk Zogjajt Drin n/a 0,33 n/a n/a n/a Muhur BGE shpk Peshkut Drin n/a 0,25 n/a n/a n/a Marjan BGE shpk n/a n/a n/a 0,20 n/a n/a n/a Arras (also Arres or BGE shpk Seman Seman n/a 4,80 n/a n/a n/a Arrez) Dukagjin BGE shpk Shale Drin n/a 0,64 n/a n/a n/a Lure (also Lura) BGE shpk Lures Drin n/a 0,75 n/a n/a n/a Ujanik BGE shpk Shtikes Seman n/a 0,63 n/a n/a n/a Voskopoje BGE shpk Sules Seman n/a n/a n/a n/a n/a Piqeras (also BGE shpk Piqeras Vjosa n/a n/a n/a n/a n/a Piqerras) Rajan BGE shpk Rajan Vjosa n/a 1,02 n/a n/a n/a Lozhan BGE shpk Dolanit Seman n/a 0,10 n/a n/a n/a Borje ENERGJI Borjes Drin n/a 1,50 n/a n/a n/a Oreshke ENERGJI Lumi Luma Drin n/a 5,60 n/a n/a n/a Carnaleva ENERGJI Borjes Drin n/a 2,95 n/a n/a n/a Carnaleva 1 ENERGJI Borjes Drin n/a 3,27 n/a n/a n/a

64

HP OSTROVICA Faqekuq 1 Lumi Vlushes Seman n/a 3,00 n/a n/a n/a shpk HP OSTROVICA Faqekuq 2 Lumi Vlushes Seman n/a 3,40 n/a n/a n/a shpk Stranik Hidroinvest 1 shpk n/a n/a n/a 1,60 n/a n/a n/a Zall Tore Hidroinvest 1 shpk Zall Tore Shkumbin n/a 2,60 n/a n/a n/a Belesova 1 (Lumas Korkis 2009 shpk Belisoves Berat Seman n/a 0,15 n/a n/a n/a Berat) Belesova 2 Korkis 2009 shpk Belisoves Berat Seman n/a 0,28 n/a n/a n/a Fterra 1 Hidro Borshi shpk Lumi Fterre Vjosa n/a 1,08 n/a n/a n/a Fterra 2 Hidro Borshi shpk Lumi Fterre Vjosa n/a 2,00 n/a n/a n/a Lura 1 ”Erdat Lura” shpk Molla Lures Drin n/a 6,54 n/a n/a 39,96 Lura 2 ”Erdat Lura” shpk Molla Lures Drin n/a 4,02 n/a n/a n/a Lura 3 ”Erdat Lura” shpk Molla Lures Drin n/a 5,66 n/a n/a n/a Hydro power Plant Verba 1 n/a n/a n/a 2,00 n/a n/a n/a Of Korca shpk Hydro power Plant Verba 2 n/a n/a n/a 3,00 n/a n/a n/a Of Korca shpk Projeksion Energji Çarshove Carshove Vjosa n/a 0,07 n/a n/a n/a sh.a. Projeksion Energji Rehove n/a n/a n/a 0,10 n/a n/a n/a sh.a. Devy shpk & Zyfi n/a Nice Verbes Seman 0,60 n/a 2,74 n/a shpk Nishove 1 Nishova shpk Nishoves Seman n/a 1,11 n/a 6,91 n/a Meshanik Drini 2000 Bence Vjosa n/a 1,65 n/a n/a n/a Guve Drini 2001 Bence Vjosa n/a n/a n/a n/a n/a Ferrar shpk & Alfa n/a Bence Bence Vjosa 5,4 n/a n/a n/a Projekt

65

Ferrar shpk & Alfa n/a Tepelene Bence Vjosa n/a n/a n/a n/a Projekt Gramozi shpk & n/a Ujanik 2 Ujanikut/Tomorrices Seman 1,9 n/a 9,58 n/a Ujanik II shpk Kaskada e Luses 1- Komp Energji & n/a Lusses Mat 6,8 n/a 31 n/a 7 STGC Total 273 259,2 Operational Total 263 259,2 Table 8: Hydropower Plants in Albania below 10 MW.

