kosovo ipp study 2006

60R05429.01-Q070-009 February 6, 2006

European Agency for Reconstruction

Contract nr 04KOS01/03/009, Lot 1

Pre-feasibility study for the new lignite fired power plant

Executive summary

Draft final

Lot 1, Executive summary February 6, 2006 (7)

Table of content

1 INTRODUCTION..............................................................................................................3

2 SIBOVC LIGNITE ............................................................................................................3

3 SOUTH EAST EUROPEAN (SEE) ELECTRICITY MARKETS AND NEW TPP 3

4 NEW THERMAL POWER PLANT................................................................................4

4.1 Power plant site ....................................................................................................................4 4.2 Power plant concept and applied technology.......................................................................5 4.3 Economic and financial performance...................................................................................5 4.4 Legal and regulatory changes...............................................................................................7

5 RECOMMENDED ACTIONS..........................................................................................7


1 INTRODUCTION

Kosovo has ample lignite resources and their utilization for large scale thermal power generation has been envisaged in the regional electricity generation plans. The recently published Kosovar energy strategy outlines the same. Electrowatt-Ekono Oy, Finland has conducted a prefeasibility study on a new thermal power plant based on the Sibovc lignite field. That is planned to be developed next after the exhausting current mines of Bardhi and Mirash. This study is financed by the European Agency for Reconstruction, EAR. It has been assumed that a foreign investor or investor group will have a leading role in the mine and power plant development as the Kosovar financial resources as scare.

2 SIBOVC LIGNITE The Sibovc field contains some 840 million tons of lignite Some 200 million tons of that is planned to be reserved for the supply of the existing power plants of Kosovo A and B. That mine will be a continuation of Bardhi in the southwestern corner of the new field. A feasibility study on the mine development was con-ducted in 2004 by Vattenfall. It concluded that the cost of lignite fuel available from the new mine is one of the lowest ones in whole Europe making power gen-eration on the Kosovar lignite very attractive. The remaining lignite resource of approximately 650 million tons would make possible to build a 2000 MW power plant. The mine could furnish the plant at its full load for its whole lifetime of 40 years. It has been assumed that the investor will develop its mining operations in-dependently of the KEK mine.

3 SOUTH EAST EUROPEAN (SEE) ELECTRICITY MARKETS AND NEW TPP Even if there is currently no functioning electricity market in the SEE region and no third party access, some conclusions on the future electricity market and the competitiveness of the power generated from lignite in Kosovo can be drawn. The prefeasibility study concludes that the variable cost of new power plant in Kosovo would be in a range of € 10-12 /MWh. This compares well with the sys-tem marginal prices of the SEE market estimated in the REBIS GIS report, where even the lowest system marginal prices are around € 17/ MWh in case of low de-mand growth and ample rainfall. This illustrates the high competitiveness of the lignite deposits in Kosovo. In other cases of the REBIS GIS study, the estimated system marginal prices, which could also be interpreted as absolute minimum open market prices, remain well over € 20 / MWh. The current recorded market prices are 40 € /MWh and over.


The current electricity generating capacity of Kosovo is highly dependent on the Kosovo A units, which are in relatively poor condition, and in any case are not expected to operate beyond 2016 because of new EU emission regulations. The first new unit of any capacity increase can be considered to meet the domestic Kosovar electricity demand, and only later units could dedicate most of their gen-eration to export markets.

4 NEW THERMAL POWER PLANT The study has analyzed two alternative unit capacities namely 300 and 500 MW. It is assumed that the new plant will be able to operate at its full load i.e. base load at all market conditions. The Consultant has assumed that the plant will be built in two phases i.e. 900-1000 MW in the first phase (3 x 300 MW or 2 x 500 MW), the first units running by 2012-2014 and the second phase (4 x 300 MW alternatively 2 x 600 MW or 2 x 500 MW) would start when the first phase has demonstrated its ability to generate power and sell it to the market. The whole 2000 MW could be completed by 2018-2020.

4.1 Power plant site Large scale lignite utilization has to take place close to the mine as it has low calorific value per weight and results in high transportation cost. A so called “mine mouth plant” with belt conveyors will be used for its haulage up to the plant. Additionally a site for correctly dumping ash from the operation has to be found. The 650 million tons of lignite will gradually be converted into 600 TWh electricity and 100 million tons of ash over 40 years of operation. Three potential sites around the Sibovc field has been analyzed in details: Kosovo B, Bivolak and the valley north of Grabovc on the western side of the field. All those sites are within 3 kilometres from the field and can be used. The Consultant recommends Kosovo B site provided that sufficient assurances can be given to the foreign investor that he will not be liable of any existing contamination of the site. The 15 million ton ash pile aside the Kosovo B plant has to be removed to make space for the new reserve lignite yard at the site. The cost of removal has been estimated at 52 million EUR. The site in Grabovc would offer a less visible site and in the future shorter trans-portation distance of lignite as it is assumed that following lignite mines after Si-bovc will be in the south.


4.2 Power plant concept and applied technology The new plant will apply the latest well proven steam power plant technology available for lignite firing. Its pollution control methods will be as the current EU rules call for. For combustion of the lignite in 300 MW units the modern Circu-lated Fluidized Bed (CFB) technology can be used. As the fuel contains lime-stone, desulphurization takes place during the actual combustion process in the boiler and very low sulphurdioxide (SO2) emissions can be expected. In the case of 500 MW units more conventional pulverized firing (PF) is used and there a separate desulphurization plant is required to meet the same emission limit. Addi-tional investigation is recommended to identify the most economical method for desulphurization. The pulverized firing concept is also calculated for the 300 MW plant for comparison purposes. Both combustion processes can meet the given ni-trogen oxide (NOx) emissions. The plant cleans its flue gases from dust in the electrostatic precipitators. Thereafter the flue gases are planned to be taken into the large cooling tower and mixed with the exiting water vapour of the tower i.e. the highly visible stack is eliminated. The plant is estimated to have an overall efficiency of 40 %. In the case of apply-ing CFB combustion technology for the 300 MW plant its efficiency will be 1-1,5 percentage points less as subcritical steam parameters would be used. There are no proven references for supercritical parameters with CFB-boilers. The exact ef-ficiency figures will depend on the final plant design taking into consideration also of the possible impacts of the Kyoto protocol for Kosovo and the plant inves-tor. The plant itself is estimated to employ directly 200-300 persons in the first phase operation and the second phase would basically double that number. Additionally the plant will use a lot of external services for its maintenance. The mining opera-tion for the plant will employ more than 1000 persons.

