tpp task 1 final report

November, 2007

European Agency for Reconstruction Contract nr 05KOS01/04/005

Studies to support the development of new generation capacities and related transmission – Kosovo UNMIK

CONSORTIUM OF PÖYRY, CESI, TERNA AND DECON Task 1 Report

Power Market Review

Studies to support the development of new November, 2007 generation capacities and related transmission (95) Task1, Power Market Review

European Agency for Reconstruction Pöyry-CESI-Terna-Decon

Disclaimer

While the consortium of Pöyry, CESI, TERNA and DECON considers that the information and opinions given in this work are sound, all parties must rely upon their own skill and judgement when making use of it. The consortium members do not make any representation or warranty, expressed or implied, as to the accuracy or completeness of the information contained in this report and assumes no responsibility for the accuracy or completeness of such information. The consortium members will not assume any liability to anyone for any loss or damage arising out of the provision of this report. The report contains projections that are based on assumptions that are subject to uncertainties and contingencies. Because of the subjective judgements and inherent uncertainties of projections, and because events frequently do not occur as expected, there can be no assurance that the projections contained herein will be realised and actual results may be different from projected results. Hence the projections supplied are not to be regarded as firm predictions of the future, but rather as illustrations of what might happen. Parties are advised to base their actions on an awareness of the range of such projections, and to note that the range necessarily broadens in the latter years of the projections.



Table of contents

1 TASK REPORT FOR TASK 1, POWER MARKET REVIEW ...................................7

1.1 Subtask 1.1.A: Market analysis............................................................................................8 1.1.1 A. Consideration of demand and supply data in existing reports (ESTAP I and GIS) .......8 1.1.1.1 Evaluation of ESTAP I study ...............................................................................................8 1.1.1.2 Analysis of the electricity consumption in the years 2000 –2006........................................9 1.1.1.3 Analysis of future availability of Kosovo A and Kosovo B ..............................................11 1.1.1.4 Analysis of the electricity demand data .............................................................................14 1.1.1.5 Direct customers.................................................................................................................17 1.1.1.6 Reference Year 2005 and load curves................................................................................18 1.1.1.7 Reference Year 2005 and load shedding............................................................................20 1.1.1.8 Year 2007 Forecast.............................................................................................................21 1.1.1.9 Comparison between energy consumption data 2000-2005 and ESTAP forecast.............22 1.1.1.10 Technical and no-technical electricity losses .................................................................22 1.1.1.11 Household.......................................................................................................................23 1.1.2 Subtask 1.1.B: Review and update of ESTAP I and analysis in the context of SEE regional market...................................................................................................................................25 1.1.2.1 Premises to ESTAP Scenarios update................................................................................25 1.1.2.2 Electricity demand forecast: MGS scenario.......................................................................26 1.1.2.3 Electricity demand forecast: HGS scenario .......................................................................37 1.1.2.4 Load curves and peak power estimation ............................................................................43 1.1.2.5 Comparison with other forecasts........................................................................................49 1.2 Subtask 1.1.C. Pricing of electricity (actual level in SEE countries and long-term forecast level) 52 1.2.1 Electricity market background of the countries analysed ..................................................52 1.2.1.1 Albania ...............................................................................................................................52 1.2.1.2 Bosnia -Herzegovina ..........................................................................................................53 1.2.1.3 Bulgaria ..............................................................................................................................54 1.2.1.4 Croatia ................................................................................................................................55 1.2.1.5 Kosovo ...............................................................................................................................56 1.2.1.6 Romania .............................................................................................................................57 1.2.1.7 Macedonia ..........................................................................................................................58 1.2.1.8 Serbia..................................................................................................................................59 1.2.1.9 Montenegro ........................................................................................................................60 1.2.2 Input assumptions to EurECA electricity price model.......................................................61 1.2.2.1 Updated GIS report ............................................................................................................61 1.2.2.2 Main price scenarios...........................................................................................................64 1.2.2.3 Underlying demand scenarios ............................................................................................64 1.2.2.4 Resulting regional available capacity.................................................................................65 1.2.2.5 Assumptions on net transfer capacities ..............................................................................68 1.2.2.6 Underlying fuel price scenarios..........................................................................................72 1.2.2.7 Resulting regional electricity prices ...................................................................................75 1.3 Subtask 1.2 Potential Take-off opportunities.....................................................................77 1.3.1 General assumptions on generation from new capacities (Kosovo C)...............................77



1.3.2 General classification of customer base .............................................................................77 1.3.2.1 Potential types of long-term contracts for Kosovo C.........................................................78 1.3.3 Assessment of market opportunities ..................................................................................80 1.3.3.1 Assessment of market opportunities in Kosovo.................................................................80 1.3.3.2 Assessment of market opportunities in neighbouring countries ........................................81 1.3.3.3 Export countries requiring more than one cross-border transmission point ......................84 1.3.3.4 Export opportunities to countries outside of SEE ..............................................................86 1.3.3.5 Electricity exchanges..........................................................................................................86 1.3.3.6 Summary of sales opportunities .........................................................................................88 1.3.4 A. Assessment of market expansion opportunities if new and existing industrial plants eligible to participate in domestic and regional markets....................................................................89 1.3.5 List of potential off-takers of regional utilities and industries ...........................................92 1.3.6 Summary of market study ..................................................................................................93

REFERENCES.................................................................................................................................94

List of Tables Table 1-1 Characteristics data of generation plants in Kosovo..........................................................10 Table 1-2 Domestic Electricity Production - Years 2000 –2006 .......................................................10 Table 1-3 - Energy Balance - Year 2000 - 2006 ................................................................................10 Table 1-4 Electricity consumption and total losses data ....................................................................14 Table 1-5 Monthly Load factors 2000-2005 ......................................................................................16 Table 1-6 - Billed electrical energy...................................................................................................16 Table 1-7 - Technical losses...............................................................................................................17 Table 1-8 - Electrical energy consumption - Distribution..................................................................17 Table 1-9 - Total energy requested in distribution network...............................................................17 Table 1-10 - Direct consumers consumption data..............................................................................18 Table 1-11 - Electric energy available to the consumption and system peak power – year 2005 ....18 Table 1-12- Estimated amount of demand curtailemets by load shedding during period 2000-2006

....................................................................................................................................................20 Table 1-13 – Year 2007 Forecast .......................................................................................................21 Table 1-14 - Household electrical energy consumption....................................................................24 Table 1-15 Demographic trend and number of dwellings, (forecast of 2000). ..................................27 Table 1-16: electricity demand forecast concerning the household space heating ............................28 Table 1-17 : electricity demand forecast concerning the household water heating ...........................28 Table 1-18: electricity demand forecast concerning the household heat for cooking........................28 Table 1-19: electricity demand forecast for not thermal uses ............................................................29 Table 1-20: electricity demand forecast extended to all the household uses, absolute values and

sharing percentage......................................................................................................................29 Table 1-21: electricity demand forecast extended to all the uses in the services sector, absolute

values and sharing percentage....................................................................................................30 Table 1-22 : Updated industry MGS electricity demand forecast......................................................31 Table 1-23: Energy losses ESTAP forecast, 2001-2005 real data, updated and 2020 extended

forecast. ......................................................................................................................................32 Table 1-24: Total electricitydemand forecast MGS...........................................................................33 Table 1-25 Total electricity demand forecast for MSG with commercial loss reduction ..................35 Table 1-26: Demographic trend and number of dwellings in HG Scenario.......................................37 Table 1-27: Household electricity demand forecast for space heating in HGS .................................37



Table 1-28 Household electricity demand forecast for water heating in HGS ..................................38 Table 1-29 Household electricity demand forecast for cooking in HGS ...........................................38 Table 1-30 Household electricity demand forecast for non heat uses in HGS ..................................38 Table 1-31 Household electricity demand forecast in HGS...............................................................39 Table 1-32: Industry electricity demand forecast, HGS scenario ......................................................39 Table 1-33 Electricity demand data for services sector, HGS scenario ............................................40 Table 1-34 Total electricitydemand forecast HGS.............................................................................41 Table 1-35 Total electricity demand forecast for HSG with commercial loss reduction...................42 Table 1-36 - Energy forecast from 2005 to 2020 ...............................................................................49 Table 1-37 - Peak forecast from 2005 to 2020...................................................................................50 Table 1-38 Recent electricity prices paid in power exchanges in SEE during 2006 ........................87 Table 1-39 Total estimated utility sales potential from Kosovo C. ...................................................88 Table 1-40 Industrial growth in SEE..................................................................................................89 Table 1-41 State of deregulation of industrial customers in SEE ......................................................90 Table 1-42 Summary of identified industrial clients..........................................................................92 Table 1-43 Observed industrial customer prices in SEE region (unofficial) .....................................93

List of Figures Figure 1-1 Past availability of Kosovo A...........................................................................................12 Figure 1-2 Kosovo B1, generated electricity and net electricity to power net...................................12 Figure 1-3 For Kosovo B2, generated electricity and net electricity to power net: ...........................13 Figure 1-4 Electricity consumption and total losses ..........................................................................15 Figure 1-5 – Monthly electrical load and monthly peak load ............................................................15 Figure 1-6 Electric energy available to the consumption and system peak power – year 2005 .......19 Figure 1-7- Selected Daily Load Curves 2006...................................................................................19 Figure 1-8- Annual Load Duration Curves 2000 - 2006....................................................................20 Figure 1-9 – Actual and Estimated (corrected) Annual LDCs 2005..................................................21 Figure 1-10 - Electricity forecast - ESTAP MSG Scenario ...............................................................23 Figure 1-11 Comparison of ESTAP forecast for household sector with actual data during 2000-2005

....................................................................................................................................................24 Figure 1-12: industry electricity demand forecast (2000-2020).........................................................31 Figure 1-13 : MGS Development of losses 2005 - 2020....................................................................33 Figure 1-14 : Total demand, technical losses and demand by sectors. .............................................34 Figure 1-15 : Demand forecast in MGS with commercial loss reduction in 2010.............................36 Figure 1-16: HGS scenario, total electricity demand, technical losses and subdivision by sector. ...41 Figure 1-17 : Demand forecast in HGS with commercial loss reduction in 2010. ...........................42 Figure 1-18 - Typical load shapes for KLM model ...........................................................................44 Figure 1-19 - Peak power estimation in MGS....................................................................................45 Figure 1-20 - Peak power estimation in MGS with commercial loss reduction in 2010 ...................46 Figure 1-21 -: Load curves and peak power estimation in HGS........................................................47 Figure 1-22 – Peak power estimation HGS with commercial loss reduction up to 2010 ..................48 Figure 1-23 –LDCs of MGS and HGS 2010, 2015 and 2020 ............................................................48 Figure 1-24 – Electricity demand forecast from 2005 to 2020 ..........................................................50 Figure 1-25 - Peak power forecast from 2005 to 2020 ......................................................................51 Figure 1-26 Optimal plant rehabilitation and construction timetables for scenario 5 in the updated

GIS report (17) ...........................................................................................................................63 Figure 1-27 Annual demand (TWh) in all three scenarios.................................................................64 Figure 1-28 Regional capacity and demand in GW (High scenario) .................................................65 Figure 1-29 Regional Capacity and demand in GW (Central scenario) ............................................66



Figure 1-30 Regional capacity and demand in GW (Low scenario)..................................................67 Figure 1-31 Capacity margin in our three scenarios. ........................................................................68 Figure 1-32-Net Transfer Capacities in MW, in Year 2007 ..............................................................69 Figure 1-33 -Net Transfer Capacities in MW, in Year 2018 .............................................................70 Figure 1-34 - Net Transfer Capacities in MW, in Year 2030 ............................................................71 Figure 1-35 Regional average fuel prices in Low scenario................................................................72 Figure 1-36 - Regional Average Fuel Prices in Central Scenario ......................................................73 Figure 1-37- Regional Average Fuel Prices in High Scenario...........................................................73 Figure 1-38 - Regional Average Wholesale Electricity Prices ..........................................................75 Figure 1-39 Transitional structure of Albanian electricity market.....................................................81 Figure 1-40 Current structure of the Croatian electricity market.......................................................85



1 TASK REPORT FOR TASK 1, POWER MARKET REVIEW The Terms of reference for the project

Studies to support the development of new generation capacities and related transmission – Kosovo UNMIK called for the consultant to significantly increase the level of understanding for the potential electricity market facing any expansion of lignite-fired generation capacity planned for Kosovo. The information to be generated should enhance the knowledge and understanding of the regional electricity market and generate a knowledge base for the Kosovan authorities, the foreseen project lenders and potential investors on which they would be better placed to make decisions regarding future power sector development.

For Task 1, the consortium members have acted jointly, and sections of Task 1 have been completed by various consortium members. Having carried out the study ESTAP 1, CESI has been in charge of the its review and update. Pöyry Energy has collected and analysed the past performance and availability of Kosovo A and B, and also for the modelling of the South-Eastern European electricity market. The market study was carried out by TERNA.

This report on Task 1 does not include the description of the respective consultant’s methodology and modelling tools. In this respect, we wish to refer materials presented in our tender. However, the consortium members are willing to make their methodology descriptions available to any party or stakeholder making such a request.

In some areas of this report, we have chosen to illustrate certain issues with aspects of possible future physical or commercial structures for the future Kosovo C project. These illustrations are not intended to be recommendations for such structures; they are instead intended to facilitate the understanding of our analysis by the LPTAP Project Steering Committee and its advisors. The consortium has also refrained from evaluation power export potential to Greece and Italy, in order not to prejudice the position of any prospective investor candidate in the concurrent investor selection process by the Kosovan government.

In this report on Task 1, the report structure follows the description of Task 1 in the ToR. The internal sectioning and numbering of the report has been limited to number 1, to better reflect the sectioning of Task 1 in the ToR.



1.1 Subtask 1.1.A: Market analysis

1.1.1 A. Consideration of demand and supply data in existing reports (ESTAP I and GIS)

1.1.1.1 Evaluation of ESTAP I study The module A of the Energy Sector Technical Assistance Project (ESTAP), Pristina 2002, analysed the electricity consumption in Kosovo and prepared a demand forecast for Kosovo considering a study fifteen year period 2000-2015. This study was based on data and information on demand for electricity up to 2000 which was taken as the reference year.

Three scenarios for economic development were considered:

• HGS: High Growth Scenario with an average GDP growth of about 10 % per year;

• MGS: Medium Growth Scenario with an average GDP growth of about 6% per year;

• LGS: Low Growth Scenario with an average GDP growth of about 4% per year. For the time being, five years of experience show the soundness of demand forecast performed in ESTAP Module A, first of all for its methodology and moreover for its structure in considering the particularities of Kosovo electricity consumption.

The approach used in analysing electric energy demand and in predicting its further evolution consists in analysing the main end-uses separately. For the residential users in Kosovo, electricity consumption is primarily related to space heating, cooking, and hot water. Keeping the consumption of these end-uses separate will make it possible to study the impact on the total load of gradual introduction of other fuels to replace electricity, e. g. natural gas, district heating or LPG.

This tailor-made load model was applied to an extremely large range of possibilities, and it was a correct choice, taking into account the events from which the Kosovan society was coming out, and the choice to consider more than three basic scenarios (High, Medium and Low growth) investigating a range of additional scenarios. The assumptions on economic and demographic development of Kosovo are an important point for predicting electric energy consumption. The reference scenarios were agreed upon as concerns the GDP (Gross Domestic Product) forecast as well as the population growth forecast for the period 2001-2015. Another aspect was that in 2000 was not easy to predict the energy demand growth so it was decided to consider three growth rates for the GDP (and GNI) and indirectly correlate with them the growth of electricity demand, based to the experiences of similar countries leaving a post-war situation. Assumptions have been made about demography, growth of new dwellings, standard of life (and of consumption) etc.

The forecasting process has been studied with reference to two main aspects: the energy forecast and the forecast for its load distribution through time i.e. load curves and, especially, the peak load forecast.



Separated analyses were carried out with or without natural gas penetration, as well as the varying success in adoption of measures against the illegal consumption of electricity. The latter aspect was taken into consideration based on three time-domain approaches, three variants: a) fast countermeasures ( 2003-2005), b) partly postponed (2003-2010), and c) no implementation of any measures. Today we can affirm that the most probable pace of handling this problem is a progressive reduction of illegal consumptions of electricity (reaching its regime in 2020), starting with civil sectors such as residential sector and service sector, because seems that the industrial sector level of the unauthorised consumptions is low .

Nowadays, maintaining the central structure of ESTAP forecast methodology, it is possible to verify its soundness and accuracy by comparison of its findings with actual data concerning the past period 2001-2005 together with recent data of 2006, and an available forecast for 2007 provided by KEK.

In particular, the analysis of this first period after the war allows us to understand what is the pace taken by the Kosovo electricity sector growth, identifying and focusing to the scenarios that are demonstrated as more realistic and making forecasts by modifying the assumptions, conditions of original starting base cases, and by establishing of a new starting point for the electricity consumption growth rates of various sectors, etc.

After this first phase of comparison of ESTAP forecast results with reality of electricity consumption in Kosovo, it was possible to update ESTAP forecast and to prepare a new electricity forecast up to 2020, which is the scope of the present study.

1.1.1.2 Analysis of the electricity consumption in the years 2000 –2006

1.1.1.2.1 Analysis of electricity production data The electric system of Kosovo is primarily supplied by two thermal power plants using lignite obtained from nearby mines: Kosovo A with an installed capacity of 800 MW and Kosovo B with 678 MW. Besides these plants, there are small hydraulic power plants with a total installed capacity of 37.2 MW. So the total installed capacity is 1515.2 MW, as reported in Table 1-1.

During the period 1990 – 1999, the power plants have been exploited without any maintenance and overhauls, so the effective production capacity, reported in Table 1-2, is much lower. Electricity production is referring to the period 2000- 2006, but at present the statistics and load data regarding year 2006 are not complete.



Table 1-1 Characteristics data of generation plants in Kosovo

Kosova A Kosova B

A1 A2 A3 A4 A5 Total A B1 B2 Total B Hydro Total

Installation Year 1962 1966 1969 1971 1975 1983 1984 1981Design Capacity [MW] 65 125 200 200 210 800 339 339 678 37 1,515Present Net Capacity [MW] 25 0 120 135 0 280 277 277 554 34 834

Table 1-2 Domestic Electricity Production - Years 2000 –2006

Domestic Electricity production (GWh) Year Kosova A Kosova B Hydro Total

2000 582.0 1,281.0 51.0 1,914.02001 1,024.9 1,451.9 90.7 2,567.62002 1,134.2 1,938.5 80.3 3,153.02003 1,581.6 1,629.0 51.3 3,262.02004 863.7 2,524.3 111.8 3,499.82005 644.9 3,244.3 110.5 3,999.72006 899.0 2,972.4 100.5 3,972.0

During the period 2000-2006, the production of electric energy has increased from 1,914 GWh to almost 4,000 GWh in 2005, while the total energy available for consumption taking into account the Import/Export balance, (see Table 1-3), was 4,259 GWh in 2005, with an increase of 1,390 GWh compared to 2000.