Reservoir AVG Basin/(Sub) Storage Capacity Design Plant River Type Turbine Started Operation Output River Basin Volume (MW) CF (%) (GWh) (million m3) Kalimanci Bregalnica Vardar DAM 127 13,6 2*6,9 1970 25 21 Vrben/Mavrovo Korab Vardar ROR n/a 12,8 2*6,4 1959 38 33,9 Francis Shpilje Radika Black Drin DAM 506 84 1969 272 37 3*28 Francis 2 in 1968 & 2 in Tikvesh Reka Cma Vardar DAM 479,6 112 144 14,2 4*28 1981 Vrutok/Mavrovo Korab Vardar DAM 376 165,6 4*41,4 1973 350 24,1 Raven/Mavrovo Korab Vardar ROR 376 21 3*7 1973 42 22,5 Globocica Black Drin Black Drin DAM 55,3 42 2*21 1965 180 48,9 Francis Kozjak Treska Vardar DAM 550 82,5 2004 130 18,1 2*42 Sveta Petka Francis Treska Vardar DAM 9 36 2012 43 13,5 (Matka 2) 2*18 Total 569,5 1224 25,9 Table 9: Hydropower plants in North Macedonia above 10 MW.

66

Reservoir Output Storage Capacity Started Design Plant Operator River Basin/(Sub)River Basin Type Turbine in 2015 Volume (MW) Operation CF (%) (GWh) (million m3)

Matka (New) EVN AG Treska Vardar DAM 3,7 9,6 2x4,8 MW 2007 37,4 35,67 1x1,28 Pena EVN AG Pena Vardar ROR n/a 3,3 1927 12,7 38,05 MW+1x2MW Zrnovci EVN AG Zrnovska Bregalnica ROR n/a 1,6 2x0,8 MW 1950 7,5 34,25 Pesočani EVN AG Pesocanska Lake Ohrid, Crn Drim ROR n/a 2,88 2x1,76 MW 1951 12,4 41,62 Sapunčica EVN AG Sapunčica Dragor, Crna Reka ROR n/a 2,9 2x1,76 MW 1952 13,7 43,3 Dosnica EVN AG Dosnica Vardar ROR n/a 5,1 3x1,7 MW 1953 28,9 41,41 Popova Šapka EVN AG N/A n/a ROR n/a 4,8 4x1,2 MW 1993 22,3 47,56 cascade Turija EVN AG Turija Strumesnica DAM 48 2 2x1 MW 1985 0,7 8,56 Babuna EVN AG Babuna Vardar ROR n/a 0,64 2x0,32 MW 1994 1,7 14,27 Belica 1 cascade DOOEL Belica Reka, Treska ROR n/a 0,25 1x0,25 MW 1989 0,6 27,4 Belica 2 cascade VODAVAT n/a n/a n/a n/a 1 n/a n/a 0 25 SOL SEE, JP Lukar Kavadarci Old River n/a ROR n/a 1,3 n/a 2003 0 25 Komunalac Filternica n/a n/a n/a n/a n/a 0,38 n/a 1997 0 25 Streževo 1 JP Strezevo Semnica n/a DAM n/a 2,4 3x0.8 MW 1992 0 25 Biološki JP Strezevo Semnica n/a DAM n/a 0,13 n/a 1994 0 25 Dovlednjik JP Strezevo Semnica n/a DER n/a 0,46 n/a 1997 0 25 Filternica JP Strezevo Semnica n/a DER n/a 0,38 n/a 1997 0 25 MHE (Ohrid 1) MHE Vodovod Ohrid n/a ROR n/a 0,12 1X0,117 2010 0,2 8,24

67

MHE (Ohrid 2) MHE Vodovod Ohrid n/a ROR n/a 0,32 1x0,320 2010 1,3 36,99 MHE (Ohrid 3) MHE Vodovod Ohrid n/a ROR n/a 0,23 1x0,229 2010 0,8 28,65 MHE (Belica 1) MHE Vodovod Ohrid n/a ROR n/a 1 1X0,995 2010 3,3 35,29 MHE (Belica 2) MHE Vodovod Ohrid n/a ROR n/a 1 1X0,996 2010 3 32,75 DIKOM DOOEL DIKOM n/a n/a ROR n/a 0,03 1x0,032 2010 0,1 18,3 Kavadarci VODOVOD HIDROENERGO Glaz n/a ROR n/a 0,4 1x0,4 2010 1,9 48,77 BITOLA DOOEL BITOLA Studencica Mali Studencica Studencica n/a ROR n/a 0,6 1x0,6 2011 3 50,97 hidro DOO Skopje Mali hidro Krkljanska reka elektrani DOO Krkljanaska river Pcinja/Vardar ROR n/a 0,38 1x0,384 2012 1,3 28,94 Skopje Fero invest DOO Slatino Slatinska reka reka/Ohrid Lake/Crn ROR n/a 0,56 1x0,560 2012 1,7 28,01 Skopje Mali hidro Brbushnica elektrani DOO Brbushnica Bregalnica/Vardar ROR n/a 0,58 1x0,576 2012 1,9 29,04 Skopje Mali hidro Kranska reka elektrani DOO Kranska reka Lake/Crn Drim ROR n/a 0,58 1x0,584 2012 2 34,1 Skopje Mali hidro Kriva reka 2 elektrani DOO Kriva reka Pcinja/Vardar ROR n/a 0,58 1x0,584 2012 2 32,52 Skopje Mali hidro Brajcinska(Stara) Brajcino 1 elektrani DOO Lake/Crn Drim ROR n/a 0,7 1x0,704 2013 2,4 36,52 reka Skopje Mali hidro Kamenicka reka elektrani DOO Kamenicka reka Bregalnica/Vardar ROR n/a 1,2 1x1,2 2013 5,9 41,98 Skopje