4.3 Economic and financial performance The new thermal power plant is estimated to cost € 1,1-1,3 billion in the first phase plus the development cost of the mine estimated at € 300 million. The sec-ond phase is approximately 10 % less expensive. Building two 300 MW units into one 600 MW plant in the second phase saves an additional 15%. The plant operat-ing cost by using € 4/ton direct lignite mining expenditure is estimated as follows: Plant type & size Operating cost excl. capital €/MWh 300 MW CFB 10,26

500 MW PF 10,46 300 MW PF 10,72


The financial evaluation assumed the following input data: Interest on cash assets 10,0 % Energy market price 40 EUR/MWh Tax rate 20,0 % Corporate tax in Kosovo Depreciation 5 % annually Amortization period 9,5 years Rest value 20 % of total investment Inflation 4 % Debt/Equity Ratio 70/30 Return on equity 20 % (required minimum) Interest on debt 10,0 % Lignite Fee 3,00 EUR/MWh Dividends max ROE (from retained earnings)

The power plant would be profitable at the assumed market price using any of the technical options. The CFB plant and the large PF plant are largely equal in NPV calculations, with more advantage to the large PF plant, shorter the calculation period. Debt repayment within 10 years from the start of construction of each unit is fea-sible. A sensitivity analysis indicates that the plant would be very profitable using any of the technical options if the electricity sales price goes up to € 60/MWh, and make a loss (after financing costs, also all technical options) if the price is at 20 EUR/MWh. Regarding to economic benefits of the new power plant to the Kosovar economy the construction of the new mine and power plant will bring approximately € 60 million of foreign money every year over the ten year development time. When the fully built 2000 MW plant is in operation, its turnover is around € 600 million (€ 40/MWh sales price and 15 TWh/a). One quarter i.e. 25 % of that revenue is estimated to benefit directly the Kosovar economy as follows: Revenue item Estimated value € mil-lions/a Salaries, mine & plant 25 Maintenance services 25 Ash & water fees 10 TSO electricity transfer fee 30 Lignite fee 48 Land lease 2 Corporate tax 10 Grand total to Kosovo 150


It has also to be noted that the plant revenue is mostly from the export sales i.e. fresh new funds into the Kosovar economy. PSIG can directly benefit with the lignite fee as that will be paid for the utilization of the Kosovar mineral resources. That fee is proposed to be the selection criteria for the foreign investor. The high-est bid (e per ton) should win. In this estimate it is assumed to be € 3 per ton.

4.4 Legal and regulatory changes Fair and fast selection of the foreign investor or investor group is of utmost im-portance as that process involves two typically different sectors namely mining and power generation. In this case the mine would serve the power plant only and the power plant would not have any other commercially viable options to acquire its fuel. The revenue for the project comes from the electricity exports and the revenue to PSIG would come through lignite concession fees/royalties. There is no competitive transfer pricing between the mine and power plant i.e. the bidding process is recommended to be integrated and simultaneous. A body for this selec-tion process should be established and the EU rules in that tendering process have to be followed.

The current energy, environmental and tax laws should be reviewed to make that kind of approach possible. Foreign investor wants to have a clean sites from the past legacy and clear land ownership/lease contracts.

5 RECOMMENDED ACTIONS One of the most urgent actions is to get the Sibovc mine development moving al-though the foreign investor should decide itself where and how to do it. The time required to vacate the land for construction and develop the mine up to the point where lignite is delivered to the power plant is longer than the time for the power generation. Resettlement of the area for the mine development around the Sibovc village should be started immediately.

As there are mining and power generation parts in the development scheme and they have separate licensing bodies (ERO and ICMM) there should be a unifying system/organization to integrate and conduct the tendering process. The best thing would be “one window at the government for the Sibovc development”.

The depositing of ashes from the power generation needs a permanent and envi-ronmentally sound solution. The foreign investor should not be forced to get in-volved in the past neglects or potential liabilities arising from depositing the ash into the old mines. In this respect the most convenient solution is that there will be an entity taking care of the all the ashes coming from the power plants against a ash handling fee. The fee will cover the transportation, handling and recultiva-tion costs and possibly generate some surplus to make gradually clean and recul-tivate the abandoned ash or overburden piles.

60R05429.01-Q070-002

February 6, 2006

European Agency for Reconstruction Contract nr 04KOS01/03/009

Pre-feasibility studies for the new lignite fired power plant and for pollution mitigation measures at Kosovo B power plant

Lot 1, Task 1 Background review/market assessment

Draft Final

Lot 1, Task 1 February 6, 2006 Background review/market assessment Page 2 (28)

Contents 1 BACKGROUND REVIEW/MARKET ASSESSMENT ........................................................4

1.1 Introduction..........................................................................................................................4 2 SUMMARY OF ASSUMPTIONS IN REBIS GIS STUDY...................................................5 3 DESCRIPTION OF CURRENT MARKET SITUATION IN KOSOVO ............................6 4 FUTURE MARKET OUTLOOK FOR KOSOVO ................................................................7 5 DEMAND FORECASTS IN KOSOVO...................................................................................8 6 REGIONAL ELECTRICITY DEMAND AND SUPPLY FORECASTS...........................11

6.1 General UCTE view...........................................................................................................11 6.2 REBIS GIS view ................................................................................................................12

7 GRID CONNECTIONS TO NEIGHBOURING COUNTRIES .........................................14 8 REGULATION OF GRID STABILITY IN KOSOVO .......................................................17 9 POWER EXCHANGE WITH ALBANIA.............................................................................19 10 EXPECTED SYSTEM MARGINAL PRICE SCENARIOS...............................................20 11 EXPECTED COMPETITIVENESS OF NEW TPP ............................................................21 12 EVENTUAL ELECTRICITY EXPORT FORECASTS......................................................21

12.1 New 300 MW units ............................................................................................................23 12.2 New 500 MW units ............................................................................................................24

13 ORGANISATIONAL AND OPERATIONAL STRATEGY FOR NEW TPP ..................26 13.1 Recommendations by ESTAP II, policy report .................................................................26 13.2 Timetable for tendering process.........................................................................................26 13.3 New investor requirements and operational strategy of the plant......................................27


Figures Figure 5.1. Comparison of ESTAP I and REBIS GIS power demand estimates. 9 Figure 7.1 Current power interconnections around Kosovo 15 Figure 7.2 Average transmission capacity between Serbia and Kosovo 2000-2004 16 Figure 7.3 Average transmission capacity between FYROM and Kosovo 2000-2004. 16 Figure 7.4 Average transmission capacity between Macedonia and Kosovo 2000-2004. 16 Figure 7.5 Year 2015 annual energy exchanges 17 Tables Table 5.1. Forecasts for Kosovan power demand in various reports and studies. 10 Table 5.2. Sensitivity analysis for new power generation capacity in Kosovo in the REBIS GIS

study. 11 Table 6.1. Estimate of combined cycle capacity needed in countries neighbouring Kosovo by the

year 2015 in REBIS GIS study scenario A (isolated markets). 13 Table 10.1. Expected system marginal prices in REBIS GIS study scenario B (liberalised market),

includes medium demand scenario 20 Table 12.1. Power imports required for Kosovo in 2005-2011. 22 Table 12.2. Estimated power exports when the first new TPP unit is 300 MW. 23 Table 12.3. Estimated power exports when the second new TPP unit is 300 MW. 24 Table 12.4. Estimated power exports when the third new TPP unit is 300 MW 24 Table 12.5. Power export in case the first new TPP would be 500 MW in size. 25 Table 12.6 25


1 BACKGROUND REVIEW/MARKET ASSESSMENT

1.1 Introduction

As part of Lot 1, Pre-feasibility study for a new lignite-fired TPP in Kosovo, the Consultant has

• Reviewed existing studies concerning the electricity demand in the region • Assessed the medium and long-term electricity market prospects of the new

TPP • Outlined an organisational and operational strategy for the development of the

new plant • Developed a set of electricity supply scenarios which will be taken into account

in economic and financial analysis of the new TPP • Assessed the firm export potential of the proposed new TPP • Developed a set of system marginal price scenarios for the new plant (or a set

of contract price scenarios with each of the prospect markets assessed For purposes of this study, the following reports have been reviewed in detail and taken into account in developing the required outputs:

1) ESTAP I a. Module A, Electricity Demand b. Module B, Generation Plan c. Module C, Transmission

2) REBIS GIS Study for the regional least cost power generation investment plan

for SEE

3) Interim draft of refurbishment plan for Kosovo A

4) Feasibility study for Kosovo-Albania 400 KV transmission interconnection project

5) Energy strategy for Kosovo 2005-2015 by the Ministry of Energy and Mining

(draft)

6) UCTE system adequacy forecast for the region, January 2005

7) ESTAP II: review of the Policy, Legal, Regulatory, and Institutional Framework for Private Sector Participation in the Energy Sector in Kosovo, IPA Energy Consulting and Norton Rose, March 2005


In addition, interviews have been conducted with personnel of the Ministry of Energy and Mining and the generation and transmission department of KEK. The feasibility study of the HPP Zhur was not available to the Consultant, but its eventual effects on the power generation situation are considered minor. At the same time, the completion of Zhur would be feasible only after the estimated date for commissioning of the new TPP, i.e. after 2013. The Consultant has sought to locate any reports that would have forecasted price development in the planned electricity trading area of SEE in future trading arrangements, but despite best efforts such publicly available forecasts could not be located.

2 SUMMARY OF ASSUMPTIONS IN REBIS GIS STUDY

During the early part of 2005, a regional study on the power plant expansion in SEE was finalized by a consortium of consultants (REBIS GIS study). The study discusses the whole electricity market in SEE, develops an overall least cost generation plan for the region, and provides an excellent base of evaluating the planned power plant investments in the region. However, with respect to the source data utilised for UNMIK, the REBIS study assumes developments that do not necessarily reflect the latest plans by MEM, e.g. the REBIS study assumes that Kosovo A plants would be retired in 2010 and that new capacity would be already available in 2010. The REBIS GIS study utilises classic merit order approach based on variable costs of operation and screening curves for power plant projects, and in applying this methodology the REBIS GIS study might differ to a certain extent from the commercial decisions to be made by market actors on in the future. Relying on the perceived competitiveness of a power plant on the basis of a merit order study is methodologically somewhat questionable when the generation market is expected to be opened, but in the absence of market price simulation of the SEE electricity market, the REBIS study must be considered as most reliable estimate. The value of the REBIS study lies in its geographical reach and in the treatment of SEE as one single market. In comparison to the other power plant concepts listed to be constructed in the future by neighbouring countries, it can be concluded that Kosovo lignite-fired power plant concepts came very close to the top of most economical power plants in the region, preceded only by the Belene nuclear unit, Cernavoda nuclear units, and Kolubara lignite-fired units in Serbia. The expected competitiveness of the Kosovo lignite fired power plants in the REBIS GIS study vis-à-vis planned CCGT units is further strengthened by the natural gas price assumptions made in the REBIS GIS study. The Consultant considers these


natural gas price forecasts quite conservative in light of recent oil price hikes and the widely shared current future outlook on crude prices in the future. The REBIS GIS study assumes that all Kosovo A units would be decommissioned in 2010, which is not the case in the light of most recent plans by KEK and MEM. A study on the rehabilitation of Kosovo A units 3, 4, 5 has been ordered, and the current expectation is that some of units would be operated until 2016 when their further operation is expected to be disallowed or severely restricted by new EU environmental directives. In any case, the Kosovo A units have to be operated until the commissioning of new generation capacity in Kosovo, if not longer, but their operation after 2016 is not expected. In this respect, the market prospects resulting from the REBIS GIS study for the new Kosovan units are somewhat less optimistic than assumed in the REGIS GIS study. There are three main scenarios the REBIS GIS study:

A. Electricity generation for local markets only (medium load scenario) B. Electricity generation for regional market, i.e. no transmission constraints

assumed (medium load scenario, many rehabilitation scenarios) C. Scenario B, but known transmission constraints included , various sensitivity

analyses included The scenario A is of no interest to the pre-feasibility study of the new TPP because of its local nature. Of more interest are the scenarios B and C. As regards to Kosovo, the REBIS GIS study makes the following assumptions on the future of currently available Kosovo A and Kosovo B power plants:

• Kosovo unit A1 to be retired in 2006 • Kosovo A units 3-5 units discontinue operation in 2010, they would not be

refurbished • Kosovo B units continue operation until 2020

KEK currently expects to refurbish units Kosovo A 3-5, but considering the extent of the REBIS GIS study the effects of this refurbishment to the overall demand picture in SEE can be considered negligible, especially with respect to results calculated for the whole region, e.g. system margin prices. Because the potential refurbishment Kosovo A units 3-5 was not included in the comparison of various refurbishment schemes in the SEE region in the REBIS GIS study, it is unfortunately difficult to estimate how well these refurbishment projects would compare with the other refurbishment projects in the SEE region.

3 DESCRIPTION OF CURRENT MARKET SITUATION IN KOSOVO

The current electricity market in Kosovo is organisationally, technically and commercially recovering from recent time of conflicts. The Kosovan electricity system


is in transition towards a market-driven commercial environment with well defined development goals agreed in the Athens protocol of 2001. The challenge is to manage the organisational transition while simultaneously improving the technical performance and customer service of the Kosovan power system. The electricity enterprise of Kosovo, KEK, is undergoing a deep transformation and unbundling process. The grid operations will be separated and formed to an independent TSO, while electricity generation (i.e. Kosovo A and Kosovo B) will be managed in another entity. The neighbouring areas are undergoing a similar transition, and the development of new TPP power plant project will take place under significant regulatory and organisational transition and uncertainty. In 2005, the Kosovan power system is expected to deliver some 4300 GWh to the Kosovan power grid, of which some 3800 GWh is expected to be generated by the two power plants in Kosovo, Kosovo A and Kosovo B (MEM strategy paper) The minimum demand in the Kosovan grid during 2005 has been some 250 MW, while the highest registered demand has been 908 MW in February 2005. The amount of electricity fed to the Kosovan grid, 4300 GWh in 2005, does not account for the amount of electricity that would have been consumed if the load shedding and other power outages at the customers’ consumption points could have been avoided. Despite the best efforts of KEK, the electricity customers of Kosovo are facing interruptions in supply. These are due to insufficient grid stability arrangements to counter unexpected outages in Kosovo A and Kosovo B, insufficient availability of imported power, financial deficit of KEK caused by the high level of technical and commercial losses in the grid, and high non-collection ratio of electricity invoiced. The crucial problem in the development of the electricity sector in Kosovo is that currently only some 30% of electricity sent to the main grid is actually paid for by the end customers, which leads to a significant financial resource problem in KEK and poses a tremendous challenge for the development and financing of new power plants in Kosovo.

4 FUTURE MARKET OUTLOOK FOR KOSOVO

On behalf of Kosovo, UNMIK has signed the so-called Athens memorandum, where the countries of SEE have committed themselves to creating a free electricity market. In the Athens Memorandum, the SEE countries have further committed themselves to unbundling of generation and transmission, the creation of independent TSOs and liberalising the generation market by January 1st, 2008. Kosovo Trust Agency, UNMIK and SIPG have taken initial steps to implement the reforms in Kosovo, and neighbouring countries are expected to undertake similar reforms. There are plans to reduce the grid losses gradually in Kosovo, but the strong demand growth will require that Kosovo will need to import significant amounts of power until the new TPP can be commissioned. This will put another burden on the financial situation of KEK and its eventual successor companies, and the problem of non-


collection of electricity bills would have to be addressed effectively. A success in improving the financial position of those KEK successor companies would also assist the financing of the new TPP unit. As the analysis will show later in this report, the Kosovan economy would benefit from power market liberalisation and cross-border trade in electricity. Especially in the early years until 2015, Kosovo would benefit from the establishment of a power exchange in SEE, because this would enable the marketing of non-firm power supplies in a cost-effective way.