Export and import energy values reported in Table 1-3 show a consistent increase from to the year 2005; the import of energy has reached 3,610 GWh in 2005 and export energy 3,351 GWh. In 2000 these amounts were respectively 1,723 GWh and 767 GWh.

The negative net balance between import and export energy has been of 259,6 GWh (6.1% of the energy available in Kosovo) in the year 2005. In 2000 these values were 955 GWh (33.3 % of the energy available in that year). The data of 2006 are very close to those of 2005.

After the war in Kosovo the shortages of production has required the importation of large amounts of electricity (2000-2002). The TPP Kosovo B has been refurbished during the period 1999 – 2004, increasing the production. For example during 2003 around 95% of electricity was produced from domestic electricity sources and 5% from imports. In 2004 around 88.9% of electricity was produced from domestic electricity sources and 11.10% from imports..

Table 1-3 - Energy Balance - Year 2000 - 2006

Year Energy Production Import Export Net Imp/exp Energy Available Direct customer Net distribution Losses

GWh % GWh GWh GWh % GWh GWh % GWh % GWh % 2000 1,913.6 66.7 1,723.3 -767.8 955.5 33.3 2,869.1 81.4 2.8 1,431.5 49.9 1,356.2 47.22001 2,567.6 82.5 2,944.2 -2400.2 543.9 17.5 3,111.6 84.3 2.7 1,555.2 50.0 1,472.1 47.32002 3,153.0 95.0 3,409.9 -3,243,3 167.6 5.0 3,320.6 124.1 3.7 1,828.7 55.1 1,367.8 41.22003 3,262.0 90.1 3,070.9 -2712.4 358.4 9.9 3,625.4 192.6 5.3 1,882.7 52.0 1,545.1 42.72004 3,499.9 88.7 3,268.5 -2823.1 445.4 11.3 3,945.9 93 2.3 2,039.2 51.7 1,813.7 46.02005 3,999.8 93.9 3,610.8 -3351.2 259.6 6.1 4,259.4 101.5 2.4 2,010.4 47.2 2,147.4 50.42006 3,972.0 93.0 2,726.3 -2427.6 298.6 7.0 4,270.6 106.9 2.5 1,974.2 46.3 2,189.5 51.2

*in year 2000 this value is referred only to Directorium (KEK consumes)



The non-technical losses are reported in Table 1-4. The term of non-technical losses, often called commercial losses, stands for the electricity consumed but not billed for different reasons such as unauthorised consumption, illegal connections, bypass of the meters, non-billed energy for procedural errors, violation of the meters, etc. The estimated value of non-technical losses amounted in the year 2005 up to 2,147 GWh (50.4%). It means that only 2,111.9 GWh have been billed. This amount is less than half of total supplied energy. In 2000 these values were 1,351.5 GWh, (47.1% ) and 1,517.6 GWh, respectively.

1.1.1.3 Analysis of future availability of Kosovo A and Kosovo B

The report on the technical feasibility of rehabilitating of Kosovo A (16) from 2005 states clearly that rehabilitation of Kosovo A units 3, 4 and 5 is feasible, and even economical. The version of the report available to the consortium does not, however, take a stand and or try to estimate the environmental benefits achievable by such rehabilitation.

Unit Kosovo A1 expected to undergo an overhaul in the near future, and it is expected to be operational until the first unit of Kosovo C. There are no fixed plans to overhaul or rehabilitate unit A2, and it is expected to remain out of operation.

The objective of the privatisation tender is that the first unit of Kosovo C would be commissioned in 2012. Large equipment manufacturers have indicated to consortium members that due to the extremely high world demand for major power plant components, deliveries before 2014 would require that the buyer of such equipment has pre-booked earlier manufacturing slots. If the investor to be chosen has booked equipment manufacturing time slots earlier, it may be possible to commission Kosovo C than 2012. It is expected that all units of Kosovo C would be in operation in 2018.

The crucial question of rehabilitation of Kosovo A is the financing of such rehabilitation. Most recent discussions with KEK indicate that there is willingness to tackle the task of repairing Kosovo A units 3, 4 and 5.

According to operation executives of KEK, the units to be rehabilitated in Kosovo A would probably operate continuously, with the exception of rehabilitation periods until the start of Kosovo C, which is now foreseen for 2012. Any operation of the rehabilitated units of Kosovo A thereafter will be dependent on environmental conditions set for Kosovo A and the availability of peak power from the SEE electricity market. As the rehabilitated units will be in compliance with EU environmental standards and requirements, operation of the rehabilitated unites 4 and 5 for some 12-13 years after rehabilitation is technically feasible, while operation of unit 3 for some 3-4 years is considered technically feasible (16).

The consortium of Pöyry/CESI/Terna/DECON will assume that the rehabilitation of Kosovo A units 3,4,5 will be carried out by in accordance by the following timetable indicated by the Ministry of Energy and Mining:

• Unit A3: rehabilitation between January 2008 and July 2009,

• Unit A4: rehabilitation from September 2009 to November 2010

• Unit A5: rehabilitation from March 2010 to July 2011



In addition, it is assumed that both units of Kosovo B plant would be shut down for rehabilitation for in early 2010’s, with Kosovo B unit 1 expected to undergo 18-month rehabilitation period around 2013 and Kosovo B unit 2 is expected to be rehabilitated in 2015 in a similar manner. In the long run, unit Kosovo B1 is expected to be operational until 2029 and unit B2 until 2030.

1.1.1.3.1 Past availability of Kosovo A and Kosovo B The following charts illustrate the past availabilities of Kosovo A and B, as reported by KEK :

average power for units

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Figure 1-1 Past availability of Kosovo A

0300000600000900000

1200000150000018000002100000

1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

PRODHIMI NË GJENERATOR MWh PRODHIMI NË PRAG MWh

Figure 1-2 Kosovo B1, generated electricity and net electricity to power net



0300000600000900000

1200000150000018000002100000

1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003

PRODHIMI NË GJENERATOR MWh PRODHIMI NË PRAG MWh

Figure 1-3 For Kosovo B2, generated electricity and net electricity to power net:

1.1.1.3.2 Assumptions made for continued operation of Kosovo A and B Only for the modelling purposes, the following assumptions will be used during the various market and transmission modelling:

Especially for Kosovo B:

1) Kosovo B units: the units of Kosovo B will continue to operate at average available capacity of 290 MWe each, with the exception of the above-mentioned planned rehabilitation periods

2) The total time availability of both units would be 79%. Outage is assumed 12% planned, 9% unplanned.

3) The average efficiency of the Kosovo B units would be 1.4 tons of lignite/MWh net generated, at € 0.92/GJ in fuel (€ 7.50/ton of lignite) from 2008 onwards.

Especially for Kosovo A:

4) It is assumed that Kosovo A unit 1 would continue operating when its power is needed in Kosovo until the commissioning of the first unit of Kosovo C

5) The available capacity of units Kosovo A unit 5 would be 135 MW before rehabilitation, and 155 MW after rehabilitation. Kosovo A unit 4 cannot be operated before rehabilitation, and its is assumed that its available capacity after rehabilitation would be 150 MW.

6) The time availability of Kosovo A units 4 and 5 would be 6600 hrs after rehabilitation.

7) The available capacity of Kosovo A unit 3 would be 90 MW before rehabilitation and 110 MW after rehabilitation.

8) The time availability of Kosovo A unit 3 would 5500 hrs after rehabilitation.

9) The average efficiency of Kosovo A units 3-5 would be 1.7 tons of lignite /MWh net generated, at € 0.92/GJ in fuel (€ 7.50 /ton of lignite) from 2008 onwards

10) The thermodynamic efficiency of Kosovo A unit 1 would remain at 24%, available capacity 24 MW, and expected time availability at 4700 hrs.



1.1.1.4 Analysis of the electricity demand data The evolution of electrical energy consumption in Kosovo is closely linked to political events and to the resulting economic changes. The curves in Figure 1-4 and Table 1-4 show that, from 1980 to 1988, electricity consumption increased at a very high rate of 9.1% per annum. This was the period of a high economical development in Kosovo, afterwards followed by a stagnation period until 1992, coinciding with the crisis and the political disintegration of former Yugoslavia. From 1993 to 1997, electricity consumption started to increase again, especially due to the growth of households and the services sector, while the industrial sector was declining. In 1998 and 1999 the political tensions followed by the conflict, caused a drop in electricity consumption, with a minimum consumption in 2000 when the demand for electricity was similar to those in 1998. After the year 2000, that was used as a reference in the precedent study, electric consumption restarted to increase, exceeding in the year 2002 the historical maximum and reaching in 2005, 4259 GWh.

Table 1-4 Electricity consumption and total losses data Year Gross Consumption Year Gross Consumption

[GWh] [GWh] 1980 1574,00 1994 2505,00 1981 1707,00 1995 2752,00 1982 1780,00 1996 3150,00 1983 1859,00 1997 3338,00 1984 2084,00 1998 2986,00 1985 2297,00 1999 2812,00 1986 2444,00 2000 2869,10 1987 2830,00 2001 3111,60 1988 3159,00 2002 3320,65 1989 3145,00 2003 3620,55 1990 2844,00 2004 3945,99 1991 2745,00 2005 4259,44

1992 2279,00 2006 4270,63 1993 2392,00

The Table 1-4 shows that total losses (meaning technical and commercial losses) increased sharply in 1989, and the increase culminated in 2001. Only in 2002 there has been a decline in losses, soon to be followed by a new increase; in the year 2005, for the first time energy losses are more than energy consumption (year 2006 provisional data are very close to those of year 2005).



History of the electrical energy consumption

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1980 1985 1990 1995 2000 2005

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Figure 1-4 Electricity consumption and total losses

Figure 1-5 shows the energy consumption during the period 2000-2005 distributed through different months of the year. From the graph can be noted the very highly seasonal nature of the electrical load in Kosovo and the evolution of the monthly load during this period. Nevertheless, as the load has increased from year to year, the shapes of the monthly electrical load characteristics have remained almost the same.

Figure 1-5 – Monthly electrical load and monthly peak load The diagrams in Figure 1-5 illustrate the electricity demand in each month of the year and the evolution of monthly peak during the period 2000-2005. The monthly peaks exhibit an increase in the last five year. These values do not take into consideration the programmed load curtailments generally applied in Kosovo during the peak hours of a day all over the year due to difficulties to cover the peak load and especially during winter time.

With the increase in energy production and consumption, there is an increase in the annual Load Factor (LF), from 0.50 pu in 2000 up to 0.54 pu in 2005, reaching a maximum of 0.55 pu in 2004. This fact can be explained by the shedding of load during the peak and the shift of energy consumption vs. the light load hours.



Table 1-5 Monthly Load factors 2000-2005

Month Monthly Load Factor 2001

Monthly Load Factor 2002





pu pu pu pu pu pu January 0.748 0.682 0.763 0.763 0.728 0.734February 0.695 0.676 0.734 0.734 0.711 0.697March 0.656 0.714 0.642 0.642 0.644 0.676April 0.584 0.665 0.642 0.642 0.630 0.693May 0.561 0.640 0.636 0.636 0.613 0.682June 0.602 0.663 0.610 0.610 0.558 0.612July 0.621 0.667 0.628 0.628 0.564 0.542August 0.570 0.633 0.707 0.707 0.589 0.661September 0.552 0.636 0.540 0.540 0.631 0.639October 0.551 0.586 0.636 0.636 0.619 0.704November 0.636 0.741 0.730 0.730 0.648 0.741December 0.621 0.748 0.740 0.740 0.694 0.707Yearly LF 0.466 0.545 0.555 0.555 0.532 0.532

Billed electrical energy consumption data are reported in Table 1-6 for the years 2001 - 2005 (2006 data are not completed) divided for each type of users (distribution users i.e. commercial and household consumers connected to LV and MV networks and direct consumers i.e. industry connected to the HV networks ).

Table 1-6 - Billed electrical energy

Distribution Electric system

Commercial Household Direct Customers

Year Available Energy Total losses Total billed Billed % Billed % Billed %

GWh GWh GWh GWh GWh GWh 2001 3,111.6 1,472.0 1,639.5 433.2 26% 1,122.0 68% 84.2 5% 2002 3,320.6 1,367.8 1,952.8 419.5 21% 1,409.1 72% 124.1 6% 2003 3,620.5 1,545.1 2,075.4 447.5 22% 1,435.2 69% 192.6 9% 2004 3,946.0 1,813.7 2,132.2 550.7 26% 1,488.4 70% 93.0 4% 2005 4,259.4 2,147.4 2,112.0 562.5 27% 1,447.8 69% 101.5 5% 2006 4,270.7 2,189.5 2,081.1 n.a n.a n.a n.a 106.9

The values of total technical losses for each year are assumed to be about 18% of total energy entering the network. This value is the result of the estimation done in ESTAP I study in Module C (Transmission Master Plan) and in Module D (Distribution Master Plan). The planned investments for the transmission and distribution network in Kosovo were and are at modest values so we consider that this value is still a good estimation and it is confirmed also by recent studies done by KoSTT experts. Technical losses are reported in Table 1-7 divided for each of the three main consumers (commercial, household and direct or HV industry) on the bases of their relative weight in the structure of the total billed energy.



Table 1-7 - Technical losses Distribution Year Electric

system Commercial HouseholdDirect

Customers GWh GWh GWh GWh

2001 560.1 148 383.3 28.82002 597.7 128.4 431.3 38.02003 651.6 140.5 450.6 60.52004 710.3 183.5 495.8 31.02005 766.7 204.2 525.6 36.92006 768.7 n.a n.a n.a

Electrical energy consumption data for distribution users (commercial and household consumers connected by the LV and MV networks) are reported in Table 1-8 while non-technical losses for this two type of consumers are reported in Table 1-9..

Table 1-8 - Electrical energy consumption - Distribution Distribution

Billed Total

Year Commercial Household

Total GWh % GWh % GWh GWh

2001 433.2 27.9 1122 72.1 1555.2 2904.9 2002 419.6 23 1409.1 77 1828.7 3088.3 2003 447.5 23.8 1435.2 76.2 1882.7 3165.5 2004 550.7 27 1488.4 73 2039.1 3665.5 2005 562.5 28 1447.8 72 2010.4 3881.6

Table 1-9 - Total energy requested in distribution network

Commercial Household

Year Non technical losses Billed Total Non technical

losses Billed Total

GWh GWh GWh GWh GWh GWh 2001 254.0 433.2 687.3 657.9 1,122.0 1,779.92002 176.7 419.5 596.2 593.4 1,409.1 2,002.52003 212.4 447.5 659.9 681.0 1,435.2 2,116.32004 298.0 550.8 848.8 805.4 1,488.4 2,293.82005 386.4 562.6 948.9 994.3 1,447.8 2,442.2

1.1.1.5 Direct customers The large industries with high electric energy consumption were significantly damaged during the conflict. The electricity consumption from high voltage industrial users dropped from 468 GWh in 1997 to 76.3 GWh in 2000, corresponding to a drop of 84 %. It is worth saying that during the period 1984-1991, direct consumption was much higher, with a maximum of 1053 GWh recorded in 1988.

The last data on electricity consumption for direct consumers (industry connected by the HV networks), reported in Table 1-10, shows that the situation has not significantly changed from year 2000 and the industrial activity is still usually at a low level, with a corresponding impact on energy consumption



Apart of the case of the Sharr cement factory in Kacanik, which has restored a consistent part of its pre-war electricity consumption, the Ferronickel, situated in Gllogovc, was badly damaged during the conflict and is still at standstill, and having in mind that its peak was 90 MW in full operation.. This also applies to Trepca industries.

Table 1-10 - Direct consumers consumption data

Year Trepça Feronikel Sharri WGD SHA Kos.Coal

KEK consumption Total

GWh GWh GWh GWh GWh GWh GWh 2001 48.8 2.1 0.0 33.3 84.22002 36.3 3.6 22.2 62.0 124.12003 34.9 1.7 46.3 109.7 192.62004 22.3 1.0 45.5 24.2 93.02005 22.8 1.0 54.3 3.3 1.5 18.2 101.52006 29.3 2.8 49.0 n.a n.a 25.8 106.9

1.1.1.6 Reference Year 2005 and load curves The year 2005 will be considered as a reference year for the updated forecast of electricity demand in Kosovo, and in Table 1-11 are reported the electricity balance figures corresponding to 2005. The Figure 1-6 illustrate the diagram of electricity demand, the structure of electricity supply, such as thermal, hydro and import/export and the shape of peak demand during 2005. It can be noted that the monthly peak power trend is quite similar to that of demand, reaching the maximum value of about 898 MW in February. This trend indicates a high dependence of electrical load from the weather condition and the use of great amount of electricity for heating purposes.

As described above, the annual load Factor (LF) is 0.54, but the monthly LF varies from 0.63 in June to 0.76 in January (use of electricity during the night for heating) with a ratio between the monthly energy of January and June of about 1.8.

Table 1-11 - Electric energy available to the consumption and system peak power – year 2005

Generation Net import Supplied Energy Monthly Peak Load 2005 Month

GWh GWh GWh MW January 429.0 53.0 482.0 850February 389.0 55.2 444.2 898March 381.4 47.8 429.2 849April 329.1 11.0 340.1 678May 256.6 31.5 288.1 615June 282.5 -19.1 263.3 580July 289.4 -30.3 259.1 532August 241.7 14.3 256.0 539September 241.7 28.3 270.0 568October 317.8 26.8 344.6 700November 392.3 18.1 410.4 789December 449.2 23.0 472.2 860

Yearly Peak 3,999.8 259.7 4,259.4 898



Figure 1-6 Electric energy available to the consumption and system peak power – year 2005

Selected daily load curves for the year 2006 (Source: KosTT Headquarters) shown in Figure 1-7 show a small modulation during winter time , with a high load during night hours, which confirms that many residential customers, as in the past, use electric accumulating stoves which store the heat during the night and release it during the day. In summer curves are similar with lower values of loads.