68

EMK Mali Ljubanska hidroelektrani Ljubanska reka Serava/Vardar ROR n/a 0,23 1x0,234 2013 0,9 32,5 DOOEL Skopje Hidro Energy Pesocan 393 Group DOO Pesocanska reka reka/Ohrid lake ROR n/a 0,99 1x0,990 2013 3,1 31,01 Skopje Mali hidro Selecka reka, s. elektrani DOO Selecka reka reka/Radika/Crn Drim ROR n/a 1,72 1x1,720 2013 4,6 23,27 Burinec Skopje Hidro eko Zelengradska Zelengrad inzinering DOO reka/Bregalnica/Vardar ROR n/a 0,13 1x0,130 2013 0,6 31,33 reka Skopje EMK Mali Brestjanska reka hidroelektrani Brestjanska reka Lake/Pcinja/Vardar ROR n/a 0,67 1x0,666 2013 2,3 30,33 DOOEL Skopje DDS Solar DOO Ratevo Ratevska reka Bregalnica/Vardar ROR n/a 0,4 1x0,400 2013 1,5 27,4 Skopje Mini Turija Ezoterna DOOEL Turija dam dam/Strumica ROR n/a 0,16 1x0,160 2013 1,1 59,89 PCC HIDRO Gradecka Gradecka reka Bregalnica/Vardar ROR n/a 0,92 1x0,920 2013 3,5 29,65 DOOEL Skopje Hidro Energy Tresonce Group DOO Tresonecka reka Radika/Crn Drim ROR n/a 1,98 1x1,98 2013 4,5 17,51 Skopje Hidro Energy Pesocan 392 Group DOO Pesocanska reka reka/Ohrid lake/Crn ROR n/a 1,13 1x1,125 2013 3 24,38 Skopje EMK Mali Golemaca 259 hidroelektrani Golemaca Crna Reka/Vardar ROR n/a 0,42 1x0,423 2013 1,8 28,85 DOOEL Skopje EMK Mali Mala reka hidroelektrani Mala reka Crna Reka/Vardar ROR n/a 0,27 1x0,270 2013 0,9 21,94 DOOEL Skopje

69

Hidro sistem Dobrenoec Studencica Kicevo Treska/Vardar ROR n/a 0,48 1x0,480 2014 3,6 67,35 Studencica SOL Bistrica 97 HIDROPAUER Bistrica, Tearce Vardar ROR n/a 2,64 1x2,64 2014 5,8 19,44 DOOEL Skopje SOL Bistrica 98 HIDROPAUER Bistrica, Tearce Vardar ROR n/a 3,2 1x3,2 2014 6,5 19,41 DOOEL Skopje PCC HIDRO Brajcinska(Stara) Brajcino 2 Lake/Crn Drim ROR n/a 1,47 1x1,4725 2014 3,9 18,52 DOOEL Skopje reka PCC HIDRO Galicka reka 3 Galicka reka Radika/Crn Drim ROR n/a 1,28 1x1,2825 2014 2,1 10,72 DOOEL Skopje EL TE HIDRO Esterec 372 Esterec reka/Bregalnica/Vardar ROR n/a 0,38 1x0,376 2014 1,3 20,07 DOOEL Skopje SOL Bistrica 99 HIDROPAUER Bistrica, Tearce Vardar ROR n/a 3,28 1x3,28 2014 6,7 23,49 DOOEL Skopje Eksploatacionen Hydro System PC Strezevo System Strezevo ROR n/a 0,32 1x0,320 2014 1,5 54,59 minimum Strezevo BNB ENERGI Brza voda 3 95 Brza Voda System Strezevo/Cr ROR n/a 0,72 1x0,720 2015 1,2 19,2 DOO Skopje Ezoterna DOOEL Toplec Hydro sysstem Dojransko Ezero ROR n/a 0,33 1x0,332 2015 0,3 11,46 Strumica BNB ENERGI Brza voda 2 94 Brza Voda Vardar ROR n/a 0,96 1x0,960 2015 1 12,48 DOO Skopje BNB ENERGI Brza voda 1 96 Brza Voda Vardar ROR n/a 0,96 1x0,960 2015 0,5 6,4 DOO Skopje PCC HIDRO Patiska reka 146 Patiska reka Vardar ROR n/a 0,71 1x0,7125 2015 1,6 25,21 DOOEL Skopje Golemo Ilino BNB ENERGI Goelmo Ilinska Crna reka/Vardar ROR n/a 0,46 1x0,464 2015 0,8 19,41 257 DOO Skopje reka