5 DEMAND FORECASTS IN KOSOVO

The electricity demand of Kosovo has been estimated in a number of reports and studies, the most important ones being

• ESTAP I module A, and this study remains the best available with respect to the analysis of the structure of the demand (residential, commercial, industrial). However, the demand forecasts of ESTAP I have already been exceeded by the actual demand in 2005, and it has remained unclear to REBIS GIS study team whether the shed load had been added back the actual demand in ESTAP I module A report. T

• The REBIS GIS study adds back the load that is currently shed in the Kosovan power system, and also includes that eventual restart of the Trepca mine and Feronickel metallurgical plant with an estimated annual demand of 124 MW and 1310 GWh from the year 2007 onwards.

• A demand scenario has also been developed for the refurbishment report of Kosovo A plants

• The feasibility study of the 400-kV interconnection between Kosovo and Albania has a demand scenario for Kosovo built in the study.

The demand forecasts of the REBIS GIS study are based on national economic criteria, GDP growth and energy intensity rather than on the structural analysis of demand as in ESTAP I Module A. This fact is illustrated in the comparison graph of REBIS GIS study for Kosovo: (REBIS GIS report, volume 2, page 39)


Figure 5.1. Comparison of ESTAP I and REBIS GIS power demand estimates.

In discussions with the representatives of the Ministry of Energy and Mining, it was agreed that the medium demand scenario (case 2) of REGIS GIS study for Kosovo most closely resembles the current view of the market development. In a similar manner, the reduction profiles for technical and commercial losses were considered to be representative of the actual. The low demand scenario (case 1) of REBIS study for Kosovo was considered unrealistic by MEM representatives and the Consultant in the light of most recent demand growth of 8% from 2004 to 2005. The results of the REBIS GIS study have obviously not been available to the consulting team responsible for the planning of the refurbishment of Kosovo A. This team has developed a view of the demand based on ESTAP I which excludes the shed load, and the demand forecast thus developed underestimates the demand. The refurbishment of Kosovo A would appear less economical under such underestimated overall demand scenario. The following table summarizes the demand figures utilised in various studies and reports:


Demand scenario 2005,

GWh 2010, GWh

2015, GWh

2020, GWh

ESTAP I medium growth scenario

3586 4272 5137 n/a

ESTAP I high growth h scenario

3769 4988 6519 n/a

REBIS GIS case 2, medium growth

6019 6735 7050 7800

REBIS GIS case 3, high growth 5985 7064 7894 9375 Kosovo A refurbishment = medium growth scenario (6%/a)

4296 5613 7511 n/a

Kosovo-Albania interconnection study

5420 6689 7069

REBIS GIS case 2 without Trepca and Feronickel

4999 5425 5740 6490

REBIS GIS case 3 without Trepca and Feronickel

4965 5754 6584 8065

Table 5.1. Forecasts for Kosovan power demand in various reports and studies.

The scenarios for Kosovan power demand to be used for the evaluation of the economics of the new TPP will be the following:

A. REGIS GIS medium demand scenario for Kosovo B. REGIS GIS high demand scenario for Kosovo C. REGIS GIS demand scenario with no additional industrial load from metals

industry In scenario A, independent market simulation, the REBIS GIS study assumes that there would be “some “ power deficit in Kosovo between 2005 and 2010, and recommends 135 MW of lignite-fired capacity to be built between 2005 and 2010. However, this size of plant is hardly economical, and the same result is likely to be achieved by rehabilitating Kosovo A units 3-5. For period 2011-2015, the study recommends 600 MW of lignite-fired capacity (to replace Kosovo A units, as assumed), and for period 2016-2020 the study recommends one 135 MW lignite-fired unit. In scenario B, (conservative rehabilitation scenario 2A2, same as rehabilitation scenario 2B) the whole regional investment picture changes: the plan for Kosovo would be 300 MW of lignite-fired capacity between 2005 and 2010 (sic!), 1600 MW in 2011-2015 and 1800 MW again in 2016-2020. The combined cycle power plants become generic and are not located in any specific country any more. This plan adds up to 3700 MW of lignite-fired capacity in Kosovo before the year 2020, 2600 MW in excess of what scenario A required for Kosovo. It is unlikely that Kosovo would be able to meet the construction target of 300 MW before 2010, even the combined target of 1900 MW by 2015 is challenging. However, it is the view of the Consultant that this


delay in construction from the ideal timetable will not be hindrance in securing the export market, provided that the variable cost of operation in the new TPP remains reasonably low. In scenario C of the REBIS GIS study, many sensitivity analyses are run against the scenario B, and various transmission constraints are taken into account. The regional low and high demand scenarios are of importance, as well as some intensive hydro generation scenarios. The outcome of these sensitivity analyses are described in the following table:

A 500 MW lignite-fired power plant to be built in Kosovo in 2010 is on the path of most economic investments in the SEE region. Similarly, the REBIS GIS study assumes that some 1300 MW of lignite-fired capacity is constructed in Kosovo between 2011 and 2015, and further 1400 MW between 2016 and 2020.

6 REGIONAL ELECTRICITY DEMAND AND SUPPLY FORECASTS

6.1 General UCTE view Of the neighbouring countries of Kosovo, Albania is not a member of UCTE, even if the grids are synchronized, while Serbia and Montenegro and FYROM are members of UCTE. Kosovo is not an independent member of UCTE, and in the calculations of UCTE, Kosovo is included in the JIEL, group (Serbia and Montenegro, FYROM), and is often grouped together with Greece. The system adequacy outlook for JIEL+Greece in UCTE report remains bleak. The Remaining Capacity (RC) remains at low levels even during 2005-2007. By 2010, generating capacity development should be able to follow load increase, but the reserve situation is not forecasted to improve. The ARM ( Adequacy Reference

Scenario Kosovo additional capacity increase 2005-2015

System marginal price range €/MWh

“Forced hydro” 1800 MW 2015: 19.0-25.2 High demand forecast in region 3400 MW 2010: 21.3

2015: 19.8 Low regional demand 0 MW 2010: 20.3

2015: 22.6 High gas price 1800 MW 2010: 25.7

2015: 18.5 Full environmental compliance 1800 MW n/a

Table 5.2. Sensitivity analysis for new power generation capacity in Kosovo in the REBIS GIS study.


Margin) requirement is not forecasted to be met in JIEL+Greece at any time before 2015. The forecasted capacity for the region is unable to meet demand in 2015. UCTE paints a picture of generally tight capacity in the region until 2015. This in general is a good situation for the planned new TPP in Kosovo.