Figure 1-7- Selected Daily Load Curves 2006



The load duration curves (LDC) for period 2000 - 2006, (Source: KosTT Headquarters) illustrated in Figure 1-8 show an increase of load demand from 2000 to 2006; for example from the analysis of the curves can be found that the electricity demand exceeded 600 MW for only 0.34% of the time (30 hours) in the year 2000 while in 2006 this value of was exceeded for 3650 hours (41.6% of the time).

The load level corresponding to 4382 h (50% of the hours/year) has increased from 325 MW in the year 2000 to 548 MW in the year 2006.

Figure 1-8- Annual Load Duration Curves 2000 - 2006

1.1.1.7 Reference Year 2005 and load shedding During previous period 2000-2006 planned load shedding was implemented to adjust consumption to available power. The load shedding program is prepared every day by the Kosovo TSO (KoSTT), and is based on generation unit availability, on the possibility of imports and on forecast demand. This plan is organized so that it distributes reductions among all HV/MV substations as uniformly as possible.

The KoSTT has provided us with their estimation of the hourly shed load for the period 2000 - 2006, reported in Table 1-12. The shed load corresponds to a considerable amount of electricity demand every year and this estimation for the period 2001-2006 is given in the graph shown in Figure 1-9.

Table 1-12- Estimated amount of demand curtailemets by load shedding during period 2000-2006

2000 2001 2002 2003 2004 2005 2006

Estimated Load Shed (MWh) 377,873 362,061 460,787 426,168 254,937 268,129 480,666

Source KoSTT



For the year 2005 we have estimated the actual electricity demand and the corrected demand obtained by adding back the estimated amount of the load shed. The result of this addition is illustrated in Figure 1-9 where the graph shows that load has been shed in Kosovo over more than 90% of hours during 2005.

Figure 1-9 – Actual and Estimated (corrected) Annual LDCs 2005

1.1.1.8 Year 2007 Forecast KEK Electricity 2007 forecast data, reported in Table 1-13, shows an increase in available energy (4,833 GWh) respect to the year 2006 (4,270 GWh), with an expected electricity demand of 5,118 GWh.

Table 1-13 – Year 2007 Forecast

Energy production

Kosova A Kosova B Hydro Sh.A Kosova Total

Net import/export Available energy

GWh GWh GWh GWh GWh GWh GWh 937.4 3,068.20 129.3 25 4,159.90 673.2 4,833.10

Transmission balance Qualified

Customers* Ferronickel Mines Other out of KEK Distribution Net

Consumption Transmission

losses Expected demand

GWh GWh GWh GWh GWh GWh GWh GWh 131.6 359.2 140.5 17.7 4,316.60 4,965.60 152.7 5,118.40

Distribution balance

Available Supply Losses Household Net Distribution

Total Losses in Network (without

Transmission) 110 kV 35 kV 10 kV 0.4 kV

GWh GWh GWh GWh GWh GWh GWh GWh 4,357.90 0 46.6 176.7 373 1,824.00 2,420.20 1,927.70



1.1.1.9 Comparison between energy consumption data 2000-2005 and ESTAP forecast

1.1.1.9.1 Scenarios of electricity forecast As indicated in the summary, three scenarios for economic development were considered in the original ESTAP study:

• HGS: High Growth Scenario with an average GDP growth of about 10 % per year;

• MGS: Medium Growth Scenario with an average GDP growth of about 6% per year;

• LGS: Low Growth Scenario with an average GDP growth of about 4% per year.

A forecast was also prepared considering the introduction of natural gas for the High Growth (HGS) and Medium Growth (MGS) scenarios, based on the assumption that natural gas would gradually replace part of the electricity consumption for heating purposes in Kosovo starting from 2005

At present we can state that the introduction of natural gas, initially planned in 2005 for residential and commercial sectors, was not implemented, so we will consider only the three main scenarios of ESTAP forecasts concerning period 2000 – 2005. Results of comparison between actual data and MGS forecast (without gas) are reported in Figure 1-10 As reported in [5 - a] the MGS forecast was made according to three hypotheses:

Option A: That the actions for reducing non-technical losses and for eliminating non- payment of electricity were not carried out or did not succeed;

Option B: That the actions in the previous Option a) were carried out proved to be successful within 2005;

Option C: That the actions in the previous Option a) were carried out proved to be successful within 2010.

1.1.1.10 Technical and no-technical electricity losses As reported in Figure 1-10, the data collected in the years 2000 - 2005 show an excellent matching with the forecast described in Option A, confirming the assumptions that actions for reducing non-technical losses and for eliminating non-payment of electricity were not carried out or did not succeed in the last five years. The curve of total losses shows a new strong increase after a little inversion of tendency in the year 2002, and in the year 2005, for the first time in Kosovo, the total energy losses are more than energy billed for consumption.

Of course, the new loss forecast needs some new assumptions, fully described in the next chapter.



Figure 1-10 - Electricity forecast - ESTAP MSG Scenario

1.1.1.11 Household Regarding household electricity consumption for the scenario MGS without gas, ESTAP forecast included for the first 5 years three different assumptions:

Assumption 1: the implementation of measures restricting household consumption is not foreseen, but it is presumed that all new and rehabilitated households would not be equipped with meters. Another assumption is that, in time, the consumption of average households with and without meter would have grown. With this variant, energy consumption in 2005 would reach 2,434 GWh.

Assumption 2:assumes that until 2005, all dwellings will be meter-equipped. Under these assumptions, electricity consumption in households would rise until 2002 to 2,063 GWh, and then would sharply drop down to 1,800 GWh in 2005.

Assumption 2A: the installation of meters occurs with a slower rate, (being completed in 2010), so that the average consumption of the users in 2005 is 2134 GWh.

Results of comparison between household forecast with the different assumptions and actual data reported in Table 1-14 show a good agreement with ESTAP forecast Assumption 1.



Table 1-14 - Household electrical energy consumption

Household electrical energy consumption

Scenario 2000 2001 2002 2003 2004 2005 GWh GWh GWh GWh GWh GWh

Assumption 1 1,705 1,920 2,063 2,193 2,319 2,434 Assumption 2 1,705 1,920 2,063 1,931 1,853 1,800 Assumption 2A 1,705 1,920 2,063 2,109 2,151 2,134 Real data 1,705 1,779 2,002 2,116 2,293 2,442

Figure 1-11 Comparison of ESTAP forecast for household sector with actual data during 2000-2005

Comparison ESTAP Annual Household Forecast with real data Kosovo 2000 - 2005

0

500

1,000

1,500

2,000

2,500

3,000

2000 2001 2002 2003 2004 2005

Year

GW

h

Assumption 1 Assumption 2 Assumption 2A Real data



1.1.2 Subtask 1.1.B: Review and update of ESTAP I and analysis in the context of SEE regional market The following activities were carried out for review and update of the demand forecast for Kosovo power system:

• Data collection regarding the electricity supply and consumption in different sectors of economy such as households, industry and services, the development of electricity demand during 2001-2007 and identification of supply constraints,

• Review of economic and demographic assumptions and forecasts, • Assessment of impact of unpaid electricity on energy consumption and

demand forecast. • Preparation of the demand forecast considering the year 2005 as reference year

and extended up to 2020; and

• Demand aggregation and peak power forecast using the Kosovo Load Model (KLM) using typical load curves for each user category and demand allocation by regions.

1.1.2.1 Premises to ESTAP Scenarios update The availability of the data on electricity demand during the period 2000- 2005 and the comparison of such data with ESTAP forecasts (2001) allow some observations, before we establish the new updated scenarios and sub-scenarios as follows:

Regarding the electricity forecast, the statistics on electricity demand in 2000-2007 allow us to reach to the conclusion that the more direct and reliable information can be used as a basis for forecast rather than the extrapolation from GDP data. In 2000, starting after disruptive events, it was really difficult to prepare a forecast in electricity, without passing the estimation of macroeconomic parameters as GDP and GNI. Now, the situation is somewhat reverse: during the period 2000-2007 the electricity demand has shown a growth more regular than GDP, so one can be confident that the scenario MGS was well predicted and is still followed. Meanwhile the GDP had shown a strongly fluctuating trend (i.e. 25% growth in 2001 and negative growth in 2005). Thus, the MGS electricity demand will be taken as the reference scenario for forecasting of electricity demand.

Insignificant intervention has been made against illegal consumption of electricity, especially in the household sector. However, it seems probable than necessary and compulsory measures are required, but the pace of intervention will be not so fast as was assumed, and proposed in ESTAP: it is fair to assume than Kosovo will progressively reduce non-technical losses according to a new time-schedule for an “action plan”, with objective to reach original ESTAP target and complete elimination of illegal electricity consumptions in 2020.

The penetration of natural gas does not seem so immediate at the moment, and for example the “Kosovo Energy sector: Heat market study” gives a satisfactory explanation, “..in spite of all favourable effects associated with the utilization of natural gas as heating fuel” . To summarise:



• In a reasonable future there is no room for natural gas in the power generation sector of Kosovo,

• Without the need of gas for generation or massive transit to third markets, the capital cost of the necessary infrastructure is considerably high;

• Variable cost of gas even without further price increases will remain higher than that of alternative fuels.

On the other hand, natural gas penetration would have a smoothing effect on the electricity demand peaks on the network, so that ignoring gas penetration into account has a conservative effect. Moreover, the feasibility of a new power installation is not heavily affected by the gas penetration, as the electricity export is the really important opportunity to be exploited by this new power.

After the presentation of the Draft Report, the Ministry of Energy and Mines has requested the analyse of an addition scenario based on assumption that the elimination of commercial (non-technical) losses will occur during the period 2007-2010, reaching in 2011 a realistic level of about 5%. The Consultant has prepared and included in this report an additional electricity forecast on these basis.

In conclusion, two updated scenarios and an additional sub-scenarios are prepared, having as reference year 2005 and extended to 2020: a) a new updated Medium Growth Scenario (MGS); b) new updated High Growth Scenario (HGS), both considering a progressive transition from a situation characterised by a very high level of electricity losses to an optimal situation up to 2020, and without a natural gas penetration; c) and d) Sub-scenarios relevant to MGS and HGS both considering a progressive transition from a situation characterised by a very high level of electricity losses to an optimal situation up to 2010.

1.1.2.2 Electricity demand forecast: MGS scenario

1.1.2.2.1 Household sector In the A module of ESTAP, two separated analysis are carried out about the same scenario, called “MGS without gas”1:

a) Analysis of each type of energy demand in which electricity has a share, extended to the period 2000-2015. These types of uses are: • space heating, • water heating, • cooking, • non heat uses

The methodology is supported by the determination of specific consumption coefficients per dwelling or per person, while demographic and social analysis gives the trend on the number of dwellings, the number of persons per dwelling, and the variation in the period of the specific parameters.

1 MGS means “Medium Growth Scenario”. It was the scenario associated with a GDP annual growth in the period 2000-2015 of about 6%. The data of the first five years show a posterior that the real GDP growth is started following this intermediate trend rather than the LGS (Low Growth) or HGS (High Growth). Moreover, the MGS was developed also in the hypothesis of natural gas penetration, that would lower the electricity consumption for heating uses. For the time being, (2007) the penetration of natural gas seems to be still far to start.



b) Assumption (only up to 2005) of coefficients of total electricity consumption only for two classes of dwellings: those who are equipped with a metering system and those who are not, and with a strong difference between the consumption per dwelling (obviously the not metered one being higher).

Basically the growth of the number of dwellings is fixed, and from the very start all the new ones will be without metering. Three different hypotheses can be made:

• “No measures of reduction” of the illegal consumption phenomenon (assumption 1). In this case the household sector could reach in 2005 the electric consumption of 2434 GWh.

• Full implementation of the above mentioned measures of reduction no later than the 2005 (assumption 2). In this case the household sector could have in 2005 the electric consumption of 1800 GWh, equal to the value coming from the a) analysis.

• Full implementation reached in the 2010 (assumption 2A). In the 2005 the results of this action are partial, and the household sector could have the electric consumption of 2134 GWh.

As previously discussed, ESTAP uses the a) analysis to extend the forecast to the entire period 2000-2015, but the analysis a) is carried out with the hypothesis typical of the assumption 2, while the data known as or the time being, seems to repeat exactly the assumption 1: no measures are taken against illegal consumption of not billed electricity.

Consequently, it becomes necessary to update the forecast, assuming that the transition towards a more efficient user’s average behaviour is delayed: it will affect the value of the specific coefficients of consumption, to be rethought and extrapolated to 2020.

However, the growth rate of the dwellings and of the inhabitants will be maintained and extrapolated to the 2020 as well.

1.1.2.2.2 General data In the Table 1-15 , a demographic growth rate of 1.1% is supposed, as already done in ESTAP. Moreover, the same growth is extrapolated until the 2020.

Table 1-15 Demographic trend and number of dwellings, (forecast of 2000).

Year 2000 2005 2010 2015 2020

General data

Population thousand 2,073 2,190 2,313 2,443 2,580

Number of dwellings 321,614 370,758 413,000 454,000 510,000

Persons per dwelling 6.45 5.91 5.60 5.38 5.06

1.1.2.2.3 Space heating New dwellings will be larger in average, as well as they will have a higher percentage of heated area. They also will be better insulated. This factor should be stronger and in the complex the heat demand per unit of area will lower (in case of maintained heating options).

However, the delay in the installation of the metering systems in the households pushes against efficient behaviour, that in the forecast the effects are to be postponed.



Particularly, the share of electricity in space heating will became lower with a delay respect to the ESTAP hypothesis: its forecast for these values is more or less shifted by 5 years, and the 2005 has a growth of the electricity share up to 20.2%.

Table 1-16: electricity demand forecast concerning the household space heating

Year 2000 2005 2010 2015 2020

Space heating

Average area m2 74.1 75.6 77.2 78.7 80.8

Specific useful heat m2/kwh 226 300 260 225 195

% of heated floor % 40.8% 42.1% 43.1% 44.0% 44.8%

Total heat consumption GWh 2,197 3,540 3,573 3,537 3,600

Consumption per dwelling kWh 6,833 9,548 8,650 7,791 7,058

Share of electricity in space heating % 16.0% 20.2% 17.9% 16.8% 15.7%

Electricity for space heating GWh 352 714 641 595 565

1.1.2.2.4 Water heating ESTAP water heating specific consumption are confirmed, with extrapolation up to 2020, but the total consumption is slightly higher, due to a higher share of electricity, again due to the delay in reducing non metered consumption.

Table 1-17 : electricity demand forecast concerning the household water heating

Year 2000 2005 2010 2015 2020

Water heating Useful heat for water heating kWh/cap 251.0 284.0 321.3 363.5 411.3

Total heat consumption GWh 406 460 463 479 506


Share of electricity in water heating % 85.1% 94.0% 84.6% 81.4% 78.7%

Electricity for water heating GWh 443 584 628 723 835

1.1.2.2.5 Cooking Concerning the electricity used for cooking, the hypothesis of use of LPG is confirmed, but the penetration foreseen for 2015 is postponed to 2020, as is the share of electricity.. Moreover, 2005 and 2010 has a per capita consumption higher than the constantly assumed 196 kWh/person.

Table 1-18: electricity demand forecast concerning the household heat for cooking

Year 2000 2005 2010 2015 2020

Cooking

Useful heat for cooking kWh/cap 196.0 210.0 200.0 196.0 196.0


Consumption per dwelling kWh 1,263 1,240 1,120 1,055 992

Share of electricity in cooking % 72.7% 80.3% 70.2% 60.2% 42.9%

Electricity for cooking GWh 295 369 325 288 217



1.1.2.2.6 Non thermal uses It is supposed that the heat demand for non-thermal uses is significantly higher than in the ESTAP forecast for 2005. The difference from the original forecast should be progressively lower.

Table 1-19: electricity demand forecast for not thermal uses Year 2000 2005 2010 2015 2020

Not thermal uses Electricity for not thermal uses kWh/cap 294.0 432.0 435.2 438.5 454.7Consumption per dwelling kWh 1,895 2,551 2,437 2,359 2,300Total electricity for not thermal uses GWh 609 946 1,007 1,071 1,173

1.1.2.2.7 Entire balance for the household sector In the Comparing the results with findings of ESTAP (Table 7.2 of [5]), we have the same residential consumption in 2005, the share of water heating and cooking in total consumption is almost equal, while the component “other uses” has been estimated to be slightly higher, with a correspondent a reduce share of “space heating” component.

Table 1-20 all the previous forecasts are summarised, including the share of electricity in different uses.

It is worth noting that the relevant factors play counterbalancing roles in the trend of the electric consumption: on one hand, a richer lifestyle, the growth of the number of dwellings, and number of the inhabitants; on the opposite hand, an improvement of the electric efficiency and the penetration of other energy carriers (LPG in bottles for cooking are considered).

The assumption to reduce the non-authorised use of electricity in the household sector has a great impact in electricity demand. For the period 2000-2005 is estimated that this component was responsible of the increase of 43% of the electricity consumption.

Consequently, 2005-2010 could be revealed like stagnation due to the counterbalancing factors such as a slow decrease in illegal electricity consumption and the improvement of the specific parameters.

Comparing the results with findings of ESTAP (Table 7.2 of [5]), we have the same residential consumption in 2005, the share of water heating and cooking in total consumption is almost equal, while the component “other uses” has been estimated to be slightly higher, with a correspondent a reduce share of “space heating” component.

Table 1-20: electricity demand forecast extended to all the household uses, absolute values and sharing percentage.

Year 2000 2005 2010 2015 2020

Household Electricity Balance

Space heating GWh 352 714 641 595 565

Water heating GWh 443 584 628 723 835

Cooking GWh 295 369 325 288 217

Non-thermal electricity GWh 609 946 1,007 1,071 1,173

Total electricity for Housholds GWh 1,699 2,613 2,601 2,677 2,790 Space heating % 20.7% 27.3% 24.6% 22.2% 22.2%

Water heating % 26.1% 22.4% 24.2% 27.0% 27.0%

Cooking % 17.4% 14.1% 12.5% 10.8% 10.8%



Non-thermal uses % 35.9% 36.2% 38.7% 40.0% 40.0%

Total electricity % 100% 100% 100% 100% 100% Average electricity per household kWh 5,283 7,049 6,297 5,897 5,471

1.1.2.2.8 Services sector Also in the services sector, the delays in the application of reliable metering system make the detailed electricity forecast of ESTAP too low (chapter 5.3). The electricity consumption foreseen in the 2005 was 431 GWh, starting from the 289 GWh in 2000. But, apart from the lack of incentive to save electricity, the growth of electricity consumption in the service sector can be considered as a good fit with the original MGS scenario, from which we can take the forecast of m2/cap and used area. The corrections consist from the correlation between these parameters with the values of consumption, as was foreseen in the scenario “MGS without measures” discussed in ESTAP (Chapter 7.3).