70

Baciska reka 2 Albnor Kompani Baciska reka Treska/Vardar ROR n/a 1,17 1x1,170 2015 1,6 16,01 28 Elektrolab DOO (Maloilinska Kusnica 256 Crna reka/Vardar ROR n/a 0,25 1x0,2475 2015 0,3 14,22 Skopje reka) SOL Kamena reka HIDROPAUER Kamena reka Lipkovsko Lake ROR n/a 2,4 1x2,4 2015 1,1 5,27 125 DOOEL Skopje EL TE HIDRO Konjarka 236 Konjarka Lake/Pcinja/Vardar ROR n/a 1 1x1 2015 1 11,46 DOOEL Skopje EMK Mali Kriva reka 1 179 hidroelektrani Pcinja/Vardar Pcinja/Vardar ROR n/a 0,54 1x0,540 2015 0,6 11,69 -1 DOOEL Skopje EMK Mali Kriva reka 2 179 hidroelektrani Pcinja/Vardar Pcinja/Vardar ROR n/a 0,99 1x0,990 2015 1,2 13,74 -2 DOOEL Skopje Hidro Osogovo Kalin Kamen 1 Pcinja/Vardar Pcinja/Vardar ROR n/a 0,25 1x0,248 2015 1,8 81,3 DOO Skopje Hidro Osogovo Kalin Kamen 2 Pcinja/Vardar Pcinja/Vardar ROR n/a 0,32 1x0,320 2015 1,7 60,45 DOO Skopje Hidro Bosava Bosava 1 Bosava Vardar ROR n/a 2,88 1x2,880 2015 1,1 4,32 DOO Kavadarci Hidro Bosava Bosava 2 Bosava Vardar ROR n/a 2,88 1x2,880 2015 1,2 4,56 DOO Kavadarci Hidro Bosava Bosava 3 Bosava Vardar ROR n/a 1,92 1x1,920 2015 0,6 3,63 DOO Kavadarci Hidro Bosava Bosava 4 Bosava Vardar ROR n/a 1,92 1x1,920 2015 0,3 1,67 DOO Kavadarci Hidro Bosava Bosava 5 Bosava Vardar ROR n/a 1,44 1x1,440 2015 0,1 0,76 DOO Kavadarci Hidro Osogovo Stanecka reka Pcinja/Vardar Pcinja/Vardar ROR n/a 0,14 1x0,136 2015 0,2 16,35 DOO Skopje

71

BNB ENERGI Kazani 208 Semnica Crna reka/Vardar ROR n/a 1,06 1x1,064 2015 0,3 3,68 DOO Skopje AK - INVEST Vejacka reka 93 Vejacka reka Vardar ROR n/a 1,31 1x1,3064 2015 n/a 0,14 ДООЕЛ Tetovo MHE Jablanica Jablanica 399 Jablanicka reka Crn Drim ROR n/a 3,28 1x3,28 2015 n/a 0,02 DOO Skopje Total 97,4 246,4 25,8 Table 10: Hydropower plants in North Macedonia Below 10 MW.

Capac AVG Started Country Plant Type ity Output Status Operation (MW) (GWh) Albania Fier HFO 186 n/a n/a Out of Operation Albania Vlora NGCC 97 n/a n/a Constructed in 2011/Not operating Albania Central PV 1 2014 2 In Operation Albania Elbasan Waste 2,85 2017 n/a In Operation Albania Fier Waste 3,8 n/a n/a In Operation N. Macedonia Bitola Coal 675 1982-1988 3200 In Operation N. Macedonia Oslomej Coal 125 1980 565 Out of Operation N. Macedonia Skopje CC Gas CHP 227 2011 455 In Operation N. Macedonia Negotino HFO 210 n/a n/a Out of Operation N. Macedonia Bogdanci Wind 36,8 2014 102 In Operation N. Macedonia Various PV 17 n/a n/a In Operation N. Macedonia Various Biogas 7 n/a n/a In Operation Table 11: Thermal and renewable installations excluding hydropower.