6.2 REBIS GIS view The REBIS GIS study outlines in scenario A (independent market simulation) what would the power plant construction plan if the countries were operating as isolated markets under medium load growth scenario. The national plans include hydro plants, CHP plants, coal-and lignite-fired plants and a large number of gas-fired combined and open cycle units. When the markets are again opened for competition, imports and exports in scenarios B and C, the loads served mostly by combined cycle and open cycle plants represent demand that could be served with power imports in the neighbouring countries of Kosovo. In moving from scenario A to competitive import/export market, the export/import potential of the neighbouring markets becomes clearly discernible. The combined cycle/open cycle power plants become independent of location, to be constructed at sites where the average power cost achieved is to be lowest ( inexpensive fuel, low construction cost).It is relatively difficult to foresee where they would be constructed, ,most probably on coastlines and in proximity to major gas pipelines. The export potential Kosovo should be targeting lies in the combined cycle and open cycle power plant capacity that is anticipated to be constructed in the neighbouring countries between 2005 and 2015. This is demand that the country in question is not able to meet economically by its hydro or lignite resources, or other forms of generation (nuclear), and presents a relatively firm export load opportunity. The following text outlines the expected changes in generation by neighbouring country of Kosovo. Serbia Serbia has a larger power plant capacity than other neighbouring countries of Kosovo. In scenario A, Serbia is expected to rehabilitate 3140 MW of capacity and construct 928 MW of new capacity between 2005 and 2020. Of the new capacity, 300 MW would be combined cycle capacity, to be constructed before 2010. Albania Albania is facing acute power shortages. For 2003, REBIS GIS assumes that the shed load amounted to some 10% of estimated total demand of 6556 GWh. Albania’s power system is almost totally hydro driven, and the annual rainfall has a profound effect on the amount of electricity available.


The REBIS GIS study assumes in scenario A (isolated system) that Albania would have to by 2020

• rehabilitate 69 MW • complete 132 MW already under construction • erect 217 MW hydro plants • erect 258 MW of CHP plants, and • erect 1271 MW of combined cycle power plants by the year 2020.

Of this, some 450 MW of combined cycle plant would be added in 2005-2010, one 150 MW combined cycle plant would be added in 2011-2015, and 150 MW of combined cycle and 100 MW open cycle plant would be added between 2016-2020. It is unlikely that natural gas would be present to feed the earlier combined cycle units, and it is assumed that they would have to be oil-fired. Montenegro Montenegro has a relatively high share of hydro power. In the scenario A (independent market) of the REBIS GIS study, Montenegro is expected to rehabilitate some 191 MW of capacity and to build some 906 MW of new capacity before 2020. Of the new capacity, some 502 MW would be hydro, 258 MW would be CHP and 96 MW would be an open-cycle gas-fired unit to be constructed between 2005-2015. Macedonia

In case of Macedonia, the scenario A (independent market) indicates that between 2005 and 2020 some 927 MW of capacity would need to be rehabilitated, and some 1331 MW of new capacity would need to be added. This includes 584 MW of hydro, 203 MW lignite-fired, 174 MW of CHP and 370 MW combined cycle gas.fired generation. Before 2010, one 70 MW gas-fired unit would be built; 150 MW in 2011-2015, 230 MW in 2016-2020. The following table outlines the combined cycle and open cycle capacity that would have to be constructed in the neighbouring countries of Kosovo by 2015 under scenario A:

Neighbouring country Estimated available export capacity by 2015, MWSerbia 300 Albania 1271 Montenegro 96 Macedonia 70 TOTAL 1737

Table 6.1. Estimate of combined cycle capacity needed in countries neighbouring Kosovo by the year 2015 in REBIS GIS study scenario A (isolated markets).


In addition, there would be temporary trade in power as is typical for neighbouring utilities. It should be noted that the estimate trade opportunity with Albania is unlikely to be handled only by the currently planned interconnections with Albania, and more transmission capacity to Albania might be needed. As there is no natural gas available in Albania, the combined cycle gas turbines unit would have to be oil-fired with an estimated variable cost of € 30-40/MWh, and Kosovan lignite-fired units should be very competitive against them.

7 GRID CONNECTIONS TO NEIGHBOURING COUNTRIES

By the time of commissioning of the new TPP, the Kosovan grid is expected to be connected with well functioning 400 kV interconnections with Albania, Macedonia, FYROM and Serbia. All these interconnections have 1100 MW transmission capacity limit (thermal limit). As of now, the Kosovan 400 kV network has a relatively high amount of electricity transiting through Kosovo. The Kosovo-Albania interconnection study calculated the electricity flows in and around Kosovo according to the following graphs (historic data 2000-2004 from Kosovo Albania interconnection study). These power flows do not necessarily alleviate the power system situation in Kosovo itself, but crowd out available export capacity in some directions. The 1100 MW (thermal limit) 400 kV power transmission lines have mostly been repaired after the conflicts, and they are expected to be fully operational by the time of commissioning of the new TPP. The CESI feasibility study on the 400 kV transmission line with Albania and the REBIS GIS study give a quite accurate picture of the current electricity transmission flows in high-voltage transmission lines around Kosovo:


Figure 7.1 Current power interconnections around Kosovo

The current actual transmission in power interconnections varies remarkable, as illustrated by the following graphs:

510

644 MW

125 250

510

510

1000 MW

1000 MW

1000MW

125 250


Figure 7.2 Average transmission capacity between Serbia and Kosovo 2000-2004

Figure 7.3 Average transmission capacity between FYROM and Kosovo 2000-2004.

Figure 7.4 Average transmission capacity between Macedonia and Kosovo 2000-2004.

Maximum flow from Kosovo to FYROM load in interconnection

Maximum load in interconnection 525 MW

Maximum flow to Kosovo 823 MW in 2004


There has been a substantial flow of electricity flowing from Serbia over Kosovo to FYROM, reflecting the export of power from Serbia to the south, all the way down to Greece. The new unit would change this electricity flow pattern, but it should be noted that the existing export arrangement with Serbia, FYROM and Greece will have an affect on the capacity to export from Kosovo in the southern direction. The REBIS GIS study mentions that there were not, in the early part of 2005, no firm power import or export contracts in the SEE area. In this light, the power flow from the north in Serbia to FYROM should not be considered as a firm, long-term reservation of transport capacity. The Kosovo Albania interconnection feasibility study forecasts the following load pattern and volumes of electricity transmission in the interconnectors for the year 2015:

Figure 7.5 Year 2015 annual energy exchanges

8 REGULATION OF GRID STABILITY IN KOSOVO

Even if the power connections from Kosovo to the neighbouring countries are strong and the high-voltage grid of Kosovo can accommodate relatively large power plants, it should be noted that at present the short-term grid stability in Kosovo in case of a generation disturbance (e.g. unforeseen outage of either of Kosovo B units) can lead to short-term disturbances in the quality of electricity supply