It can be assumed that all the measures to reduce the illegal use of electricity in service sector will be adopted between 2010 and 2015, reaching in 2020 a condition that would be the same as by extrapolation from the scenario “MGS with measures” of ESTAP (Chapter 5.3). In other words, the scenario MGS without measures is still applicable in 2005 but is progressively reduced up to 2020.

Table 1-21: electricity demand forecast extended to all the uses in the services sector, absolute values and sharing percentage.

Year 2000 2005 2010 2015 2020

Service Electricity Balance Specific consumption GWh 145.3 293.4 448.7 618.1 759.1

Heating consumption GWh 136.6 218.3 262.0 335.9 421.1

Cooling consumption GWh 8.1 34.3 66.0 102.5 122.5

Total Service Sector GWh 290 546 777 1,057 1,303 Specific consumption % 50.1% 53.7% 57.8% 58.5% 58.3%

Heating consumption % 47.1% 40.0% 33.7% 31.8% 32.3%

Cooling consumption % 2.8% 6.3% 8.5% 9.7% 9.4%

Total Service Sector % 100% 100% 100% 100% 100%

1.1.2.2.9 Industry The industry consumption and the item “KEK consumption” are put together and compose the remaining component of total electricity demand. Unlike households and services sectors, industrial demand did not reach in 2005 the forecasted consumption, showing a delay in the foreseen growth. Hence, it is reasonable to update the industrial demand forecast according to the following procedure:

• A) to “postpone” the original “MGS without measures“ scenario up to 2020, taking into account the delay recorded for the 2005

• B) to “postpone” the original “MGS with measures“ scenario up to 2020“ as well. The 2005 value is not the real one, but the value as it would have been in the case of measures adoption.

• Compose the final scenario, assuming that from the 2005 entirely without measures there is a progressive transition up to the B) situation, completely reached in 2020.



Nevertheless, it has to be noted that:

• the industry sector is less sensitive than the others to the degree of implementation of the measures to reduce the commercial loss of electricity.

• The original scenarios described a more fluctuating trend, based on a strong initial increase in demand that did not materialise,

Table 1-22 reports the results of the updated electricity demand forecast regarding industry in MGS based on a revision of 2000 study and on the hypothesis of a progressive reduction of the commercial losses. The graph in Figure 1-12 shows the development of electricity demand for the study period up to 2020.

Table 1-22 : Updated industry MGS electricity demand forecast

Year 2000 2005 2010 2015 2020

Industry Scenario "MGS without measures" from ESTAP GWh 276 704 933.0 1,279.0

Scenario "MGS with measures" from ESTAP GWh 276 671 871.6 1,162.5 Scenario "MGS without measures" revised GWh 276 563 800 1,050 1,279

Scenario "MGS with measures" revised GWh 276 520 740 945 1,163 Final revision of industry demand forecast GWh 276 563 780 980 1,163

Figure 1-12: industry electricity demand forecast (2000-2020)

1.1.2.2.10 Losses The expected reduction of technical and non technical losses during the period 2000-2005 did not follow the ESTAP forecast, not only because of non implementation of the measures against the illegal consumption, but also because of lack of investment in transmission and distribution network

Table 1-23 shows a summary of the ESTAP forecast, characterised by a drastic decrease of the commercial losses, and with a regular improvement of the technical ones, and complete with actual data in the period 2001-2006 and new assumptions regarding loss reduction.



The new assumptions for losses forecast are:

• The technical fraction of the losses was constantly to 18% level, rather than decreasing;

• The objective of reaching 13% level for the technical losses and 5% for the commercial ones will be postponed to 2020.

• Given the present trend, at least for two years the level of technical losses will remain at 18% until end of 2007.

Table 1-23: Energy losses ESTAP forecast, 2001-2005 real data, updated and 2020 extended forecast.

Energy losses (%) ESTAP forecast Updated Forecast

Year Technical Non-technical

ESTAP forecast

Current data

Updated Technical

Updated Non-

technical

Total updated

% % % % % % % 2000 18.0 27.0 45.0 47.1 18.0 29.1 47.12001 17.7 30.0 47.7 47.3 18.0 29.3 47.32002 17.3 29.0 46.3 41.2 18.0 23.2 41.22003 17.0 25.0 42.0 42.7 18.0 24.7 42.72004 16.7 19.0 35.7 46.0 18.0 28.0 46.02005 16.3 15.0 31.3 50.4 18.0 32.4 50.42006 16.0 14.0 30.0 18.0 33.0 51.02007 15.7 13.0 28.7 18.0 32.0 50.02008 15.3 12.0 27.3 17.6 29.9 47.52009 15.0 11.0 26.0 17.2 27.8 45.12010 14.7 10.0 24.7 16.8 25.8 42.62011 14.3 9.0 23.3 16.5 23.7 40.22012 14.0 8.0 22.0 16.1 21.6 37.72013 13.7 7.0 20.7 15.7 19.5 35.22014 13.3 6.0 19.3 15.3 17.5 32.82015 13.0 5.0 18.0 14.9 15.4 30.32016 14.5 13.3 27.82017 14.2 11.2 25.42018 13.8 9.2 22.92019 13.4 7.1 20.52020 13.0 5.0 18.0



Figure 1-13 : MGS Development of losses 2005 - 2020

1.1.2.2.11 Forecast of the total electricity demand The previous discussion allows us to compile a new electricity demand forecast for the Kosovo, updated respect to ESTAP on the basis of the last period information and extended to 2020.

Table 1-24: Total electricitydemand forecast MGS

Year 2000 2005 2010 2015 2020

Industry updated MG Scenario GWh 276 563 780 980 1,163

% 11.8% 15.1% 18.3% 20.2% 21.5%

Service updated MG Scenario GWh 290 546 777 1,057 1,303

% 12.4% 14.6% 18.2% 21.8% 24.1%

Households updated MG Scenario GWh 1,699 2,613 2,601 2,677 2,790

% 72.4% 69.9% 60.9% 55.2% 51.6%

Electricity Consumption GWh 2,265 3,722 4,157 4,713 5,256

KEK Consumption GWh 82 18 114 133 155

Total Electricity Consumption GWh 2,347 3,740 4,271 4,846 5,411

Level of Technical Losses % 18.0% 18.0% 16.8% 14.9% 13.0%

Energy of Technical losses GWh 515 821 865 850 808

Total Electricity Demand GWh 2,862 4,562 5,136 5,696 6,219

The main conclusion is that the electricity demand in Kosovo has followed the forecast prepared under ESTAP study for the scenario MGS o without loss reduction. The new updated forecast indicate that in the MGS scenario the electricity demand in 2015 will be of about 5,696 GWh, a value that is between to the original ESTAP value in the case of loss reduction (5,137 GWh) and the value in the case of non reduction of non-technical losses(6,320 GWh).

The growth of electricity demand in Kosovo is following the forecasted trends, but electricity consumption in 2005 suffers the effects of the delays in the implementation of measures to reduce technical and non-technical losses. Most recently, there are indications that the countermeasures against the illegal consumption of electricity are going having an effect, i.e. the stagnation of the electricity consumption in 2005-2006.



Actually, this effect is less evident in the industry with low growth rates. This anomaly should be still effective in 2010, only to disappear progressively in the future.

The growth rates of the gross demand are, on the average around 2.4% in 2005-2010, 2.09% during 2010-2015 and almost 1.8% in 2015-2020. These growth rates could be described and presented as those of stagnant growth, but there is a need to take into account the counterbalancing effects of loss reduction which are expected to be reduced by small percentage each year.

Figure 1-14 : Total demand, technical losses and demand by sectors.

1.1.2.2.12 Variant of MGS forecast: Commercial loss reduction up to 2010

One of the conclusions of Module A of ESTAP I study was that average residential customers with meters consumed 4,500 kWh/a, while the average consumption of residential customers without meters was 68% more, about 7,554 kWh/a. The highest rate of measured residential consumption and the highest rate of residential consumption without meters occur in Pristina, where the consumption of a average residential customer without meters reaches 9,700 kWh/a, more than double that of average residential customer with a meter. These figures give an idea of the great impact on electricity demand (existing and projected) of the implementation of countermeasures against illegal consumption.

In the following are presented the main results of demand forecast based on the assumption that the measures aiming the elimination commercial losses will be successfully implemented up to 2010 and the level of commercial losses in 2011 will be 5%.



Table 1-25 reports the results of forecast prepared for MGS with reduction of commercial losses up to 2010.

The results of this assumption are shown in Figure 1-15. Under these assumptions, electricity consumption in households would drop down in 2010 to 2,138 GWh, and then would increase a slower rate up to 2,391 GWh in 2020. The average annual growth rate is estimated around –0.59% for the analysed period.

Table 1-25 Total electricity demand forecast for MSG with commercial loss reduction

Year 2000 2005 2010 2015 2020 Industry updated MG Scenario GWh 276 563 780 980 1,163 % 11.8% 15.1% 20.5% 22.1% 23.2%Service updated MG Scenario GWh 290 546 777 1,057 1,303 % 12.4% 14.6% 20.4% 23.9% 26.0%Households updated MG Scenario GWh 1,699 2,613 2,138 2,260 2,391 % 72.4% 69.9% 56.1% 51.0% 47.7%Electricity Consumption GWh 2,265 3,722 3,694 4,297 4,856KEK Consumption GWh 82 18 114 133 155Total Electricity Consumption GWh 2,347 3,740 3,808 4,430 5,011Level of Technical Losses % 18.0% 18.0% 16.8% 14.9% 13.0%Energy of Technical losses GWh 515 821 771 777 749Total Electricity Demand GWh 2,862 4,562 4,579 5,207 5,760

In an hypothetical case considering the commercial losses around a typical level (app.5%) in 2005, the electricity demand in household sector is estimated to be of about 1,920 GWh. Referring to this year and assuming the same level of commercial losses, the average annual growth rate of household sector is estimated around 1.48 % for the analysed period.



Figure 1-15 : Demand forecast in MGS with commercial loss reduction in 2010.

Updated Medium Growth ScenarioReduction of Commercial Losses up to 2010

Electricity Demand Forecast (2005-2020)

2,6132,138 2,260 2,391

8941,113

1,318

1,057821 771

777

749

581

546 777

1303

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2005 2010 2015 2020Year

Elec

tric

Ene

rgy

Households Industry Services "Losses"

5.97 %/a.

4.95 %/a.

-0.59 %/a.

1.57 %/a.



1.1.2.3 Electricity demand forecast: HGS scenario The HGS scenario assumes the highest standard of living for household sector, the highest economic growth of the country with impact on electricity consumption in the services as in the industry as well; and full recovery of large industrial complexes, etc. We can assume that t a higher growth is associated with a more effective campaign of loss reduction. Conservatively, it could be assumed that the losses remain constant, in percentage terms.

1.1.2.3.1 Household

1.1.2.3.2 General data The Table 1-26 is prepared following the ESTAP hypothesis for HGS, namely a the average yearly construction of 10,000 apartments per year until 2015. To extrapolate until the 2020, the same growth rate is assumed as in 2010-2015.

As for the population, it will grow with the same constant 1.1% used for the MGS. It means that in 2020 the value of 4.84 persons/dwelling will be reached.

Table 1-26: Demographic trend and number of dwellings in HG Scenario.

Year 2000 2005 2010 2015 2020

General data

Population thousand 2,073 2,190 2,313 2,443 2,580

Number of dwellings 321,614 370,758 420,000 470,000 533,320

Persons per dwelling 6.45 5.91 5.51 5.20 4.84

1.1.2.3.3 Space heating Comparing with MGS space heating, only the percentage of the heated floor area has changed, while the dwellings maintain the same average surface, and the same average consumption per heated area (generally a higher growth is associated with higher efficiency).

Table 1-27: Household electricity demand forecast for space heating in HGS Year 2000 2005 2010 2015 2020

Space heating Average area m2 74.1 75.6 77.2 78.7 Specific useful heat m2/kwh 226 300 260 225 195% of heated floor % 40.8% 42.1% 43.8% 45.5% 47.0%Total heat consumption GWh 2,197 3,540 3,692 3,787 3,950Consumption per dwelling kWh 6,833 9,548 8,792 8,057 7,406Share of electricity in space heating % 16.0% 20.2% 17.9% 16.8% 15.7%Electricity for space heating GWh 352 714 662 637 620

1.1.2.3.4 Water heating The specific consumption of “water heating pro capita” is higher than in MGS and in 2020 is estimated to be about 442 kWh/capita. It means an annual growth of this component is assumed 3% instead of than 2.5% in MGS.



Table 1-28 Household electricity demand forecast for water heating in HGS

Year 2000 2005 2010 2015 2020

Water heating

Useful heat for water heating kWh/cap 251.0 284.0 329.2 381.7 442.5



Share of electricity in water heating % 85.1% 94.0% 84.6% 81.4% 78.7%

Electricity for water heating GWh 443 584 644 759 899

1.1.2.3.5 Cooking Following the ESTAP assumption, the electricity consumption for cooking can be considered equal in MGS or HGS.

Table 1-29 Household electricity demand forecast for cooking in HGS

Year 2000 2005 2010 2015 2020

Cooking Useful heat for cooking kWh/cap 196.0 210.0 200.0 196.0 196.0


Consumption per dwelling kWh 1,263 1,240 1,101 1,019 948

Share of electricity in cooking % 72.7% 80.3% 70.2% 60.2% 42.9%

Electricity for cooking GWh 295 369 325 288 217

1.1.2.3.6 Non thermal uses The electric consumption for non heat uses is more sensitive to a higher standard of living than the other components of the electricity demand for households, as can be noted from Table 1-30.

Table 1-30 Household electricity demand forecast for non heat uses in HGS Year 2000 2005 2010 2015 2020

Not thermal uses Electricity for not thermal uses kWh/cap 294.0 432.0 453.6 475.2 496.8Consumption per dwelling kWh 1,895 2,551 2,498 2,470 2,403Total electricity for not thermal uses GWh 609 946 1,049 1,161 1,282

1.1.2.3.7 HGS entire balance for the household sector The final balance of future electricity demand for household sector in Kosovo according to HGS scenario is reported in Table 1-31 and the main conclusions are:

• The average electricity consumption per dwelling is decreasing, after reaching a maximum in 2005. The average dwelling contains 5.51 persons in 2005, where in 2020 there are only 4.84. Comparing to 2005 situation in 2020 it is foreseen a higher efficiency in the use of electric energy and a decrease in the electricity share (i.e. for heating). The current situation in the household sector is heavily affected from not paid electricity.

• The electricity demand in 2020 is 3017GWh, from 2614 GWh in 2005, in the MGS the 2020 value is 2790 GWh.

• The variation of the sharing of each use is particularly interesting: the share of electricity for cooking is reduced due to the penetration of the LPG bottles. The



share of space heating is also reduced and the share for non-thermal use is increased.

Table 1-31 Household electricity demand forecast in HGS. Year 2000 2005 2010 2015 2020

Household Electricity Balance Space heating GWh 352 714 662 637 620Water heating GWh 443 584 644 759 899Cooking GWh 295 369 325 288 217Non-thermal electricity GWh 609 946 1,049 1,161 1,282Total electricity for Households GWh 1,699 2,614 2,680 2,845 3,017 Space heating % 20.7% 27.3% 24.7% 22.4% 22.4%Water heating % 26.1% 22.4% 24.0% 26.7% 26.7%Cooking % 17.4% 14.1% 12.1% 10.1% 10.1%Non-thermal uses % 35.9% 36.2% 39.1% 40.8% 40.8%Total electricity % 100% 100% 100% 100% 100% Average electricity per household kWh 5,283 7,049 6,381 6,053 5,658

1.1.2.3.8 Industry The industry sector is very sensitive to the economic growth rate. It is assumed that the industry is not affected by illegal electricity consumption, mainly due to a greater difficulty in avoiding the billing and payment of the electricity. This assumption was made in ESTAP for the MGS scenario (for the HGS there was not a comparison between with and without measures against illegal consumption), and it is maintained here, also for the HGS scenario. Moreover, the recent data confirm that industry (as in general for the big customers) has a low share of not paid consumption.

The forecast results for the industry sector are reported in Table 1-32 and the main features are

• The case "HGS with measures" from ESTAP (paragraph 5.2.) is reported;

• The verified 2005 values are considered ( postponed respect to the forecast) ;

• 2010 and 2015 maintains the same growth percentage of the case without delay .

• Contrary to the MGS case, it is supposed that a good growth rate is maintained up to the 2020 (rather to a shift of 2015 objectives to 2020). One of the main reasons is that the rehabilitation of the mines and industries of Trepca is postponed to 2014.

Table 1-32: Industry electricity demand forecast, HGS scenario

Year 2000 2005 2010 2015 2020

Industry

Scenario "HGS with measures" revised GWh 276 704 1,167 1,720

Scenario "HGS without measures" revised considering current delays GWh 276 563 911 1,470 2,370

Average yearly growth, % 15.32% 10.11% 10.04% 10.02%

Final revision of industry demand forecast GWh 276 563 911 1,470 2,370



1.1.2.3.9 Services The services sector has a remarkable sensitivity both to the growth rate and to the adoption of the measures against illegal consumption. The main assumptions are:

• Following the higher growth rate, the service area per capita and the consumption per area will increase. Moreover, the share of cooled area will also increase.

• Without measures against illegal consumption, the electricity demand increases, with different effect in the different uses. Particularly, it will affect mainly the electric heating, and less so the non heat uses. The use of electricity for cooling shows a moderate sensitivity to widespread of illegal consumptions in service sector. It becomes an incentive not to save electricity

• The difference between implementing and not implementing measures against illegal consumption is transformed into half percent of annual growth in the electricity consumption, as observed in the comparison of the MGS scenarios.

• However, in 2020 the demand is estimated to be at the same levels as was foreseen in ESTAP HGS “without measures”. The growth rate in the electricity consumption will be 10.53% from 2005 to 2010, 9.40% from 2010 to 2015 to be reduced to 6.32% from 2015 to 2020.

The results reported in Table 1-33 are obtained using the same methodology as for the MGS: the consumption have a progressive transition from the scenario “without measures” (2005) to the scenario with measures (2020).