72

Voltage Line Length Type of Type of Conductor Rated Country Node 1 Country Node 2 Level (kV) (km) Circuit Conductor per Phase Current (kA)

Existing Interconnections Kriva FYROM Bulgaria Skakavica 110 18,1 Single 3xAI/Fe 240/40 1 0,647 Palanka FYROM Susica Bulgaria Petric 110 32,6 Single 3xAI/Fe 240/40 1 0,647 FYROM Dubrovo Bulgaria C. Mogila 400 150 Single 3xAI/Fe 490/65 2 1,92 FYROM Stip Bulgaria C. Mogila 400 150 Single 3xAI/Fe 490/65 2 1,92 FYROM Bitola 2 Greece Meliti 400 40 Single 3xAI/Fe 490/65 2 1,92 FYROM Dubrovo Greece Thessaloniki 400 115,3 Single 3xAI/Fe 490/65 2 1,92 FYROM Skopje 5 Kosovo Ferizaj 2 400 53,2 Single 3xAI/Fe 490/65 2 1,92 FYROM Stip Serbia Nis (Vranje) 400 70 Single 3xAI/Fe 490/65 2 1,92 Albania Fierze Kosovo Prizren 220 n/a n/a n/a n/a n/a Albania Tirana 2 Kosovo Pristina 400 n/a n/a n/a n/a n/a Albania Zemblak Greece Kardia 400 n/a n/a n/a n/a n/a Albania Bistrice Greece Mourtos 150 n/a n/a n/a n/a n/a Albania Koplik Montenegro Podgorice 220 n/a n/a n/a n/a n/a Albania Tirana 2 Montenegro Podgorice 400 n/a n/a n/a n/a n/a Planned Interconnections FYROM Bitola 2 Albania Elbasan 400 n/a Single 3xAI/Fe 490/65 2 1,92 FYROM Skopje 5 Kosovo Kosovo B 400 n/a Single 3xAI/Fe 490/65 2 1,92 Table 12: Existing and planned interconnections involving Albania and North Macedonia.

73

Plant Fierza Komani Vau I Dejes Ashta 1 Ashta 2 Ulza Shkopeti Banja Moglice Dam Height (m) 161,5 115,5 46,4/60/30 64,2 52,2 80 n/a

Dam Length (m) 380 290 440/390/320 260 88,3 n/a n/a Dam Base Width (m) 576 n/a n/a n/a n/a n/a n/a Dam Crest Width (m) 13 n/a n/a n/a n/a n/a n/a

Dam Volume (million m3) 8 5 3,5 ofRun River ofRun River 0,26 n/a n/a n/a

Nominal Head (m) 118 96 52 5 7,5 53,7 36,8 n/a n/a 1971- 1981- 1952- 1958- 2013- exp. in Construction Time 1965-1973 Operated in 2013 1980 1988 1958 1963 2016 2019

Max Water Level 296 176 76 23 18 131,7 77,2 n/a n/a Compared to Sea Level (m)

Reservoir Capacity (billion 2,7 0,5 0,68 n/a n/a n/a n/a 0,39 n/a m3) Average Water Discharge 202 289 306 560 530 n/a n/a n/a n/a (m3/s) Mean Annual Inflow 6,37 9,11 9,65 n/a n/a 1,2 1,2 n/a n/a (billion m3) Francis Francis Propoller Propoller Francis Kaplan Francis Turbine Type, Number and Francis 5*50 Francis 4*125 4*150 45*0,438 45*0,6338 4*6,25 2*12,5 3*24,3 Power MW 192 MW MW MW MW MW MW MW MW Table 13: Specifications for major hydropower plants in Albania.

74

Glob Sv. Plant Vrben Vrutok Raven Spilje Tikves Kozjak Matka Kalimanci ocica Petka Total Power (MW) 12,8 165,6 21 42 84 112 82,5 36 7,5/9,6 13,6 Turbine Type, Francis Francis Francis Francis Kaplan Number & Power 2*6,4 4*41,4 3*7 2*21 2*6,9 3*28 4*28 2*42 2*18 2*4,8 (MW) Reka Korab/ Korab/ Korab/ Black Radika/ Treska/ Treska/ Treska/ Bregalnica/ River Crna/ Vardar Vardar Vardar Drin B. Drin Vardar Vardar Vardar Vardar Vardar Dam Height (m) n/a n/a n/a n/a 101 113,5 116,1 64 n/a n/a Max Water Level Compared to Sea n/a n/a n/a n/a 580 n/a 459 n/a n/a n/a Level (m) Type ROR DAM n/a DAM DAM DAM DAM DAM DAM DAM Average Inflow 3,71 9,73 9,73 28,8 47,13 28,11 21,14 22,48 23,82 n/a (m3/s) Peak Inflow (m3/s) 8 32 32 54,9 108 120 100 70 40 n/a Nominal Head (m) 196 525 74 88 86 88 95 33 27 n/a Useful/Total 15/ 309/ Reservoir Capacity 0 277/376 0 212/506 260/550 1/9 1 127 55,3 479 (million m3) Average Annual Generation Output 39,5 317,8 38,3 166 245,5 133,9 152 53 35 25 (GWh) 1957/ 1970/ 1968/ Started Operation 1959 1959/1973 1965 2004 2012 2008 1970 1973 1998 1981 Table 14: Specifications for major hydropower plants in North Macedonia.