For the pre-feasibility study, the representatives of the Consultant interviewed Kosovan power grid experts both in KEK and in MEM. The Kosovan grid is supposed to be operated in accordance with UCTE regulations, but for very practical reasons UCTE requirements cannot be met for the time being. The Kosovan power grid is currently unable to meet e.g. unexpected outages of Kosovo B units, because there is in practically nil generation capacity available for primary and secondary regulation of the grid in Kosovo. In case of acute shortfall, load shedding becomes only available tool to stabilize the grid in practice, as emergency imports from neighbouring countries are usually available only starting from the beginning of the next hour. At present, there are no co-operation agreements with neighbouring grid operators with respect of grid regulation, and for all practical planning purposes, the Kosovan grid functions as if it where an isolated grid system. The situation is further aggravated by the very steep demand annual curve in Kosovo, where maximum electricity demand is over 2.5 times higher than the minimum demand. The low level of generation capacity in comparison to demand and the relative isolation of the power grid leads to the situation where electricity supply cannot be guaranteed to all Kosovans in case of sudden outage of even one power generation unit in Kosovo. The neighbouring Albania faces the same situation because the Albanian generation capacity in general cannot meet the demand. Similar import requirements can be noted in other neighbouring grids in Serbia, Montenegro and Macedonia. Even if the region in general has a relative high share of hydro generation and it should be possible to stabilise the power grid with good co-operation with grid operators and utilising the reserve power available in hydro generation, it must be noted that the basic generation in the region is unable to meet the expected rapid demand growth of the region. Unfortunately KEK lacks the computational tools to be able to simulate the dynamic stability of the grid, and thus cannot provide the Consultant with results from detailed grid stability situation simulating the additions of power plants with varying unit sizes to the grid. In a similar manner, no regional grid stability analysis was available to the Consultant. The current unstable grid conditions would be quite similar to all prospective unit sizes of the New TPP. For larger unit sizes, e.g. 500 MW, the problem becomes more acute. However, with good co-operation of neighbouring TSOs, the issues around grid stability should be solvable. The arrangements to stabilise the grid should be in place at the time when the construction of the new TPP would be initiated, i.e. mid-2008.


9 POWER EXCHANGE WITH ALBANIA

The feasibility study of a new 400 kV power transmission line between Albania and Kosovo (ESTAP II/1 report) indicates good investment economics for the new planned power line. The REBIS GIS study takes into account the construction of the new power line, and thus the REGIS GIS study is in accordance with the expected future power transmission picture. Of the three scenarios presented in ESTAP II/1, the two latter are of interest:

• Joint operation scenario: only Kosovan and Albanian power systems would be operated jointly

• Additional scenario: Kosovan export-oriented power generation considered in the framework of both countries and on regional level.

In comparison to the scenarios of the REBIS GIS study, the additional scenario reflects better the scenarios B and C, where power trading is only limited by regional transmission constraints. The ESTAP II/1 study assumes that Kosovo would add 626 MW of lignite-fired-capacity and Albania would add hydro plants and 305 MW of oil-fired CCGT capacity between 2010 and 2020. This picture differs tremendously from the one presented in the REBIS GIS study and described in section 6 above, but the ESTAP II/1 study is not intended to be a WASP-based power system expansion study. The additional capacities for ESTAP II/1 have been adopted from earlier studies, not from REBIS GIS. Also, the power plant “park” in both countries is kept the same for most of ESTAP II/1 scenarios including the least interesting reference scenario, where Albania operates its power system independently. Thus the ESTAP II/1 study takes into account operational benefits of the new power interconnection with generation “parks” held constant in both Albania and Kosovo, but the ultimate commercial objective of Kosovan power generation industry should avoiding new CCGT construction in Albania and satisfying the Albanian power demand with firm exports from Kosovo. Given the above assumption of constant power plant “parks” for the reference scenario and joint operation scenario, the new power interconnection would serve to reduce the thermal generation in the planned Albanian CCGTs significantly, and improve the effectiveness of the Kosovan and Albanian power systems through mutually beneficial temporary electricity exchange. The third scenario, additional scenario, relaxes the assumption of constant power plant “parks” in the cases with exports to Italy, and allows for the assumption that new Kosovo TPP units would be of output of 500 MW. The additional scenario differs significantly from the REBIS GIS scenarios, and the value of the additional scenario remains unclear vis-à-vis the planned regional SEE power exchange scenario referred in point 12 below.


The joint operations scenario of ESTAP II/1 is more sensitive to the effects of a wet year in Albania than the REBIS GIS scenario B. In joint operations scenario, the hydro generation in Albania would curtail Kosovan thermal generation at times, but in the regional evaluation of the REBIS GIS study the effect of a wet year are much more subdued and the thermal generation in Kosovo would be affected only slightly. A larger electricity market area than Kosovo and Albania would reduce fluctuations of system marginal price between wet and dry years, and even if there are tremendous benefits in the sole co-operation of the Kosovan and Albanian grids, an even larger joint operation area is more beneficial to the long-term profitability for the future Kosovan power exports.

10 EXPECTED SYSTEM MARGINAL PRICE SCENARIOS

The REBIS GIS reports estimate the system marginal prices for the whole SEE. Of importance are REBIS GIS scenarios B) and C) which assume cross-border trade in electricity. Of special importance to the new TPP concept are unfavourable scenarios where the system marginal price remains low – such scenarios can be found in cases of rainy years and low demand growth. The most important scenarios and corresponding marginal price scenarios are the following:

System marginal price in €/MWh REBIS GIS scenario 2010 2015 Scenario B), fully open market: Dry year 28.7-35 25-29.2 Average year 17.7-28 17.8-25.5 Wet year 17.1-27.8 16.9-25.3

Table 10.1. Expected system marginal prices in REBIS GIS study scenario B (liberalised market), includes medium demand scenario

Combining these system margin prices with the sensitivities listed above, and at this point in the pre-feasibility study, it can be assumed that the new TPP, expected to reach some 42% efficiency in operation, would need to be able to meet the € 17 /MWh variable cost limit even including variable operating and environmental costs. This is set as target for concept design at this stage. Being able to generate at variable costs below € 17 /MWh would also leave some margin to cover fixed costs for the new TPP, even if there is no certainty at this stage of the pre-feasibility study whether that would be enough to assure profitability of the new TPP. Being able to reach this variable cost level would be a guarantee of new TPP being dispatched, but it is not as such a guarantee of general profitability after all fixed expenses have been deducted.


The REBIS GIS study indicates that substantial new capacity would be needed to meet the growing demand of the SEE region. Judging from the large number of investments and refurbishments required to meet the rising electricity demand described in the REBIS GIS study, it is difficult to foresee any overcapacity situation where electricity market prices would go down and approach the marginal system prices. A sensitivity analysis will be carried out taking into account an estimated value of CO2 emission allowances of € 25/ton.

11 EXPECTED COMPETITIVENESS OF NEW TPP

As noted earlier, the Consultant has been unable to locate a publicly available study on the expected price levels of electricity in the future SEE market, even if it assumed that the regional utilities have already developed such price estimates. The reports available in the study have made various assumptions on the market price of power in the region. The report on the refurbishment of Kosovo A units assumes power import prices to Kosovo based on recent experiences of KEK, and uses price scenarios in the range of € 40-49 / MWh. The feasibility study of the 400-kV interconnection between Kosovo and Albania assumes that power import prices in general would be in the range of €30-35 /MWh. When the pre-feasibility study for the new TPP nears its completion and all cost items are known, the required power price of the new TPP will be compared against the price assumptions mentioned above.