Table 1-33 Electricity demand data for services sector, HGS scenario Year

HG scenario revised 2000 2005 2010 2015 2020

Service Electricity Balance Specific consumption GWh 145.3 293.4 483.6 771.4 1,109.5Heating consumption GWh 136.6 218.3 356.8 507.6 575.8Cooling consumption GWh 8.1 34.3 60.5 132.6 232.2Total Service Sector GWh 290 546 901 1,412 1,918 Specific consumption % 50.1% 53.7% 53.7% 54.6% 57.9%Heating consumption % 47.1% 40.0% 39.6% 36.0% 30.0%Cooling consumption % 2.8% 6.3% 6.7% 9.4% 12.1%Total Service Sector % 100% 100% 100% 100% 100%

1.1.2.3.10 Total forecast for the HGS scenario Table 1-34 reports the results of forecast prepared for HGS. Losses are slightly less than MGS, in percentage terms, as a higher share of the total supplied electricity is used by customers connected in the HV network.



Table 1-34 Total electricitydemand forecast HGS Year 2000 2005 2010 2015 2020

Industry updated HG Scenario GWh 276 563 911 1,470 2,370 % 11.8% 15.1% 19.8% 25.1% 31.8%Service updated HG Scenario GWh 290 546 901 1,412 1,918 % 12.4% 14.6% 19.6% 24.1% 25.7%Households updated HG Scenario GWh 1,699 2,614 2,680 2,845 3,017 % 72.4% 69.9% 58.2% 48.6% 40.4%Electricity Consumption GWh 2,265 3,723 4,492 5,726 7,305KEK Consumption GWh 82 18 114 133 155Total Electricity Consumption GWh 2,347 3,741 4,606 5,859 7,460Level of Technical Losses % 18.0% 18.0% 16.8% 14.4% 12.0%Energy of Technical losses GWh 515 821 933 986 1017 Total Electricity Demand GWh 2,862 4,562 5,539 6,845 8,477

Figure 1-16: HGS scenario, total electricity demand, technical losses and subdivision by sector.

1.1.2.3.11 Variant of HGS forecast: Commercial loss reduction up to 2010 The following presents the main results of demand forecast based on the assumption that the measures targeting the elimination commercial losses will be successfully implemented up to 2010 and the level of commercial losses in 2011 will be 5%. Table 1-35 reports the results of forecast prepared for HGS with reduction of commercial losses up to 2010.

The results of this assumption are shown in Figure 1-17. Under these assumptions, electricity consumption in households would drop down in 2010 to 2,168 GWh, and thereafter would increase at a slower rate up to 2,488 GWh in 2020. The average annual growth rate is estimated around –0.33% for the analysed period.



In an hypothetical case considering the commercial losses around a typical level (app.5%) in 2005, the electricity demand in household sector is estimated to be of about 1,920 GWh. Referring to this year and assuming the same level of commercial losses, the average annual growth rate of household sector is estimated around 1.77 % for the analysed period.

Table 1-35 Total electricity demand forecast for HSG with commercial loss reduction

Year 2000 2005 2010 2015 2020 Industry updated HG Scenario GWh 276 563 911 1,470 2,370 % 11.8% 15.1% 22.3% 27.5% 34.2%Service updated HG Scenario GWh 290 546 901 1,412 1,918 % 12.4% 14.6% 22.0% 26.4% 27.7%Households updated HG Scenario GWh 1,699 2,614 2,168 2,324 2,488 % 72.4% 69.9% 52.9% 43.5% 35.9%Electricity Consumption GWh 2,265 3,723 3,980 5,206 6,776KEK Consumption GWh 82 18 114 133 155Total Electricity Consumption GWh 2,347 3,741 4,094 5,339 6,931Level of Technical Losses % 18.0% 18.0% 16.8% 14.4% 12.0%Energy of Technical losses GWh 515 821 829 898 945Total Electricity Demand GWh 2,862 4,562 4,923 6,237 7,876

Figure 1-17 : Demand forecast in HGS with commercial loss reduction in 2010.

Updated High Growth ScenarioReduction of Commercial Losses up to 2010

Electricity Demand Forecast (2005-2020)

2,614 2,168 2,324 2,488

1,0251,603

2,525

1,412821

829

898

945

581

1918

901546

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2005 2010 2015 2020Year

Elec

tric

Ene

rgy

Households Industry Services "Losses"

8.73 %/a.

10.06 %/a.

-0.33 %/a.

3.71 %/a.



1.1.2.4 Load curves and peak power estimation Estimation of the total load curves and of the peak power at each network voltage level (LV, MV, and HV) was undertaken by the Kosovo Load Model (KLM: for a full description see [5-a]) . The same software was utilised in ESTAP study.

This model separately considers the end-use of each customer category. Residential space heating end-use was divided into “direct space heating” (utilised manly during the day) and “storage space heating” (energy consuming mainly during the night), because they have a very different impact on the load curves. A total of 9 end-uses load classes were modelled by coefficients representing electric energy modulation through time. The nine end uses categories are:

• Residential: space heating divided into direct and storage; • Residential: cooking; • Residential: hot water; • Residential: other uses; • Services: heating and thermal uses; • Services: other uses; • Industry: thermal uses; • Industry: other uses;

A description of the different load coefficient for the three types of modulation in time (annual modulation, weekly modulation and daily modulation) together with a description of the Peak Power estimation method are reported in [5-b] .

Typical load shapes for KLM model are reported in Figure 1-18.

Residential Other Users - Winter and Summer

Residential Cooking and Hot Water

Residential Space Store and Direct Heating Services : Heating and Thermal Uses



Industry

0

0,2

0,4

0,6

0,8

1

1,2

1,4

1,6

0 3 6 9 12 15 18 21 24

Day hours

p.u

Thermal Users Non Thermal Users

Services : Other Uses Winter and Summer Industry: thermal and no thermal uses

Figure 1-18 - Typical load shapes for KLM model

1.1.2.4.1 Peak power estimation in MGS Load curves and peak power estimation results, obtained by the Kosovo Load Model from the electrical energy forecast analysis described above, are reported in Figure 1-19 for MGS.

Following the analysis performed with KLM model , are calculated the hourly loads for some target years. As example the figure Figure 1-23 shows the annual Load Duration Curves relevant to 2010, 2015 and 2020 corresponding to medium growth scenario.

1.1.2.4.2 Peak power estimation in MGS with commercial loss reduction up to 2010 Load curves and peak power estimation results, obtained by the Kosovo Load Model from the electrical energy forecast analysis described above, are reported in Figure 1-20 for MGS in case that the commercial losses will be reduced up to 5% in 2010.

1.1.2.4.3 Peak power estimation HGS Load curves and peak power estimation results, obtained by the Kosovo Load Model from the electrical energy forecast analysis described above, are reported in Figure 1-21 for HGS.

Following the analysis performed with KLM model , are calculated the hourly loads for some target years. As example the figure shows the annual Load Duration Curves relevant to 2010,2015 and 2020 corresponding to medium growth scenario.

The Figure 1-23 shows the annual Load Duration Curves relevant to 2010,2015 and 2020 corresponding to high growth scenario.

1.1.2.4.4 Peak power estimation in MGS with commercial loss reduction up to 2010 Load curves and peak power estimation results, obtained by the Kosovo Load Model from the electrical energy forecast analysis described above, are reported in Figure 1-22 for HGS in case that the commercial losses will be reduced up to 5% in 2010.



Figure 1-19 - Peak power estimation in MGS



Figure 1-20 - Peak power estimation in MGS with commercial loss reduction in 2010



Figure 1-21 -: Load curves and peak power estimation in HGS



Figure 1-22 – Peak power estimation HGS with commercial loss reduction up to 2010

Figure 1-23 –LDCs of MGS and HGS 2010, 2015 and 2020

Medium Growth ScenarioAnnual Load Duration Curves 2010-2020

-100

100

300

500

700

900

1100

1300

1500

0 1000 2000 3000 4000 5000 6000 7000 8000 9000h

MW

LDC-2010 LDC-2015 LDC-2020

High Growth ScenarioAnnual Load Duration Curves 2010-2020

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 1000 2000 3000 4000 5000 6000 7000 8000 9000h

MW

LDC-2010 LDC-2015 LDC-2020



1.1.2.5 Comparison with other forecasts The prepared forecast of electricity demand is compared with ESTAP forecast and peak power loads are reported in the following tables.

1.1.2.5.1 Electricity Demand Forecast Energy forecast values from 2005 to 2020 are reported in Table 1-36 and Figure 1-25 It can be noted that in 2005 the new MSG values were very close to those of ESTAP MGS without measures for the reduction of non-technical losses. The new demand values at the end of the period, year 2020 are not different from the values of ESTAP MGS with measures for non-technical losses reduction (option b)

The comparison with other forecasts is particularly difficult because of the methodology applied and assumptions used and differences in starting points. The same table reports the results of the demand forecasts prepared in REBIS GIS study for Kosovo and in the Figure 1-24 the development of the demand during 2005-2020 is illustrated graphically.

Comparing the Case 2 of REBIS study with our updated MGS, it can be noted that the electricity demands at the end of the period are almost the same. The REBIS GIS central case, Case 2, indicates a offset in first part of the period followed by relatively slow growth in demand over the period to 2020. The differences are in the intermediate years and are due to the different estimation of the amount of shed load.

The forecast prepared for MGS demonstrates a more constant growth with a slight saturation, meanwhile the HGS is characterised by a considerable growth of demand occurring towards the end of the forecast period. We consider that our estimation is more precise and is based on the updated information in amount of shed load and (source KoSTT) and updated statistics of electricity consumption for the years 2003, 2004, 2005 and 2006.

Table 1-36 - Energy forecast from 2005 to 2020

Updated MGS

Updated HGS

Actual Demand

Corrected Demand

ESTAP MGS

ESTAP MGS no-

meas

Case 2 PwC forecast

Case 1 PwC forecast

Case 3 PwC forecast

GWh GWh GWh GWh GWh GWh GWh GWh GWh

2005 4,562 4,562 4,259 4,259 3,586 4,431 6,019 5,696 5,985 2006 4,660 4,725 4,271 4,751 3,714 4,608 6,092 5,636 6,119 2007 4,771 4,908 3,846 4,793 6,534 5,958 6,628 2008 4,874 5,090 3,983 4,984 6,616 5,927 6,779 2009 4,994 5,299 4,125 5,184 6,702 5,909 6,942 2010 5,136 5,539 4,271 5,391 6,735 5,847 7,064 2011 5,235 5,764 4,432 5,569 6,779 5,803 7,201 2012 5,340 6,009 4,599 5,753 6,833 5,776 7,353 2013 5,452 6,276 4,772 5,943 6,896 5,762 7,519 2014 5,571 6,568 4,951 6,139 6,969 5,762 7,700 2015 5,696 6,845 5,137 6,341 7,050 5,773 7,894 2016 5,790 7,119 5,330 6,550 7,191 5,828 8,168 2017 5,890 7,417 5,531 6,767 7,337 5,891 8,453 2018 5,994 7,741 5,739 6,990 7,487 5,960 8,749 2019 6,104 8,094 5,954 7,221 7,641 6,036 9,057 2020 6,219 8,477 6,178 7,459 7,800 6,118 9,375



Figure 1-24 – Electricity demand forecast from 2005 to 2020

1.1.2.5.2 Peak power forecast Peak power forecast values from 2005 to 2020 are reported in Table 1-37 and the graphics in Figure 1-25 illustrate the peak development according to updated MGS and HGS compared to ESTAP scenarios and the forecast performed by REBIS study.

It can be noted that the values of updated MGS are very close to those of ESTAP MSG without measures for the reduction of non-technical losses, and the updated HGS has almost the same growth rate from year to year as the ESTAP HSG scenario.

Table 1-37 - Peak forecast from 2005 to 2020

Updated MGS

Updated HGS

Actual Peak

Corrected Peak

ESTAP MGS

ESTAP MGS no-meas

ESTAP HGS

Case 2 PwC

MW MW MW MW MW MW MW MW 2000 653 653 653 653 653 2001 763 763 763 852 763 763 763 2002 723 723 723 820 723 723 723 2003 759 759 759 847 759 759 759 944 2004 819 819 811 863 819 819 819 1,055 2005 1,030 1,030 898 956 749 1,019 796 1,179 2006 1,055 1,069 916 1,019 775 1,029 847 1,196 2007 1,081 1,088 803 1,071 896 1,213 2008 1,107 1,159 831 1,113 948 1,230 2009 1,130 1,210 861 1,158 1,002 1,247 2010 1,154 1,263 891 1,204 1,060 1,265 2011 1,171 1,314 933 1,182 1,151 1,261 2012 1,189 1,367 969 1,221 1,214 1,258 2013 1,212 1,414 1,005 1,261 1,281 1,254 2014 1,235 1,467 1,043 1,303 1,351 1,251 2015 1,270 1,557 1,082 1,345 1,425 1,247 2016 1,291 1,616 1,123 1,390 1,504 1,273 2017 1,312 1,678 1,165 1,436 1,586 1,300 2018 1,333 1,741 1,209 1,483 1,674 1,327 2019 1,355 1,807 1,254 1,532 1,766 1,355 2020 1,377 1,876 1,301 1,583 1,863 1,384



The PwC ([10] Volume 2 ) central case, Case 2, shows differences only in the period from 2005 to 2010, due to the differences on the starting point. After this year the peak power curve follows the same growth up to 2020 as in our MGC.

Figure 1-25 - Peak power forecast from 2005 to 2020



1.2 Subtask 1.1.C. Pricing of electricity (actual level in SEE countries and long-term forecast level)

1.2.1 Electricity market background of the countries analysed For the time being, most SEE countries have very fragmented and inefficient electricity markets, which do not provide the price signals that would direct the decision-making of the enterprises in the sector.

From the point of view of regulation, the SEE countries are undergoing a deregulation and liberalisation process defined by the Athens Treaty. The deregulation process and the outcome have varied greatly in the SEE countries, and price controls, especially for retail customers, have remained strong. The half-way liberalisation outcome has also been aggravated by continuous and gradually increasing capacity shortage, especially in Albania, Kosovo and Greece.

The recently formed TSOs of the region are currently planning and testing their allocation mechanisms for cross-border transmission capacity allocation. As the region is split into nine relatively small countries, the requirement for e.g. two cross-border transmission points can be created for even quite short transmission distances. The missing cross-border allocation mechanisms have contributed to a small share of cross-border power exports and imports and to the distortion of price picture.

At this stage of deregulation, it is difficult to establish what the “actual” electricity prices are in the SEE region. Although there are a few electricity exchanges operating in SEE, the credibility of such electricity exchanges is limited by their low market share. In addition, strict price regulation affceting many customer segments limits the efficiency of the market.

Based on various sources (e.g. Albanian capacity tenders, information from independent traders etc.) it can be concluded that quite limited amounts of power are available in SEE “in the free market” for prices exceeding € 40 MWh. In many cases, industrial customers can buy power from their incumbent utilities at prices which are much lower.

We begin with a description of the electricity market in each of the countries that we have modelled: Albania, Bosnia and Herzegovina, Bulgaria, Croatia, Kosovo, Romania, Macedonia, Serbia, and Montenegro. For detailed lists of power plants in these countries we refer the reader to commercially available databases, e.g. Platts, and we limit ourselves to analysing the transmission capacities to/from Kosovo to nearby-markets.

1.2.1.1 Albania

Power Generation system in Albania

Generation capacity The Albanian power generation system is predominantly hydro, with hydro generation located mainly n the northern part of the country, and normally representing over 90% of the country’s total power generation. Thus the power system reliability is very dependant on the hydro conditions. The other part of Albania’s capacity (8%) is thermal power plants.



Transmission and Distribution The transmission system includes the 400, 220 and 110 kV voltage levels. The Albanian Power System has 400/220 high voltage substations with a total installed capacity of 5.031 MVA.

The Albanian Power System is facing serious problems due to insufficient development of the transmission system and lack of rehabilitation and upgrading of the equipment during the last 15 years. This has considerably reduced the reliability of system operation and the quality of electricity supplied, and has limited the exchange capacity with neighbouring jurisdictions.

Structure of the Albanian market Actually the Albanian electricity market is represented by:

• The public sector (state owned) is consisting of TSO and the utility KESH (with generation and distribution), and

• The private sector consisting of the small companies taken by concession by Governmental decision and small independent power producers (IPP).

The private sector had its beginning in 2002 and was doing first steps towards an opening of the electricity market. There are in total 13 small companies that operate in this sector.

The public sector consists of KESH. The unbundling of a TSO from KESH started in 2004, and TSO still preserves its monopoly position for import and export of electricity. KESH and TSO own 99-99.5% of the quantity of the electricity in the market and TSO is the only one that imports 100% of electricity that is needed for the lack of capacity in the domestic generation.

Besides KESH, Shkoder, Elbasan and Vlora are private companies that share the distribution of electricity in the remainder of Albania.

The framework of the new organization is based on Law No. 9072, date 22/5/2003 “On the Power Sector” and managed by the Transmission System Operator (TSO).

Energy Regulatory Authority in Albania ERE was set up in September 1999 and is in charge of the regulation of tariffs. Five commissioners appointed by the government form the governing body of the agency. The ERE is responsible for the approval of tariffs and prices, licensing of companies in electrical energy sector and monitoring their activities. It is financed from the licensing fees.

1.2.1.2 Bosnia -Herzegovina

Power Generation System in Bosnia-Hergovina

Generation Capacity About 59% of the total generation is produced by thermal power plants while the rest is generated by hydro power plants.



Transmission and Distribution The transmission system includes the 400, 220 and 110 kV voltage levels with an overall length of 5.565 km and a total transformer capacity of about 4.744 MVA. The distribution system includes a 10 kV, 6 kV, 1 kV and 0,4 kV voltage levels with distribution lines of 28.497 km of length.

Structure of the Bosnia-Herzegovina market The power sector consists of three vertically integrated monopolies: Elektroprivreda Bosne i Herzegovine (EPBiH), Elektroprivreda of the Republic of Srpska (EPRS) and Elektroprivreda Hrvatske Zajednice Herceg-Bosna (EPHZHB). The power companies are synchronised and interconnected, but there is no competition among them; they are virtual monopolies within their exclusive ethnically based service territories.

The total net generation from these three companies was split into 45,33% of EPBiH, the largest company, 40,80% of ERS and 13,87% of EPHZHB. EPBIH and EPHZHB are holders of single power generation license each for all of their generation facilities, while generation subsidiaries of EPRS are licensed separately.