75

Losses in the Distribution Grid 50,0 46,4 45,0 45,0

40,0 37,6 37,8 35,4 34,0 35,0 32,7 31,3

30,4 Losses Losses (%) 30,0 27,6

25,0 23,1

20,0 2006 2008 2010 2012 2014 2016 2018

Figure 32:Losses in the distribution grid of Albania (ERE, 2016).

76

Appendix B: Electricity Demand, Hydrological and Economical Parameters

s Albania Electricity Demand Profile North Macedonia Electricity Demand Profile

45000 45000 40000 40000 35000 35000 30000 30000 25000 25000 20000 20000 15000 15000

10000 10000 ElectricityDemand (MWh) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 ElectricityDemand (MWh) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Jan. Feb. Mar. Apr. May Jun. Jan. Feb. Mar. Apr. May Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jul. Aug. Sep. Oct. Nov. Dec. Figure 33: Electricity demand profile in Albania and North Macedonia.

77

Average Monthly Flow and Precipitation in Vau Dejes Average Monthly Flow and Precipitation in Kukes

1800,0 400,0 R² = 0,7815 1600,0 350,0 R² = 0,7303 y = 3,2834x - 24,168 1400,0 y = 5,8758x + 15,5 300,0 1200,0 250,0 1000,0 200,0 800,0 150,0

600,0 River River Flow (m3/s) 400,0 River Flow (m3/s) 100,0 200,0 50,0 0,0 0,0 0 50 100 150 200 250 300 0 20 40 60 80 100 120 140 Precipitation (mm) Precipitation (mm)

Figure 34: Average monthly values for flow and precipitation in Vau Dejes and Kukes station.

78

Year Total Annual Invest Capital s of O&M Operatio Capacity Generation Project Lifeti ment Plant Country River Cost Cons (Euro/ n Costs (MW) Forecast Phase me (Euro/ (Euro/kW) truct MWh) (Euro/M (GWh) MWh) ion Wh) Costs for DAM Hydropower Plants Skavica 441 Albania Black Drin 193 768 Proposed 3432,1 n/a n/a n/a n/a n/a Katundi i Ri 445 Albania Black Drin 49 206 Proposed 2030,6 n/a n/a n/a n/a n/a Skavica 385 Albania Black Drin 119 467 Proposed 1800,8 n/a n/a n/a n/a n/a Skavica 395 Albania Black Drin 132 488 Proposed 1881,1 n/a n/a n/a n/a n/a Partly Banja & Moglice Albania Devoll 265 729 2018,9 n/a n/a n/a n/a n/a Completed Cebren N. Macedonia Crna Reka 61,3 183 Proposed 3083,2 n/a n/a n/a n/a n/a Cebren N. Macedonia Crna Reka 333 340 Proposed 958,0 7 50 67,1 2,3 69,4 Galiste N. Macedonia Crna Reka 193,5 264 Proposed 1033,6 7 50 71,3 2,3 73,6 Veles N. Macedonia Vardar 93 300 Proposed 2698,9 7 50 79,3 2,3 81,6 Costs for ROR Hydropower Plants Ashta 1&2 Albania Drin 56,4 345 Completed 3018,9 n/a n/a n/a n/a n/a Gjorice Albania n/a 3,2 21 Proposed 1846,9 n/a n/a n/a n/a n/a Borova Albania n/a 1,26 7 Proposed 1319,6 n/a n/a n/a n/a n/a Sebisht Albania n/a 2,5 12 Proposed 1546,4 n/a n/a n/a n/a n/a Okshtun Albania n/a 10,15 51 Proposed 1935,6 n/a n/a n/a n/a n/a Prodan 4 Albania n/a 0,32 2 Proposed 2238,1 n/a n/a n/a n/a n/a Prodan 5 Albania n/a 0,7 4 Proposed 1148,3 n/a n/a n/a n/a n/a Lubalesh Albania n/a 11,89 53 Proposed 2030,6 n/a n/a n/a n/a n/a Ternove Albania n/a 0,63 3 Proposed 1315,8 n/a n/a n/a n/a n/a Turija N. Macedonia Strumica 0,15 n/a Completed 1666,7 n/a n/a n/a n/a n/a 3 SHPP in Vardar N. Macedonia Vardar 6,75 53,3 Proposed 1333,3 n/a n/a n/a n/a n/a