12 EVENTUAL ELECTRICITY EXPORT FORECASTS

From the REBIS GIS study, it can be concluded that the actual thermal generation in Kosovo would not be significantly affected if the there would a dry, wet or average year in the region (REBIS GIS, Appendix 11, pages 56-57). The effect of hydrological conditions would be captured in the system marginal price. Thermal generation volume would only be affected in the spring, even if the system margin price would change (see table 10.1 above). For simplification, it has been assumed that the regional variations in the rainfall can be excluded from the analysis of available export capacity. In the years to 2011, Kosovo will unfortunately not be in a position to export firm power even in the most optimistic scenario depicted in table 12.1, because most of the time the capacity would be needed to cover the domestic demand. However, temporary trade with neighbouring countries to replace hydro is well feasible. Combining the REBIS GIS medium demand scenario and the generation opportunities created by the


refurbishment of Kosovo A (from the draft rehabilitation report) results in the following table up to mid-2011:

2005 2006 2007 2008 2009 2010 2011

Energy demand, medium, GWh

6019 6092 6534 6616 6702 6735 6779

Peak load, MW 1179 1196 1280 1279 1278 1265 1262 Maximum capacity, MW

777 897 897 925 1105 1105 1105

Generation, Kosovo B

3300 3300 3300 3900 * 3900 *

3902 *

3919 *

Three revamped units A

510 510 510 960 2618 2618 2618

Net imports 2209 2282 2724 98 184 215 242

Table 12.1. Power imports required for Kosovo in 2005-2011.

*It is assumed that a power exchange would be available in SEE from 2008 onwards, and consequently that Kosovo B units would no longer have to follow the low summer load to an uneconomical area of operation, and Kosovo A units would also be competitive on marginal cost basis throughout the year. The current estimated variable cost of generation for Kosovo A units is € 14 /MWh and for Kosovo B units €13/MWh, which is below the estimates for lowest system marginal price. Availability of a power exchange and the low variable costs of Kosovo A units would allow theoretical optimisation of production until full capacity. However, considering the current condition of Kosovo A units this may be an optimistic evaluation. Also, total availability of Kosovo B assumed to be 79% (rehabilitation report) and not 67% (CESI feasibility study on interconnection to Albania)

Table 12.1 assumes that the full rehabilitation of Kosovo A units would be accomplished. This would maximize domestic production to cover the local demand, and shows the net import need even in the most favourable scenario. Considering the current condition of Kosovo A units, this may be overly optimistic – there may be unforeseen issues in the rehabilitation. In the later analysis, rehabilitation of only two units out of Kosovo A 3-5 is assumed. After mid-2011, the commissioning of the new TPP, the picture would change significantly. The first conclusion is that the first new unit would not create firm export capacity (if one unit unavailable), because if it is in outage itself the Kosovan system will not be able to meet the local demand, unless load is shed. In this respect, it is irrelevant whether the first new unit would be 300 MW or 500 MW. According to n-1 criteria, firm export capacity would only generated after the second new unit comes online, and even then the existence of export capacity would be somewhat dependent on the continuous operation of Kosovo units A.


12.1 New 300 MW units

If we assume that the first new TPP unit would be of the output of 300 MW, the above table would continue as follows: (medium load growth in Kosovo):

2012 2013 2014 2015 2016 2017 2018

Energy demand, medium, GWh

6833 6896 6969 7050 7191 7337 7487

Peak load, MW 1247 1240 1235 1247 1277 1302 1329 Maximum capacity, MW 1190 1190 1190 1190 1190 880 880 Generation, Kosovo B, max. 4000 4000 4000 4000 4000 4000 4000 Two revamped units A 1650 1650 1650 1650 1650 0 0 Generation new 300 MW TPP, maximum at base

2234 2234 2234 2234 2234 2234 2234

Net imports -1051 -988 -915 -834 -693 1103 1253 Firm export capacity 0 0 0 0 0 0 0

Table 12.2. Estimated power exports when the first new TPP unit is 300 MW.

It should be noted that the net export volume is totally dependent on the assumptions regarding Kosovo A units. They would be able to

Generate to the planned level of availability of the rehabilitation report (6600 hrs for units 4-5 according to the rehabilitation report)

That at least two units of the all three rehabilitated units remain operational Remain competitive vis-à-vis the expected power exchange. i..e their variable

cost of generation remains under the eventual price in the power exchange at all times, estimated at €17/MWh at minimum

Keep this level of operation without causing environmental issues Secure availability of ,fuel and ash disposal area.

If we assume further that a second 300 MW unit would be commissioned within six months of the completion of the first 300 MW unit, the above table would change to the table 12.3

2012 2013 2014 2015 2016 2017 2018 Energy demand, medium, GWh

6833 6896 6969 7050 7191 7337 7487


1490 1490 1490 1490 1490 1180 1180

Generation, Kosovo B, max.

4000 4000 4000 4000 4000 4000 4000

Two revamped units A 1650 1650 1650 1650 1650 0 0 Generation new 2*300 4468 4468 4468 4468 4468 4468 4468


MW TPP, maximum at base Net imports -3285 -3222 -3149 -3068 -2927 -1131 -981 Firm export capacity 0 0 0 0 0 0 0

Table 12.3. Estimated power exports when the second new TPP unit is 300 MW.

Further, the calculations can be performed for the third 300 MW unit (bringing the total new TPP capacity to 900 MW, according to table 12.4. (third unit assumed to come on-line beginning of 2013).


6833 6896 6969 7050 7191 7337 7487


1490 1790 1790 1790 1790 1480 1480

Generation, Kosovo B, max.

4000 4000 4000 4000 4000 4000 4000

Two revamped units A 1650 1650 1650 1650 1650 0 0 Generation new 3*300 MW TPP, maximum at base

4468 9981 9981 9981 9981 9981 9981

Net imports -5519 -5456 -5383 -5302 -5161 -3365 -3215 Firm export capacity 0 250 255 243 213 0 0

Table 12.4. Estimated power exports when the third new TPP unit is 300 MW

12.2 New 500 MW units If, however, we assume that the first unit would be of the unit size of 500 MW, the domestic table would continue as follows: (medium load growth in Kosovo)


2012 2013 2014 2015 2016 2017 2018Energy demand, medium, GWh

6833 6896 6969 7050 7191 7337 7487

Peak load, MW 1247 1240 1235 1247 1277 1302 1329Maximum capacity, MW

1390 1390 1390 1390 1390 1080 1080

Generation, Kosovo B 4000 4000 4000 4000 4000 4000 4000Two revamped units A 1650 1650 1650 1650 1650 0 0 Generation new 500 MW TPP, maximum at base

3723 3723 3723 3723 3723 3723 3723


Table 12.5. Power export in case the first new TPP would be 500 MW in size.

Again, almost the same analysis with respect to the importance of Kosovo A units applies. This could be avoided, however, if the next unit would be constructed as soon as practicable after the first one. This unit would also generate firm export capacity for the first time, provided that the Kosovo A units remain operational, as shown in table 12.6. If the second unit of 500 MW would be commissioned in 2012, the firm export capacity (n-1) would vary between 113 MW in 2106 and 155 MW in 2012.


6833 6896 6969 7050 7191 7337 7487


1890 1890 1890 1890 1890 1580 1580

Generation, Kosovo B

4000 4000 4000 4000 4000 4000 4000

Two revamped units A

1650 1650 1650 1650 1650 0 0

Generation new 2* 500 MW TPP, maximum at base

7446 7446 7446 7446 7446 7446 7446


Table 12.6 Firm export potential of the second 500 MW unit


13 ORGANISATIONAL AND OPERATIONAL STRATEGY FOR NEW TPP

13.1 Recommendations by ESTAP II, policy report Within the framework of ESTAP II, a consortium of IPA/Norton Rose have produced a report on the required policy, legal, regulatory and institutional framework required to support the commercial, technical and legal development of new TPP in Kosovo by a private investor. Without going into detail of the report, the Consultant can, based on its experience on major power plant schemes, concur with all the recommendations of the proposed changes to the legal framework proposed by IPA/Norton Rose. The most crucial of the changes recommended by IPA/Norton Rose are the changes to the regulations covering electricity change contracts, and new legislation should be drafted and be in late stages of the legal approval process when interested foreign investors are invited to bid.