A single company for transmission of electricity (Elektroprenos Bosne i Hercegovine, Banja Luka) started its operations in February 2006.

EPBIH and EPHZHB are holders of a single distribution license each, while distribution subsidiaries of EPRS are licensed separately. Distribution in Brčko District of BIH is done by a separate entity, attached to the local government.

Energy Regulatory Authority The State Electricity Regulatory Commission (SERC) is an independent and non-profitable institution of Bosnia and Herzegovina, which acts in accordance with the principles of objectivity, transparency and equality, and has jurisdiction over the transmission of electricity, transmission system operation and international trade in electricity. The SERC was established by the Parliament of Bosnia and Herzegovina by adopting the Act on Transmission, Regulator and Electricity System Operator, and appointing the Commissioners (July 1, 2003).

1.2.1.3 Bulgaria

Power Generation System

Generation Capacity Thermal power plants (51%) and nuclear generation (41%%) dominate the available generation capacities. Bulgaria is dependent on imports for 70% of its primary energy supplies. Most of the existing thermal power plants need rehabilitation and modernization.

Transmission and Distribution Bulgaria's high-voltage power transmission network consists of transmission lines of 750 kV, 400kV, 220kV, and 110kV; step-down substations; one 400kV switching station; and medium and low voltage distribution networks that supply the industrial, public and residential customers.

Structure of the Bulgarian market



Until mid-2000, the national electric utility, Natsionalna Elektricheska Kompania (NEK), set up in 1992, was responsible for power generation and transmission, as well as for energy trade. It owned all nuclear, hydro and pumped hydro power plants in Bulgaria. After restructuring in 2001, NEK is now only responsible for transmission. NEK is an observer in the regional group of four transmission system operator companies, CENTREL.

At the end of the unbundling process, it is intended that NEK will retain only its network assets, and the system operator function.

The seven regional distribution companies have been incorporated as joint stock companies in which the State, through the Ministry of Energy, owns 100% of the equity shares. The eighth distribution company "Zlatni piasazi - Service" AD is already in private ownership. Privatisation of the others is intended (time of price liberalization).

The production is ensured by seven companies that are being privatized - the Nuclear Power Plant (NPP) Kozloduy and the Thermal Power Plant (TPP) coal/lignite of Maritza East 2 remaining public. Independent producers, concentrated into 9 municipal district heating companies and 17 industrial TPPs make up for 11% of generation in the country. Several hydropower plants are being sold.

The Ministry of Energy and Energy Resources (MEER) published its “Energy Strategy for Bulgaria” in 2002. This policy has started to be implemented by the new November 2003 Energy Law2, which sets the framework for gradual opening of the electricity and gas markets.

Energy Regulatory Authority The regulator, SEWRC (formerly SERC), is responsible for setting tariffs for customers in the captive market, and for issuing licenses to participants in the gas, electricity and district heating markets.

1.2.1.4 Croatia


Generation Capacity Croatia’s electricity production can be divided into 51% thermal, 37% hydro and 12% nuclear generation.

Transmission and Distribution The Croatian transmission system operates at the following levels: 400 kV, 220 kV and 110 kV. The transmission lengths at each transmission voltage level are: 157,4 km (400 kV), 1.245,1 (220 kV) and 4.762,6 km (110 kV).

Structure of the Croatian market Upon the independence of the Republic of Croatia in 1991, several state-owned public enterprises were formed, among them, Hrvatska Elektroprivreda d.d. (HEP). The 119 independent electricity entities in the Croatian territory were then consolidated into a single enterprise organised on a functional-territorial basis. In the form of a

2 The Energy Law was published State Gazette No. 107 of December 09, 2003 and is effective as of December 12, 2003



government-owned stock company, HEP has operated since 1994; in July 1995 it was harmonized with the then new Companies Act. The HEP Group – a system of affiliated companies performing core electric activities and auxiliary activities – was formed in July 2002. HEP Group has some subsidiary companies over which HEP exercises prevailing control: HEP Production, HEP Transmission, HEP Distribution, HEP Supply, HEP Gas, HEP District Heating, Sisak District Heating. The privatisation of HEP will be performed in accordance with the HEP Privatisation Act (Official Gazette 32/02).

HEP supplies 95 percent of electricity demand in Croatia. The remaining 5% is generated in industrial cogeneration plants and in small private hydro power plants.

With the relevant legislation passed in 2002, the Croatian Independent System and Market Operator (CroISMO) was established as operator of the electric power system other than HEP itself.

Croatia began the process of developing a competitive internal power market several years ago. By initiating the draft treaty that created the Energy Community of South East Europe in March of 2005, Croatia took the decisive step of joining the regional electricity market, with the ultimate goal of incorporating Croatia into the European Internal Electricity Market. Coming into compliance with EU Directives governing internal power markets will require that the current monopoly of the Croatian market, presently held by the national power utility (HEP), gradually transitions to a regulated market model.

Energy Regulatory Authority The Croatian Energy Regulatory Council (CERC) is the independent regulatory authority responsible for monitoring the market to ensure non-discrimination, effective competition and the efficient functioning of the market. CERC is working on secondary legislation, licensing procedures, public service obligations, transmission fees, data collection and grid codes, thereby enabling the Council to assume its new responsibilities quickly and effectively. CERC joined a regional regulators association (ERRA) to improve regional dialogue on common issues.

1.2.1.5 Kosovo


Generation Capacity Kosovo has a substantial potential for electricity generation (lignite) and, together with other resources, and there is also a small hydro-electric potential. The coal (lignite) deposits in Kosovo are primarily used (approximately 85%) in the two generating plants – Kosovo A and Kosovo B – to provide electricity. The total installed generation capacity is 1.498 MW.

Transmission and Distribution The total length of transmission lines (400, 220 and 110 KV) is 1.162 km. During the conflict the transmission network, especially the 400 kV portion, was partially destroyed. Most of the transmission lines are now back in operation following recent repairs, while many substations are still in bad technical condition.

The 400 kV and 220 kV transmission networks of Kosovo (UNMIK) is an integral part of the regional interconnected transmission system.



Structure of the Kosovan market The UNMIK power system was until recently dominated by a vertically integrated monopoly – public utility Korporata Enegjetike e Kosoves (KEK) – that operated two lignite mines, two lignite fired power plants, the transmission and distribution networks, and a dispatching centre. The only significant power plant outside KEK was a hydro power plant Gazivode/Ujman (2x17,5 MW) operated by an irrigation company (Hidrosistem Ibar-Lepenac). A TSO, KoSTT, was formed in 2006.

The establishment of an energy regulator falls within the wider framework of energy policy harmonization in South Eastern Europe. On behalf of Kosovo, UNMIK signed Energy Community of South East Europe (ECSEE). By doing that, Kosovo became an equal partner and player in establishing ECSEE, which is of prime importance for its economic development, because of favourable lignite reserves and the ideal position of Kosovo for power exchanges in the SEE region. Kosovo is committed to become a power exporter after 2012 and to further reinforce its central role in facilitating power wheeling in the SEE region.

Energy Regulatory Authority On 30 June 2004 the Energy Law, Electricity Law and Law on Energy Regulator were promulgated. These laws are promoting the integration of Kosovo into the European Economic area with a view to its future accession to the EU; participation of Kosovo in all relevant international agreements that Kosovo is a party to or may become associated with and gradual harmonization of the energy legislation of Kosovo to the EU’s energy legislation. Law 2004/9 “on Energy Regulator” established a strong, fully-independent regulator (Energy Regulatory Office - ERO), completely autonomous from any Governmental Department to exercise economic regulation in the energy sector.

1.2.1.6 Romania


Generation Capacity In 2005, Romania’s total net generation could be divided into hydropower with 25%, thermal power with 66% – mainly lignite, with some hard coal and nuclear with 9%.

The rehabilitation and modernisation of existing coal plants has already begun, and some ageing plants will undergo fuel conversions to get more efficient configurations with pollution abatement.

Transmission and Distribution Romania has an extensive interconnected power transmission and distribution network with an overall length of about 239.618 km, and a total transformer capacity of about 93.554 MVA. The national grid operates on 750 kV, 400 kV and 220 kV for transmission and 10 kV, 6 kV, 1 kV and 0,4 kV for distribution.

Structure of the Romanian market The Romanian electricity market is still undergoing significant changes with a view to converging with EU requirements. Unbundling, privatisation and the introduction of competition are likely to be the main focus of Romanian energy policy in the coming years.



The legal framework for the operation of the market was set out in the Electricity Law 318/20033, which follows the guidelines of the EU Electricity Directives.

According to the regulatory framework, the structure of the wholesale electricity market is divided into two segments:

• a regulated market, where the electricity transactions are settled based on regulated contracts with firm prices and quantities; and

• a competitive market, where the transactions are settled based on negotiated contracts and spot market prices.

The regulated, or captive, market is governed by regulated contracts and prices, which are the responsibility of ANRE.

The competitive market is ruled by bilateral contracts and transactions (biddings). These can be bilateral contracts between generators and suppliers to supply consumers outside the regulated market or import or export contracts, etc.

Power is generated by Hidroelectrica S.A. (hydroelectric power), Nuclearelectrica S.A. (nuclear power) and Termoelectriva S.A. (thermal power) as well as Electrocentrale Deva S.A., Electrocentrale Bucuresti S.A., Electrocentrale Rovinari S.A., Electrocentrale Turceni S.A., Electrocentrale Galati S.A. and Electrocentrale Craiova S.A. which are joint stock companies, set up through SC Termoelectrica S.A.

In 2002, Electrica S.A. responsible for distribution and supply has been reorganised, as it became a group of companies which includes 8 divisions for the supply and for the distribution of electric energy and 8 divisions for maintenance and for energy services.

The National Power Grid Company, Transelectrica S.A., is currently acting as the Transmission System Operator (TSO) of the entire Romanian power system. OPCOM, a legal subsidiary of Transelectrica plays the role of the market operator.

Energy Regulatory Authority The Romania Energy Regulatory Authority (ANRE) is a public autonomous legal body with the mission to create and implement the appropriate regulatory system. Its remit is to ensure the proper functioning of the sector and of the electricity and heat markets under conditions of efficiency, competition and transparency and consumer protection.

1.2.1.7 Macedonia


Generation Capacity About 80% of the demanded energy is provided through domestic production of electricity in thermal and hydro power plants. Macedonia has no oil or gas resources. Six large hydropower plants have been constructed and a new one was commissioned in September 2004. A number of small hydropower plants have been constructed as well, but the energy contribution of these plants is small.

Almost 90% of the annual energy generation is provided by three thermal power plants of which two are lignite-fired plants. These plants were commissioned in the 1980’s.

3 Romanian Parliament, Law no.318 regarding energy, Official Gazette of Romania, Section 1 no.511 / 16 July 2003.



The third plant was designed to burn heavy fuel oil but it can also use natural gas. In recent years, the plant has not been used due to the high fuel cost and lack of demand.

Transmission and Distribution The main transmission network of Macedonia consists of overhead transmission lines rated at 400 kV, 220 kV and 110 kV. There is also one 150 kV line used as a connection with Greece.

Structure of the Macedonian market The idea of privatizing the Macedonian electric energy company “Elektrostopanstvo na Makedonija” (ESM), dates back to 2001. The effort was cancelled in 2002, renewed in 2004, and resulted in the formation of four new companies in 2005: two generation companies (AD TEC Negotino and AD Elektrani na Makedonija – ELEM), a transmission company (AD MEPSO) and a distribution company (AD ESM).

One of the recent results from the privatization process is a new owner of the Macedonian distribution company. On the 16th of March 2006, Austrian EVN AG was proclaimed as the winner on the bidding process to buy the national electricity distribution company, AD ESM. At this moment EVN AG owns 70.1% of the distribution company’s shares. The remaining 19.9% of the shares belong to the European Bank of Reconstruction and Development (EBRD).

Elektrostopanstvo na Makedonija (AD ESM), performs the functions: distribution of electricity, distribution system operator, generation of electricity (distributed generation) and retail supplier for tariff customers – and has recently (March, 2006) been privatized with 90% by EVN – Austria.

The electricity framework is based on the Energy Law (“Official Gazette of the Republic of Macedonia No. 47/97 and 50/97).

Energy Regulatory Commission The Energy Regulatory Commission (ERC) regulates electricity and is financed by own funds provided by the payment of fee in the total income of the companies performing energy activities and from the payment of issued licenses. The ERC is not financed from the national budget.

1.2.1.8 Serbia


Generation capacity Serbia’s generation capacity is dominated by thermal power plants with 71% share, hydro power plants with 27% share and oil and gas units generating 2% form the rest of the generation mix. More than 90% of total supply with coal (mostly lignite) comes from Serbia’s own sources, and some75% of the total coal consumption is used for electricity production. Serbia depends on imports of oil and gas despite increased utilisation of local resources (large deposits of coal and hydro resources).

Transmission and Distribution Total transmission line lengths are: 1.562 km of 400 kV, 2.196 km of 220 kV and 6.465 km of 110 kV. Reliability of the electricity network has been improved, with decreasing losses. Transmission losses and power outages were reduced in electricity



transmission and 110 km of power lines were replaced, helping to stabilise the power network.

In 2004, after a 13-year break, the electric power system of Serbia was once again reconnected to the first synchronous zone of UCTE.

Structure of the Serbian market In 1991 a public enterprise – “PE Electric Power Industry of Serbia” (EPS) was established. During the NATO bombing in 1999 EPS’s electric power facilities suffered great damage. In 2005, the unbundling of PE EPS, separation of transmission activities and establishment of two autonomous public enterprises, PE Electric Power Industry of Serbia and PE Electric Power Network of Serbia, took place.

EPS now comprises of 11 legally independent subsidiaries- 4 generation companies, 1 generation/coal mining company, 5 distribution/ supply companies and one coal- mining company.

Based upon the Decision of the Government of the Republic of Serbia and according to the Energy Law, the Public Enterprise “Elektromreža Srbije” (EMS) started operations on 1st of July, 2005. The basic activities of EMS are: Transmission of electricity, system operation and organization of electricity market. EMS is Serbia’s Transmission System and Market Operator. It is 100% owned by the Republic of Serbia.

The “Economic Association for Electric Energy distribution” is the second part of EPS and also owned to 100% by the Republic of Serbia. The power distribution activity is performed in five Economic Associations: Elektrovojvodina plc, Elektrodistribucija Beograd plc, Elektrosrbija plc, ED Jugoistok plc, ED Centar plc.

Energy Regulatory Authority The “Energy Agency of the Republic of Serbia” (AERS) was founded by the Energy Law4 as a regulatory authority. AERS has jurisdiction in electricity, gas, oil and district heating sub- sectors. After legal establishment in June 2005, AERS became fully operational in January 2006.

1.2.1.9 Montenegro

Power Generation System in Montenegro

Generation Capacity Generation in Montenegro is dominated by hydropower with 59% generated by two hydro power plants (Perucica and Piva). The other 41% of the production come from one lignite-fired power plant (Pljevlja).

Despite large imports of electricity (about 40% of needed electricity are expected for 2007), Montenegro’s power sector still faces supply shortages. The shortages were caused by a continuing drought cutting the hydropower production combined with an increasing demand, This problem can only be solved with the construction of new power stations or by increasing imports.

4 The Law was published in the “Official Gazette of the RS” No.84/2004 of July 24, 2004



Transmission and Distribution The system consists of 400 kV lines, 220 kV lines, and 110 kV lines. Interconnections exist with Serbia on 400 kV and 220 kV lines, with Albania on 220 kV lines, and with Bosnia and Herzegovina on all three levels.

Structure of the Montenegrin market The energy sector in Montenegro is in urgent need of restructuring and investment following a decade of neglect. The state-owned power company Electro Distribution Company (EPCG) has faced mounting losses. The government aims to privatise EPCG, but steps must first be taken to restructure the enterprise.

EPCG is the functionally unbundled entity with four divisions responsible for generation, transmission, distribution and supply.

Competitive electricity market (based on bilateral contracts) is in the early stage of development. Until sufficient competition has been established, generation and supply will be regulated by ERA.

Energy Regulatory Authority The Energy Regulatory Agency of Montenegro (ERA) was established in January 2004 based on the legal framework of Energy Law 2003. Besides generation and supply, ERA establishes licence requirements and issues for transmission, distribution and wholesale trading.

1.2.2 Input assumptions to EurECA electricity price model

1.2.2.1 Updated GIS report

This section describes our input assumptions which are mostly based on those used in updated GIS report. For each of the key assumptions, we show High, Central and Low electricity price levels which correspond to the main price scenarios with the same names. We have sought to ensure that our scenario combinations are internally consistent: for example, high demand growth is likely to be coincident with high capacity growth (over an extended timeframe), as otherwise severe shortages would occur.

In 2006, the earlier REBIS GIS study was updated, that the updated report (17) serves as a basis to our analysis. As the original report, the updated GIS report calculates optimal generation portfolios under various scenarios. The scenarios calculated in the updated GIS report were the following:

1) Base case with official rehabilitation program,

2) Base case with “justified” rehabilitation program

3) High fuel price scenario

4) Low fuel price scenario

5) € 20/t carbon dioxide scenario



6) € 30/t carbon dioxide price scenario

7) High electricity import scenario

8) Hydro power plant with high fuel price scenario

9) Hydro power plant with € 20/ t carbon dioxide price scenario

10) Hydro power plant with € 30/t carbon dioxide scenario

The consortium selected the fifth scenario of the GIS report as a base scenario for the price analysis. The scenario selected is the fifth out of the total of ten scenarios in the updated GIS report, i.e. the one that describes the optimal generation park in a situation with:

• “justified” power plant rehabilitations in SEE (those which can be justified on the basis of screening curves) as per updated GIS report

• base fuel price scenarios as per updated GIS report

• carbon dioxide emission “cost” € 20/ton,

• no “forced” hydro plant construction.

This scenario was selected despite the fact the Kosovo is currently not a member of Kyoto Protocol, and lignite-fired power generation in Kosovo in not subject to EU emissions trade or taxation. It was felt that in a price model reaching to 2029 some kind of emission penalty had to be taken into account, so that the analysis does not become overly optimistic for lignite.

The EurEca pricing model was set to include the expected “justified” rehabilitation and the new generation park of this GIS scenario, as illustrated in Figure 1-26.



Figure 1-26 Optimal plant rehabilitation and construction timetables for scenario

5 in the updated GIS report (17)



1.2.2.2 Main price scenarios

Drawn up to be internally consistent, our price scenario combinations are designed so that they capture the full range of likely future wholesale prices, thus:

The High price scenario contains high fuel prices and high carbon prices, with a relatively low proportion of the new capacity being renewables.