79

Small HPPs N. Macedonia n/a 72,5 200 Proposed 1103,4 n/a n/a n/a n/a n/a Costs for Unknown Type Hydropower Plants Boskov Most N. Macedonia Radika 68,2 134 Proposed 1026,4 4 50 4,47 2,3 6,77 Luk. Pole+Kamen N. Macedonia Mavrovo 8 140 Proposed 5625 4 50 27,5 2,3 29,8 Gredec N. Macedonia Vardar 54,6 252 Proposed 2875,5 7 50 59,9 2,3 62,2 10 HPPs in Vardar N. Macedonia Vardar 176,8 784 Proposed 2748,9 n/a n/a n/a n/a n/a Generic Hydro Albania n/a n/a n/a n/a 2500 n/a n/a n/a n/a n/a Table 15: Costs for proposed HPPs (Verbund, 2008) (Xhafa, 2009) ( Causevski & Nikolova, 2010) (MoE, 2010) (Devoll Hydropower, 2014) (KESH, 2017) (ELEM, 2018) (Cingoski & Nikolov).

80

Gener Capita Years Annual Investm Capaci ation Fuel O&M Project l Cost of Lifeti Operati ent Plant Type Country ty Foreca (Euro/M (Euro/MW Phase (Euro/ Constr me on (Euro/ (MW) st Wh) h) kW) uction Hours MWh) (GWh) Generic NGCC Albania n/a n/a n/a 1000 n/a n/a n/a n/a n/a n/a NGCC Generic 1200- Lignite Albania n/a n/a n/a n/a n/a n/a n/a n/a n/a Lignite 2000 Generic Geothermal Albania n/a n/a n/a 4000 n/a n/a n/a n/a n/a n/a Geothermal Generic PV PV Albania n/a n/a n/a 1100 n/a n/a n/a n/a n/a n/a Generic Wind Albania n/a n/a n/a 1500 n/a n/a n/a n/a n/a n/a Wind Generic Biomass Albania n/a n/a n/a 3000 n/a n/a n/a n/a n/a n/a Biomass Generic TPP Lignite N. Macedonia 300 2100 n/a 1200 4 30 7000 16,3 15,9 7,7 Lignite Generic NGCC N. Macedonia 234 1750 n/a 650 2 20 7479 9,1 46,2 2,3 NGCC Generic Nuclear N. Macedonia 1000 7500 n/a 2000 7 60 7500 24,6 10,9 17,7 Nuclear Generic Oil Oil CC N. Macedonia 234 n/a n/a 650 2 20 7479 9,1 n/a 2,3 CC Bogdanci Wind N. Macedonia 13,8 50 Proposed 1522 n/a n/a n/a n/a 0 n/a Phase 2 Miravci Wind N. Macedonia 14 45 Proposed 1500 n/a n/a n/a n/a 0 n/a Oslomej PV N. Macedonia 10 14,6 Proposed 900 n/a n/a n/a n/a 0 n/a Table 16: Costs for various power plants (MoE, 2010) (Mezősi & Szabó, Decarbonisation modelling in the electricity sector Albania, 2015) (Mezősi, Szabó, & al., South East Europe Electricity Roadmap Country Report Albania, 2017) (ELEM, 2018).

81

Electricity Imports Electricity Exports Euro/MWh Albania N. Macedonia Albania N. Macedonia 2002 30,2 n/a n/a n/a 2003 30,2 n/a n/a n/a 2004 35,6 35,6 n/a n/a 2005 40,0 n/a n/a n/a 2006 47,8 45,5 n/a n/a 2007 69,0 70 n/a n/a 2008 79,0 79 n/a n/a 2009 48,7 63 n/a n/a 2010 45,5 46 n/a n/a 2011 60,5 n/a n/a n/a 2012 63,6 n/a 31,2 n/a 2013 51,5 n/a n/a n/a 2014 55,2 n/a n/a n/a 2015 n/a n/a n/a n/a 2016 n/a n/a n/a n/a 2017 69,1 36,40 n/a n/a 2018 n/a n/a 24,8 n/a Average 51,8 53,6 28,0 29,0 Table 17: Historical electricity import and export prices.

82

Appendix C: Results

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 NGCC 0 0 0 0 0 0 0 0 32 32 0 HYDRO 6133 9089 7664 5078 9964 7667 5078 9989 7664 5078 10008 WIND 0 0 0 0 0 0 0 0 0 0 0 PV 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 Imports 1595 749 1474 3822 1142 2139 4503 1550 2633 5277 2032 Exports 339 2174 1357 913 2912 1394 950 2684 1210 1061 2470 NET TRADE 1256 -1426 118 2909 -1769 745 3553 -1134 1423 4216 -438 Total 7390 7664 7782 7988 8195 8412 8631 8856 9120 9327 9571 Table 18: Electricity production and trade in Albania under the BAU scenario.

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 COAL 3049 3049 3049 3049 2315 2865 3049 2594 3049 3049 2824 NG CHP 750 750 750 750 750 750 750 750 750 750 750 OIL 0 27 0 0 0 0 0 0 0 0 0 HYDRO 1451 1850 1867 1111 1806 1823 1085 1806 1823 1085 1806 WIND 107 107 691 1166 1166 1166 1166 1166 1166 1166 1166 PV 18 18 18 18 18 18 18 18 18 0 0 Imports 1664 1335 864 1281 1416 1029 1714 1447 1186 2224 1571 Exports 0 0 0 36 29 102 127 20 121 294 24 NET TRADE 1664 1335 864 1245 1388 928 1587 1427 1064 1930 1547 Total 7039 7137 7239 7340 7444 7550 7656 7761 7871 7981 8094 Table 19: Electricity production and trade in North Macedonia under the BAU scenario.

83

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 NGCC 0 0 0 0 0 0 2 0 0 38 0 HYDRO 6133 8994 7581 5031 9756 7500 4986 9669 7422 4942 9564 WIND 0 0 0 0 0 0 0 0 0 0 0 PV 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 0,6 Imports 1595 781 1504 3875 1222 2244 4600 1713 2883 5419 2267 Exports 339 2119 1303 918 2781 1332 959 2528 1219 1076 2258 NET TRADE 1256 -1339 201 2957 -1558 912 3641 -814 1664 4343 9 Total 7390 7656 7782 7988 8198 8413 8630 8856 9087 9323 9573 Table 20: Electricity production and trade in Albania under the Climate Change scenario.

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 COAL 3049 3049 3049 3049 2413 2914 3049 2675 3049 3049 2886 NG CHP 750 750 750 750 750 750 750 750 750 750 750 OIL 0 27 0 0 0 0 0 0 0 0 0 HYDRO 1451 1824 1848 1102 1756 1786 1068 1733 1768 1059 1709 WIND 107 107 691 1166 1166 1166 1166 1166 1166 1166 1166 PV 18 18 18 18 18 18 18 18 18 0 0 Imports 1664 1362 883 1305 1384 1014 1744 1457 1263 2269 1608 Exports 0 0 0 50 45 101 142 37 145 314 25 NET TRADE 1664 1362 883 1255 1339 913 1602 1419 1119 1955 1583 Total 7039 7138 7238 7341 7443 7548 7654 7761 7871 7980 8094 Table 21: Electricity production and trade in North Macedonia under the Climate Change scenario.

84

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 NGCC 0 0 0 0 0 0 0 0 0 3 0 HYDRO 6136 9273 8256 5788 11501 9073 6030 11474 8978 5977 11410 WIND 0 0 60 137 171 206 240 247 257 257 257 PV 0,6 0,6 31,9 83,3 80,0 108,9 121,7 106,7 128,1 128,1 128,1 Imports 1594 686 1239 3125 467 1436 3172 606 1636 3731 967 Exports 339 2283 1803 1144 4022 2411 937 3575 1911 769 3192 NET TRADE 1255 -1597 -564 1981 -3556 -975 2235 -2969 -275 2961 -2225 Total 7391 7677 7784 7989 8196 8413 8626 8858 9088 9326 9570 Table 22: Electricity production and trade in Albania under the Increased Renewables scenario.

GWh 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 COAL 3049 3049 3049 3049 1675 1728 2924 1467 1652 3015 1737 NG CHP 750 750 750 750 750 750 750 750 750 750 750 OIL 0 24 0 0 0 0 0 0 0 0 0 HYDRO 1458 2014 2298 1437 2585 3094 2128 3717 3794 2272 3667 WIND 107 107 399 999 999 999 1166 1166 1166 1166 1166 PV 18 18 27 37 48 64 85 95 95 77 77 Imports 1658 1178 717 1144 1488 1178 881 1294 900 1036 1248 Exports 0 0 0 75 101 264 278 728 486 336 552 NET TRADE 1658 1178 717 1069 1386 914 603 567 414 700 696 Total 7040 7140 7240 7342 7443 7548 7655 7762 7872 7981 8094 Table 23: Electricity production and trade in North Macedonia under the Increased Renewables scenario.

85