The Central price scenario contains central views on all assumptions (based on updated GIS assumptions).

The Low price scenario combines low fuel prices and low carbon prices, with a relatively high proportion of the new capacity being renewables.

1.2.2.3 Underlying demand scenarios

Figure 1-27 shows our projections for total demand in the 9-country region. The projections are consistent with average growth rates of approximately 2.0%, 2.6% and 3.3% per annum in the Low, Central and High scenarios respectively of the updated GIS. Total demand rises from about 175 TWh in the year 2007 to 266 TWh, 317 TWh, and 388 TWh by 2030 in the Low, Central and High scenarios respectively. We assume the same new renewable build in all three scenarios.

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1.2.2.4 Resulting regional available capacity

Figure 1-28 compares regional available capacity by fuel type (at peak demand) and demand, for the High scenario. Capacity has been scaled back on the basis of availability at times of peak demand; for example, a station that has peak availability of 95% (due to a forced outage rate of 5%) has just 95% of its capacity shown in these figures. In Figure 1-29 and Figure 1-30 the category ‘other renewables’ is primarily wind, but also includes biomass and solar. Imports refer to the maximum possible import capacity at the time of regional peak demand. The capacity in the graphs is shown in approximate running cost order: plant such as renewables and nuclear with low running costs are at the bottom, followed by lignite, coal and gas. However, the cost order can change over time as fuel prices change and movements in the carbon price affect the relative economics of coal and gas.

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Figure 1-28 Regional capacity and demand in GW (High scenario) The capacity margin becomes relatively tight in the High scenario – which is consistent with upward pressure on prices. Note that the cost order of fuels is not constant, as implied by the graphs. For example, the graph suggests it would not be economic to generate electricity from gas until about 2017, whereas is fact interconnection constraints and variations in the gas/lignite price ratio mean there will be significant gas usage before 2017.



We forecast that most of the growth in new capacity will be CCGT plant, even in years when the running costs are more expensive than for coal or lignite. The all-in CCGT capital costs are roughly 60% of new coal plant capital costs; and hence the overall levelized cost of CCGTs is lower than the levelized cost of new coal.

Figure 1-29 shows the regional capacity and annual peak demand in our Central scenario. Compared with the High scenario, demand growth and total capacity are lower, although the capacity margin (the difference between available supply and peak demand) is higher. The peak demand crosses into the gas capacity region in about 2022.

Figure 1-30 shows the situation in the Low Scenario, which has a lower demand and capacity growth, but a slightly larger capacity margin. There is unlikely to be much generation from gas in many of the countries until the second half of the time-frame.

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Figure 1-29 Regional Capacity and demand in GW (Central scenario)

Source: ibid



Figure 1-30 Regional capacity and demand in GW (Low scenario) Source: Ibid

Figure 1-31 shows the capacity margin (percentage difference between total available capacity and peak demand) in all three scenarios. Again its hold be noted that these values have been calculated in using the average hydroelectric output, so the capacity margin with the full hydroelectric capacity will be significantly higher.

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Figure 1-31 Capacity margin in our three scenarios.

1.2.2.5 Assumptions on net transfer capacities

Figure 1-32, Figure 1-33 and Figure 1-34 illustrate the net transfer capacities between different countries used in our simulations in 2007 (the start year), 2018 (a mid year) and 2030 (the last year of our simulations). The 2007 figures are based on ETSO figures. Net Transfer capacities (NTC) are the (annually averaged) maximum possible flows, but the actual flows are decided by the EurEca model. In the short term, the small size of some of the net transfer capacities is likely to lead to substantial price differences between countries.

However, in later years we have modelled an increase in NTC, particularly interconnections involving Serbia, Albania and Macedonia, which is likely to lessen price differences. Also shown in Figure 1-32, Figure 1-33 and Figure 1-34 are total NTCs between the countries in this study and external countries. The external countries with the largest interconnection to the region are Greece and Hungary. Flows with external countries are included in our model, with Slovenia, Greece and Turkey modelled in the same level of detail as the other countries in this report, and interconnection with other countries modelled in lower detail.

As we have limited data on the NTCs between Serbia, Montenegro and Kosovo, we model interconnection between these countries as being effectively unlimited, indicated by n.r.l (no realistic limit) in Figure 1-32, Figure 1-33 and Figure 1-34. We assume electricity losses of 2% for all other interconnections.



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Figure 1-33 -Net Transfer Capacities in MW, in Year 2018 source: ETSOs, Pöyry projections



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Figure 1-34 - Net Transfer Capacities in MW, in Year 2030

Source: ETSOs, Pöyry projections



1.2.2.6 Underlying fuel price scenarios

Figure 1-35, Figure 1-36 and Figure 1-37 compare the different fuel prices in the Low, Central and High scenarios respectively. These fuel prices are ‘at the border’, inclusive of excise taxes (if applicable) but exclusive of inland transport costs to the individual power station. In our modelling, we have projected different fuel prices in different countries – but we show here the average fuel prices for the region as a whole5. The prices are presented on a net (Lower Heating Value or LHV) basis.

The price assumptions are based on both updated GIS and analysis by Pöyry. Even if the lignite price in Kosovo is relatively low, according to the mine feasibility study in the range of € 0,92/GJ, many other lignite mines in the SEE region do not achieve this level. In many EU countries, lignite price levels of € 2/GJ are common. However, such excavating cost differences between lignite deposits in SEE do not change the competitive position of the Kosovan deposits, which are, besides Kolubara deposits in Serbia, the most economical in the region.

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Figure 1-35 Regional average fuel prices in Low scenario

Source: REBIS GIS and Pöyry analysis

5 To produce an average which reflects the region as a whole for each fuel we calculate a weighted average, weighted by use of the fuel in each country in our simulations.



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Figure 1-36 - Regional Average Fuel Prices in Central Scenario

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Figure 1-37- Regional Average Fuel Prices in High Scenario Source: REBIS GIS and Pöyry projections



As the three figures show, our assumptions are that most of the change in fuel price will take place in the next few years. In the Low and Central scenarios, the gas price closely follows the oil price, whereas in the High scenario it is slightly higher.

In addition to fuel prices, we have assumed in our modelling that power prices are affected by carbon prices similar to those in the EU Emissions Trading Scheme.

• In all three scenarios we assume a carbon price of €1/tCO2 in 2007.

• In Phase 2 of the EU ETS from 2008-12, the price is

o €10/tonneCO2 in the Low Scenario,

o €20/tonneCO2 in the Central Scenario and

o €30/tonneCO2 in the High Scenario.

• From 2013 onwards we assume a price of

o €10/tonneCO2 in the Low Scenario,

o €20/tonneCO2 in the Central Scenario and

o €40/tonneCO2 in the High Scenario.

We do not assume that the carbon price is immediately passed through into power prices. Rather, pass-through occurs gradually, starting from zero and rising to 100% over time. Here, 100% refers to full opportunity cost pass-through (the level of pass-through is not reduced because some of the allowances are issued for free). 100% pass-through is assumed to reach in 2012 in Bulgaria and Romania; 2015 in Croatia and Montenegro; 2018 in Bosnia, Serbia, Macedonia and Kosovo; and 2020 in Albania.

The impact on electricity prices depends on four factors:

the carbon price in each year,

the level of pass-through in each year,

the carbon coefficient of the relevant fuel, and

the plant efficiency of the marginal (price-setting) generator.

The fuel price assumptions above are based either on updated GIS study or Pöyry fuel price scenario database. The latter fuel price scenarios are based on e.g. IEA analysis and are updated by Pöyry periodically. They are applied to e.g. pan-European price models.



1.2.2.7 Resulting regional electricity prices

Figure 1-36 shows the regionally averaged6 wholesale electricity prices from our price simulations. There is a much larger difference between the High and Central scenarios than between the Central and Low scenarios. There are three main reasons for this.

Our fuel price assumptions follow the same pattern (i.e. the REBIS GIS fuel prices have a much larger gap between High and Central than between Central and Low)

The difference between the carbon price in the Central and High scenarios after 2012 is €20/tonneCO2, whereas the difference between the Central and Low scenarios is only €10/tonneCO2.

The capacity margin is tighter in the High scenario, particularly in the later years of our simulation, meaning that more expensive plants must be run or more electricity must be imported from relatively expensive countries outside the region of this study.

Another observation is that in the Low scenario, the wholesale price finishes higher than the 2007 prediction, with an initial price decrease followed by an increase in the period 2012-21, and fairly steady prices thereafter. This is primarily due to the increasing pass-through of the EU ETS price, but also because more expensive plants need to be run to meet rising demand (see Figure 1-30)

Figure 1-38 - Regional Average Wholesale Electricity Prices

6 The Regional Wholesale Price in Figure 1-38 is calculated by taking the annually averaged wholesale price for each of the 9 countries covered in this report for each year of the simulation and then calculating a demand weighted average.

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There was little difference in trends in fuel use between scenarios. Consistent with our input assumptions concerning new plant building, there is a fall in the proportion of generation from lignite, and an increase in the proportion of generation from gas, with most of the increase happening by 2020. There is very little generation from oil. As we assume the same renewable build in all three scenarios, there is proportionately more renewable generation in the Low scenario and less is the High scenario.

The results show that even if the lower price range can be expected to be quite “firm”, and even resilient, the upside price range is wide and the market can be expected to be sensitive to factors that could push up electricity demand and electricity prices. Higher increases in demand, higher fuel prices and higher CO2 costs can be push the price higher. Slower capacity construction timetable and sudden demand peaks could push the price quite high at a very short notice.



1.3 Subtask 1.2 Potential Take-off opportunities

1.3.1 General assumptions on generation from new capacities (Kosovo C) For the time being, and in absence of final decisions on plant unit size, construction time-table etc, the following assumptions were made on the electricity available for sale from the plant:

a. total plant capacity will reach 2000 MW by 2018

b. plant availability would be 85% and operation at full capacity would be possible

c. available generation for sale would be 14,9 TWh at 2000 MW

d. scheduled maintenance of the plant would take place in the spring, when surplus hydro capacity would be available fro Albania and Montenegro as replacement capacity

As the expected power sales “portfolio” of Kosovo C seems to become complex and seasonally variable, it is recommended that the privatisation and financial advisor to the proposed transaction would develop a mathematical “portfolio” model on the electricity sales opportunities listed below, indicating sold capacity, sold energy and expected term of contract. This model would provide a presentation tool for potential investors, serve as negotiating tool and provide a basis for analysing power sales risk.

It should be noted that the foreseen sales “portfolio” described below is not in all cases based on direct queries to utilities and is subject to substantial variations.

The consortium members have limited themselves to a relatively general analysis to illustrate the market situation and have not entered into detailed discussions with potential buyers in order not to prejudice the power sales arrangements preferred by potential investors to the plant. For the same reason, we describe potential political support to power sales arrangements (public guarantees etc.) in very general terms.

1.3.2 General classification of customer base To characterise electricity sales opportunities available to eventual new lignite–fired power generation capacity in Kosovo, the following customer group categorisation was used:

1. customers in Kosovo:

• utilities

• industrial

• commercial 2. customers in directly neighbouring countries (one cross-border

transmission point)

• utilities

• industrial



3. customers in more remote areas (at least two cross-border transmission points)

4. customers outside SEE (Italy, Greece and Turkey)

5. eventual electricity exchange in SEE region and short-term contracts

The characterisation of potential customer base is especially difficult in SEE because the countries and the electricity market are undergoing tremendous change process in terms of political and economical development and adaptation to market economy. In addition, this analysis would need to be able to forecast the changing circumstances until the year 2009, when the financial close of the project is expected to incur.

I any case, it can be concluded that the future Kosovo C plant will not be a classical Independent Power Producer (IPP) in the sense that its output would be sold under a single long-term contract. Such contract would be also difficult to structure to take into account eventual regulatory change in SEE area.

With the above distribution of customers in mind, the expected 2000 MW total plant size, and the needs of neighbouring countries, especially those of Albania and Montenegro in mind, we venture to assume very tentatively that the sales portfolio of Kosovo C could be:

1) some 500-1000 MW reserved for use in Kosovo (assuming Kosovo B continues to operate)

2) some 900-1400 MW sold to neighbouring countries: utilities and industries

3) some 0-200 MW reserved for electricity exchange and short-term contracts

Percentage-wise, this would mean that some 80% of the power plant capacity could to be contracted from early on.

1.3.2.1 Potential types of long-term contracts for Kosovo C “Long-term contracts” for electricity can vary tremendously on the type of contract and pricing mechanism used. In the most classical meaning of this expression, it would mean a contract by which a single off-taker agrees to buy all of the electricity generated by the plant at a pre-agreed indexed price for a long period, e.g. 15 years. This is the type of contract that gives most comfort to investors and lenders to the plant, provided that the off-taker is considered reliable, trustworthy, and creditworthy. Long-term contracts like these are typical to highly regulated markets, many industrial CHP plants and publicly supported renewable power generators.

In practice, however, long-term contracts hardly ever resemble the above simple type. Long-term power sales contracts can be either

a. based on determined capacity or based on buyer’s dispatch orders

b. based on single price of combination of capacity payment and variable price

c. based on fixed price, indexed price of power exchange price is used as a reference price

d. interruptible or un-interruptible contract

Based on long-term experience from liberalising markets, it can be stated that classical long-term power sales contracts become atypical as the markets liberalise. In



deregulated markets, long-term contracts with longer terms than five years are quite rare, almost solely to be found in cases of industrial CHP plants and renewable plants. As the electricity markets in SEE move towards liberalisation, there is a risk that any long-term, fixed or indexed price contract concluded between Kosovo C and neighbouring utilities at this time might become a so-called “stranded contract” during the course of further deregulation and would not be competitive in the liberalised market. There is also a risk that potential investors in the neighbouring utilities to be privatised would also consider a long-term, sales contract a substantial risk factor.

However, it must be stated that the demand for the power generated by Kosovo C will be there, especially considering the competitiveness of the lignite deposits and the looming capacity crunch in SEE. However, the situation may require that Kosovo C contracts for power sales with shorter term contracts (e.g. five years), and essentially operates as “merchant plant” with higher commercial risk, but at the same time the plant would be able to take advantage of varying market situations.



1.3.3 Assessment of market opportunities

1.3.3.1 Assessment of market opportunities in Kosovo

As indicated in section 1.1, the local Kosovan maximum demand is expected to reach a level between 1377 MW (2020, MGS) and 1876 MW (2020, HGS) in the updated ESTAP demand forecast. Assuming that Kosovo B would continue operating, and priority given to local electricity supply to cover local demand, the Kosovo C plant would need to dedicate some 1000 MW of available capacity for use in the whole of Kosovo.

The analysis of section 1.1 also shows that the industrial demand in Kosovo is expected to reach a level of some 1,2 TWh by 2020. In comparison to plant available electricity, this amount is relatively minor in the larger picture of the capacity of Kosovo C.

The remainder of the expected demand level of Kosovo in 2020, expected to be between 6.2 TWh and 8.5 TWh in 2020, would come from residential and commercial demand. Kosovo C is not expected to deal directly with customers in this segment, but through electricity marketing utilities.

The Kosovan residential and commercial electricity demand is highly seasonal, with very low summer demand and high winter demand. The seasonality pattern is expected to be reduced somewhat with increasing air-conditioning demand for summer and better house insulation for houses reducing winter demand, but the high seasonality makes it difficult to Kosovo C to serve the local residential and commercial demand. If, as above, Kosovo C would dedicate 1000 MW for the service of Kosovo (continuous base load assumed 500 MW and seasonal additional demand in the winter 500 MW), the corresponding plant-load-factor would be only some 50% (taking generation by Kosovo B into account). However, the technical and commercial losses in the Kosovan high-voltage and distribution network are currently so high that the Kosovan market must be considered unattractive strictly from the investors’ point of view. Despite the forecasts of reducing technical loss levels and better payment discipline, the investors will probably need to structure their wholesale electricity contracts with Kosovan market in a way that allows them to avoid the risk of technical and commercial losses affecting the economical outcome of their investment.

As regards the Kosovan market, and in the light of estimated generation cost of Kosovo C, we expect the Kosovan residential and commercial market to be coverable with local electricity marketing utilities with the following contract structure with Kosovo C:

a) some 500 MW of interruptible, at least five-year contracts with local electricity marketing utilities to cover base demand

b) medium- and peak load demand contracts, estimated at 500 MW, seasonal, at least five-year contracts adjusted for the available capacities of Kosovo B and Kosovo C

c) Industrial demand contracts maximum 1,2 TWh (corresponding to some 200 MW of capacity)



1.3.3.2 Assessment of market opportunities in neighbouring countries

The utilities in the neighbouring countries provide a very multi-faceted market due to differences in regulation, degree of liberalisation and degree of privatisation of electricity markets. The following chapters describe the utility markets in neighbouring countries in general terms.

1.3.3.2.1 Albania

Albanian electricity market remains in transition. The current transition structure can be described in accordance with Figure 1-39. The market is undergoing a structural change in accordance with the Athens Treaty.

The Albanian installed capacity is currently around 1500 MW, with generation ca. 5 TWh.

Figure 1-39 Transitional structure of Albanian electricity market

The market structure provides Kosovo C with two opportunities: either to contract with national transmission operator, TSMO as independent producer (for the time being, in the Albanian power sector TSO handles power exports and imports), or in principle, to sell to distribution divisions of KESH.

Albania provides Kosovo C probably the most natural market, because the Albanian electricity system is dominated by highly seasonal hydro generation. The new high-voltage transmission line between the countries is expected to be commissioned in 2012, with a capacity of some 1000 MW.

The recent feasibility study by CESI on the feasibility of transmission between Albania and Kosovo, estimates that in 2020 Albania would import between 2,8 TWh and 4,8 TWh from Kosovo (additional scenario in competitive environment, difference



between the numbers based on power unit size in Kosovo). Together with assumptions of power line load factor, our assumption is that the sales from Kosovo would be between 500 MW and 800 MW (interruptible base load contract, with interruption for plant revision in the spring, and contract assumed to be “dispatchable”).

The Albanian market is important to Kosovo C as the likelihood of being able to secure very long-term power sales contract to Albania must be considered very high, and even 15-year contract should be considered possible with proper indexation. However, in this respect the picture of deregulation in Albania is somewhat confusing, because one would assume that these contracts could be signed with major Albanian distribution utilities or generation-KESH. A contract concluded with TSMO would have to be considered atypical of liberalised markets, because generally TSOs do not involve themselves in long-term power trade or take long-term positions in base load electricity supplies.

Based on the REBIS GIS reports, the prices Albanian utilities would be willing to pay would be the lower of prevailing power exchange prices and the price of oil-fired CCGT or coal-fired plant on Albanian coast. A reduction in price may be demanded by the Albanians to compensate for the long-term, nature of the contracts.

Because of the on-going restructuring process, non-payment problems with utility end customers and general economic difficulties, none of the Albanian major electricity entities can be considered by international standards to be a credible partner for long-term power sales contracts for international lenders. In the case of Albania, the starting point should be that eventual power sales contracts should be substantially supported, both economically and politically, by the Albanian state.

1.3.3.2.2 Montenegro

The electricity sector in Montenegro is undergoing restructuring as well, first as a result of Montenegro gaining independence, and second, the sector being unbundled. The same institutional uncertainty clouds electricity sales to Montenegro as to Albania with respect to proper contracting parties.

Montenegro is another hydro-dominated system in the immediate proximity of Kosovo, and there is sufficient transmission capacity between the countries. The availability of current data concerning power exchange with Montenegro is much more limited than in the case of Albania. The installed capacity in Montenegro is some 900 MW, and Montenegro imports some 1,5 TWh annually from Serbia. The term and price levels of power exchange contracts with Serbia are not known in detail, but the current power exchange contracts with Serbia are generally considered to be favourable to Montenegro. In Montenegro, the market remains strictly divided between the regulated sector and the liberalised sector, with a significant price difference between the two sectors.

In the future, the original REBIS GIS and the updated GIS studies indicate that Montenegro would continue its power imports to some 2 TWh in 2015, which is estimated to correspond an export potential of Kosovo C of some 200-300 MW of base capacity.



It should be possible to secure a long-term power export contract with Montenegro provided that the price does not exceed the lower of market exchange prices and entry price of either gas-fired or coal-fired plant on the coast of Montenegro.

It should be noted that about 1,9 TWh of Montenegran consumption is caused by an aluminium smelter, KAP Alluminio, which may be a sales target for Kosovo C in itself. The capacity of aluminium smelters to pay for electricity is based on world wide aluminium prices, and globally, aluminium industry tends to be located in regions where inexpensive hydro power is available in abundance. In this respect, the smelter may be at least a temporary customer for Kosovo C. Market information indicates that the most recent price KAP Alluminio has paid for its share of regulated power in Montenegro has been around € 20/ MWh (1100 GWh/a, SEETEC, Platts), and some €40/MWh on the open market (some 700 GWh). A long-term contract signed with an aluminium smelter will be difficult to achieve at reasonable prices, however, a price tied to aluminium prices may be feasible. The load profile of an aluminium smelter would be ideal for exports from Kosovo C.

In the same manner as in Albania, generous public sector support would be required for power sales contracts with utilities in Montenegro to make them credible for international lenders.

1.3.3.2.3 FYR Macedonia The Macedonian market is no exception with respect to ongoing deregulation and restructuring. The historically dominant utility, ESM, has been unbundled, but the electricity sector remains highly regulated. The transmission operator is MEPSO, who also deals with outside power suppliers for Macedonia for the time being. On the customer side, the market is strictly divided between regulated and deregulated markets.

The current installed capacity in Macedonia is ca. 1400 MW and annual consumption is ca 8 TWh. The system is thermally driven, with some 500 MW of highly seasonal hydro generation. During recent times, Macedonia has experienced electricity shortages as well, and the country imports some 1,6 TWh of power annually.

Based un updated GIS reports, Macedonia will continue its power imports from the current 1,6 TWh level up to some 2 TWh in 2015. This would correspond to some 200-300 MW of export potential for Kosovo C. The prices Macedonia would be willing to pay would be close to power exchange prices.

1.3.3.2.4 Serbia

The Serbian electricity market is dominated by the local utility EPS, which remains state-controlled and has undergone a process of unbundling. The current installed capacity of Serbia is some 7000 MW, and the electricity consumption has reached the level of 39 TWh. There is generous transmission capacity between Kosovo and Serbia. .

Serbia has extensive unharnessed lignite deposits in Kolubara, and plants intended to be built there are very competitive with planned Kosovo C. It must therefore be concluded that potential price Serbian utilities would be willing to pay would be quite close to generation costs of Kosovo C.



The industrial base of Serbia is well developed, as reflected in the number and consumption data of large industrial customers in section 1.3.5, and it should be possible to identify industrial customers with significant power loads. However, in this context in must be stated that the general economic adjustment of large industrial companies after the early 1990s is still ongoing in Serbia, and the long-term business prospects of potential industrial customers must be carefully weighed. Power exports to Serbia are expected to require political support to be acceptable to international lenders and investors.

At this point in time, Serbia exports significant amounts of power through Kosovan net to Greece.

1.3.3.3 Export countries requiring more than one cross-border transmission point

1.3.3.3.1 Romania

Romanian electricity market has already undergone major change as a result of earlier accession to EU. The markets basically follow the EU electricity and gas market directives, and an electricity exchange has been set up.

The Romanian distribution utilities have been privatised to larger European electricity utilities:

ENEL: Electrica Banat

Electrica Dobrogea

E-on: Electrica Moldova

CEZ: Electrica Oltenia

Privatisation postponed:

Electrica Muntenia

An already restructured, deregulated and privatised electricity industry must be considered an attractive sales target, provided that the transmission can be secured through grid controlled by Serbia. Especially the already privatised distribution utilities with strong international parent companies would be attractive off-takers. However, Romania is continuing its own expansion of power generation sector with construction of nuclear and lignite-fired plants. The markets must be considered very competitive and prices would probably have to be very close to expected market prices.

The Romanian industrial base has a high number of large industrial electricity consumers as indicated in section 1.3.5.

1.3.3.3.2 Bulgaria

From the point of view of Kosovo C, the Bulgarian market is equally attractive because of advanced regulatory environment. Distribution utilities have been privatised to E-on, EVN and CEZ. The same analysis as for Romania applies to Bulgaria as regards available transmission capacity, industrial buyers and available price levels.



1.3.3.3.3 Croatia

The Croatian dominant utility, HEP, has also been unbundled, and the Croatian market has given a liberalisation timetable. The future HEP-generation is expected to serve the regulated residential customers, while industrial customers would procure their power from traders and marketing utilities.

The electricity market liberalisation in Croatia is following the same liberalisation timetable as other SEE countries, with industrial market expected to be liberalised in 2008.

Readily suitable utility sales targets cannot be identified in Croatia besides the generation –HEP, but new traders and marketers serving industrial clients are expected to evolve.

Figure 1-40 Current structure of the Croatian electricity market

Croatian power system is based on nuclear and thermal generation, and future available prices are expected to follow power exchange prices of the region, or coal-fired generation costs on the Croatian coastline.



1.3.3.3.4 Bosnia-Herzegovina

The electricity sector of Bosnia-Herzegovina remains as fragmented as the political picture of the country. Politically, Kosovo C may be able to sell power to some geographical sectors of the country. The Bosnian power system has some 2000 MW of capacity, divided almost equally between hydro and thermal generation, with annual consumption of some 12,5 TWh.

The detailed analysis of power sales opportunities in Bosnia-Herzegovina would require a detailed analysis of available hydro capacity in politically favourable regions of Bosnia- Herzegovina, which is currently not available. For reasons of conservative estimate, no firm load number for this market is given.

1.3.3.4 Export opportunities to countries outside of SEE

The opportunity to sell power to Greece would require the negotiation of transmission rights to Greece, and export to Italy would require the completion of undersea cables across the Adriatic sea. Plenty of creditworthy and reliable off-takers would be available in these countries for power from Kosovo C.

Because these off-take contracts outside SEE would probably be a keystone in the setting up the of financial concept to Kosovo C and the potential investors may export the power to their own use in these countries, the consortium respectfully wishes to refrain from quantifying the export opportunities to Italy, Greece and Turkey.

1.3.3.5 Electricity exchanges

There are currently a number of electricity exchanges in the SEE region, as illustrated in Table 1-38.



Table 1-38 Recent electricity prices paid in power exchanges in SEE during 2006

Source: SEETEC report (18)

It can be concluded that for the time being there is no single prevailing power exchange price in SEE, mostly due to transmission constraints and regulatory barriers to cross-border transmission. The processes under Athens Treaty seek to unify these exchanges and establish one physical power exchange in SEE, but this development is in very early stages. The creation of financial markets is even further in the future.

It is generally accepted that power exchanges must have sufficient volume to achieve credibility, which allows power exchange prices to emerge as reliable reference prices both sellers and buyers are willing to accept as contractual basis. The Greek pool is a compulsory pool with a reliable price indicator, but e.g. the physical trade volume of the Romanian power exchange remains at 7% of the total consumption. Based on experience on other power exchanges around the world, it can be concluded that some 20% of the power should to be traded through the power exchange for the price quoted in the exchange to achieve the required credibility.

However, the electricity exchanges must be considered an attractive outlet for power from Kosovo C because of their flexibility, but the opportunity to hedge through financial contracts would also be required.



1.3.3.6 Summary of sales opportunities It is estimated that the potential for long-term utility type sales for power from Kosovo C could be estimated in accordance with Table 1-39-

Table 1-39 Total estimated utility sales potential from Kosovo C.

Country Energy demand TWh in 2015 Output level, MW

Albania 2,8-4,8 500-800

Macedonia 2,5 200-300

Montenegro 2,5 200-300

Kosovo, base load 3,7 500

Kosovo, seasonal <2 up to 500

Total 13,5-15,5 1400-1800



1.3.4 A. Assessment of market expansion opportunities if new and existing industrial plants eligible to participate in domestic and regional markets

The heavy, energy- intensive industries in SEE have undergone a major restructuring since the economic changes in the early 1990s. A significant amount of energy-intensive industry has been closed down in SEE and has been replaced by lighter, more labour-intensive industries. However, the most recent industrial production growth rates are quite high, and these growth rates are expected to continue.

Table 1-40 Industrial growth in SEE

Country Year: 2003 %

Year: 2004 %

Year: 2005 %

Year: 2006 %

Bulgaria 2,0 6,3 5,2 7,3 Romania 6,0 2,3 4,0 1,9 Bosnia and Herzegovina 7,0 5,5 5,5 5,5

Serbia 1,7 Kosovo Croatia 2,8 3,9 2,7 5,1 Albania 9,0 2,7 3,1 3,1 Macedonia 4,5 0,0 6,8 Montenegro 1,7

Source: (source: Index Mundi, www.indexmundi.com)

In accordance with Athens Treaty, SEE countries are making progress to deregulate the first tranches of their industrial customer base by 2008 at the latest (Serbia likely to miss this timetable). Typically, the line is drawn at 10 GWh/customer. The following table illustrates the liberalisation timetable in various SEE countries (from SEETEC project documentation):

Table 1-41 State of deregulation of industrial custom

ers in SEE

Studies to support the development of new

Novem

ber, 2007 generation capacities and related transm

ission

(95) Task1, Pow

er Market R

eview

European Agency for R

econstruction Pöyry-C

ESI-Terna-Decon

Studies to support the development of new April 25 , 2007 generation capacities and related transmission (95) Task1, Power Market Review

However, current eligibility criteria and the number of eligible customers are quite irrelevant to the development of new generation capacities in Kosovo, because almost all non-residential market is expected to be open by the time of 2012. At the same time the credibility of any industrial customer power sales contract, signed in 2009 for deliveries to commence in 2012, must not be considered very high because of ongoing economic changes in the SEE region.

To market to industrial clients, the owners of Kosovo C would need to set up their own marketing organisation, and by 2012, with the advancing market liberalisation, they should be able to contract industrial customers at prevailing power prices. With the exception of KAP Alluminio, customers over 100 GWh/a in SEE region are very few.

1.3.5 List of potential off-takers of regional utilities and industries

The above chapters have detailed the incumbent utilities and power exchanges which form the current sales potential for Kosovo C. In addition, the consortium has identified a list of potential industrial power customers, which will be delivered to EAR separately because of commercial confidentiality. Some summary numbers of this list, comprising 108 potential industrial clients, are presented in Table 1-42.

Table 1-42 Summary of identified industrial clients

Country Number of clients Total volume (‘) TWh

Albania n/a n/a Bulgaria 33 11.88. Croatia 21 6.50

Bosnia-Herzegovina n/a n/a Macedonia 5 1.70 Montenegro 1 1.90

Kosovo 12 0.57 Romania 20 9.52

Serbia 16 9.96 Total 108 42.03

The market study has allowed the consortium to obtain some data on price levels these customers are currently paying for electricity. It should carefully noted that these price also include grid charge, which makes the actual power prices quite low. very indicative price ranges are give in Table 1-43

These price ranges should be treated with considerable caution and considered only as indicative. Firstly, they do not necessarily link closely with power prices paid in regional power exchanges because of official and unofficial regulation through state-owned utilities, secondly, they are not reflective of true market conditions, as very little generation capacity in the SEE region has been privatised. Thirdly, there are also strict divisions between the regulated power prices and market prices in many countries.



Table 1-43 Observed industrial customer prices in SEE region (unofficial)

HV MV LV Country

€/MWh €/MWh €/MWh Bulgaria 25-30 30-32 41-43 Romania 23-28 28-31 40-43

Bosnia and Herzegovina 31-35 35-39 46-50

Serbia 34-37 37-41 50-55 Kosovo 30-34 35-38 48-51 Croazia 22-25 31-34 43-47 Albania 44-47 48-52 60-63 Macedonia 33-37 38-42 50-54 Montenegro 35-39 40-42 50-54

1.3.6 Summary of market study

As a summary of the market study, review of the most recent external reports, and earlier pre-feasibility study, we wish to reiterate the following:

1) The Kosovo C power plant should be a very competitive plant in the SEE region. 2) The demand for power is high in SEE, and capacity shortages are expected at least

in the medium run.

3) Because of

a. regulatory and political uncertainty

b. ongoing deregulation processes under Athens Treaty

c. existence of low regulated prices in most customer segments

d. state-controlled nature of market players

e. uncertainties related to Kosovo C development

f. likely privatisations of many utilities

g. risk of “stranded contracts” in deregulation and privatisation

h. uncertainties related to CO2 emissions after 2012 in SEE

the willingness of many utilities to enter into binding long-term power sales contracts must be considered quite limited at this point in time.

4) Potential investors may have to rely on a portfolio of shorter term power sales contracts and thus accept some risk typical of merchant power plants.



REFERENCES 1 - Brousseau & Scacciavillani: “Can Short Term Foreign Exchange Volatility be Predicted by the Global Hazard Index!” European Central Bank Working Paper No.66, June 2001, 2 - Corker, Rehm, Kostial, “KOSOVO Macroeconomic Issues and Fiscal Sustainability,” 2001 3 - Deutsche Bundesbank, “Exchange rate Statistics 2001” 4 - Development of Power Generation in the South Est Europe "Update of Generation Investment Study" 5 - Energy Sector Technical Assistance Project -(ESTAP) KOSOVO, a) Module A “ELECTRICITY DEMAND” Final Report b) KLM User Manual 6 - Federal Reserve Bank, Remarks by Chairman Alan Greenspan “Impact of energy on the

economy,” speech before the Economic Club of Chicago, Chicago, Illinois, June 28, 2001 7 - IMF - International Monetary Foundation:

IMF “World Economic Outlook 2001,” 2001 IMF “Kosovo – Macroeconomic Issues and Fiscal Sustainability” 2001

8 - KOSOVO Energy Sector: Heat Market Study 9 - OSCE

OSCE UNHCR, “Assessment of the Situation of Ethnic Minorities in Kosovo Oct. 2000-Feb. 2001,” March 2001 OSCE Mission Factsheet

10 - REBIS:GIS Volume 2 : Electricity Demand Forecast Volume 4 :Demand Appendices

11 -UNMIK: Central Fiscal Authority “A Macroeconomic Framework for Kosovo” 2001 Central Fiscal Authority “Special Report to Contributing Countries on 1999 Expenditures and Revenues from the Kosovo Consolidated Budget,” march 2000 Mike Ives, Budget Director CFA, “Kosovo Consolidated Budget 2001- Budget Instruction No. 1,” July 2001 Central Fiscal Authority, “Kosovo Consolidated Budget,” December 1999 Central Fiscal Authority, “Kosovo budget 2001,” December 2000 IDS University Montesqieu, Bordeaux, Demographic, social, Economic Situation and Reproductive Health in Kosovo following the 1999 Conflict, Nov.1999- Feb. 2000 Dep. Of Reconstruction, Partnership in Kosovo: Reconstruction 1999-2000 Dep. Of Reconstruction, Kosovo: Reconstruction 2000, April 2000 Dep. Of Reconstruction, Kosovo 2001-2003 – from Reconstruction to Growth Care International UK& Inter-Agency Sub-Group and Poverty Assessment Team, “Preliminary Findings of the Quantitative Poverty Assessment Team,” November 2000 CESIR_KfW – STEAG Consortium “Financial Cooperation with Kosovo Region – Feasibility Study Electricity Supply for Kosovo, Final Report” November 2000

12 - Vladimir Gligorov “Kosovo Economicus – Does viability matter?” Dec. 1999 13 - World Bank

World Bank Report No. 21784-Kos: “Economic and Social Reforms for Peace and Reconciliation” 2001 World Bank Publication “World Development Indicators,” 2001 World Bank Publication “Global Economic Prospects and the developing countries,” 2001 World Bank Publication “Global Development Finance 2000,” 2000

14 - UNPOP Population UN Population Division, World Population Prospects - The 2000 Revision, February 2001



15 Energy Sector Heat Market Study ELC-Electroconsult / ERM Pristina 2007

16. First draft of the report “Economic and Technical feasibility of rehabilitation of units of Kosovo A power plant”, by consortium A3I, detailing the rehabilitation plans for Kosovo A

17 Update of generation investment study, Report by the World Bank Group , contract no 713 8967, by South East Europe Consultants, Belgrade, 2007 Summary report and Main report)

18. Study of the obstacles to trade and compatibility of market rules, Southeastern Europe Electrical System Technical Support Project by SEETEC consortium, Regional Activity REM-1202, 014551-REM-1202-47RA-I-0001-01, prepared by SNC-Lavalin Inc. (SEETEC report)

tpp task 1 final report

Documents

market analysis

task report

reconstruction pyrycesi

consortium members

related transmission

reference year

kosovo b

electricity demand data