13.2 Timetable for tendering process IPA/Norton Rose identify a 15 month timetable for conducting the tendering process, which can be initiated when this pre-feasibility study has been approved of. This would allow the selection of the successful tenderer take place around mid-August 2007. After this, the selected licensee would likely need eight months to prepare for the construction of the plant and procuring the necessary equipment, and assuming a 36 month construction timeline the new Kosovo TPP could be commissioned in the beginning of April 2011. To be conservative by some months, it has been assumed that the new TPP would be commissioned June 30th, 2011. At the same time, it should be noted that the new lignite mine recommended in this study should be operational by the time the trial runs of the new TPP begin in the first quarter of 2011. It should be noted that a programme of amending regulations and laws as recommended by IPA/Norton Rose should run concurrently and a definite set of rules and regulations affecting the operations of the new TPP should be available to prospective licensees at the beginning of the tendering process, i.e. in the second quarter of 2006. It should be noted that this legislative groundwork is on critical path for the development of the new plant. It is highly recommended that once the required amendments in regulation and legislation are in place, an external advisor should be hired to assist the Kosovan government to conduct the tendering process for the new power plant, and that the cost of such advisor could be covered by major donors.


13.3 New investor requirements and operational strategy of the plant Despite the encouraging political and economic development of Kosovo during the last few years, all the promoters of new TPP project have to rise to the challenge that significant issues remaining to be handled in manner that would reduce the risk of the investment in a new TPP. This pre-feasibility study has been drafted to take into account the requirement of the potential power plant investors to start from a clean slate, i.e. run their own mining operations and avoid the liability for past environmental issues which have been beyond their control. The potential investors would also require that their own personnel operate the plant, and also that they will have substantial control over the power sales issue and collection of their own receivables. IPA/Norton Rose have taken the view that the new investors should be solid utility companies which can finance the prospective investment in the new TPP on “balance sheet”, i.e. without having to create security over the power plant assets. If the selected power plant size is relatively large, this may stretch the risk appetite of some investors. Potential investors may also want to phase in their investment in e.g. by investing in more smaller units than in one large unit. To create comfort the potential investors, the first new TPP should represent relatively known technology. This would benefits potential IFI lenders as well, because they will have to carry out due diligence on the power plant technology. Generally, lenders feel comfortable with technology which has some two years of good operating experience behind it. The investors would like to see that the new TPP would operate in a base-load operation, and achieve a load factor as high as possible. This would mean that the Kosovo B units would operate in a mid-merit position, and the Kosovo A units, also considering the high age, would remain as seasonal capacity in the winter-time. Operating the new TPP in a base-load capacity would reduce the average cost of kWh generated, keep the price to eventual Kosovan customers at low level, and allow the whole environmental potential of the new TPP to be utilised. The power sales agreements are limited by current Kosovan electricity law to a duration of maximum 5 years, and there is a buy-back clause with an unclear meaning. IPA/Norton Rose correctly point out that the legal situation covering power sales agreements should be clarified and amended. In general, it can be stated that a five-year power sales contract, even for 100% of the power generated by the plant, is too short for a serious investors. At the same time, it must be kept in mind that the power market in Kosovo is to undergo a tremendous organisational change in connection with the implementation of the Athens memorandum in Kosovo, from current monopoly to fully liberalised generation market.


It is the view of the Consultant that the main characteristics new market organisation in Kosovo should be known to the tenderers when the tender competition is launched. Instead of offering a 100% power off-take agreement for the potential investors, the Ministry of Energy and Mining should seek to create a power sales “package” consisting of larger number of power sales contracts of varying duration. The tenderers could be offered a power off-take package consisting of elements like the following

• opportunity to sell some 20-30% of power output to Kosovan TSO or any energy generator at fixed terms for a period of 7-10 years, or a guaranteed contract for differences

• opportunity to sell to most creditworthy and stable industrial customers by contracts of some 3-5 years duration, e.g. Tepcka mine, Feronickel

• obligation to sell some 30% of power on the investor’s risk (.e.g. selling to power exchange)

• opportunity to export to neighbouring countries under 5-10 year contract Planned carefully, such package of off-take arrangements would create a package that investors would find satisfactory for the initial period of investment, without any single off-taker having to bear the risk burden of the whole power generation of the new TPP. Creating a credible package would require, however, that a very experienced international expert is retained to advice in putting together such a package after the main characteristics of the new market arrangement are well known. The potential investors s would also like to see that the future Kosovan TSO would have in place all the primary, secondary and tertiary tools to regulate grid stability in Kosovo, and that they would not face any kind of liability in case of unforeseen power plant outages.

60R05429.01-Q070-003 February 6, 2006


Contract nr 04KOS01/03/009


Lot 1, Task 2

Evaluation of site

Draft final

Lot 1, Task 2 February 6, 2006 Site selection Page 2 (27) Table of contents

1 INTRODUCTION..............................................................................................................4

2 SITE REQUIREMENTS...................................................................................................4

2.1 Area ......................................................................................................................................4 2.2 Connections..........................................................................................................................5

3 SITES TO CONSIDER......................................................................................................9

3.1 Site 1 at Kosovo B power plant..........................................................................................10 3.2 Site 2, Bivolak ....................................................................................................................13 3.3 Site 3, Grabovc...................................................................................................................16 3.4 Site 4, Palaj.........................................................................................................................21

4 OTHER CONSIDERATIONS........................................................................................23

4.1 Zoning and historic sites ....................................................................................................23 4.2 Seismic activity ..................................................................................................................23 4.3 Environmental aspects........................................................................................................23 4.4 Future considerations .........................................................................................................24

5 INITIAL COST COMPARISON ...................................................................................24

6 CONCLUSIONS AND RECOMMENDATIONS.........................................................26

Tables Table 5.1 Site initial cost comparison ................................................................................................24 Table 6.1 Comparison of the sites for new TPP.................................................................................26

Lot 1, Task 2 February 6, 2006 Site selection Page 3 (27)

Figures Figure 2.1 Length dependency of a conventional high stack...............................................................5 Figure 2.2 The main tie-ups of a lignite fired power plant ..................................................................6 Figure 3.1 Site alternatives for 2000 MW new TPP ............................................................................9 Figure 3.2 A possible new location on the eastern side of the railroad..............................................11 Figure 3.3 Kosovo B from the west. ..................................................................................................12 Figure 3.4 The 400 kV switchyard seen from Kosovo B access road. ..............................................12 Figure 3.5 Site 2 location (gridlines 1 x 1 km)...................................................................................14 Figure 3.6 View to the east.................................................................................................................15 Figure 3.7 Ibër-Lepenc water supply channel to Kosovo B and diversion to Feronikel (to the left

before the gate)...........................................................................................................................15 Figure 3.8 Roads in the area...............................................................................................................16 Figure 3.9 Site 3, Grabovc, the railroad and stream to be relocated (grid 1 x 1 km).........................17 Figure 3.10 KEK controlled areas around Grabovc (green lined areas) ............................................18 Figure 3.11 KEK controlled ash dumps southwest of Bardhi............................................................19 Figure 3.12 KEK controlled areas south of the existing mines..........................................................19 Figure 3.13 Plant site seen from the south .........................................................................................20 Figure 3.14 View to the south (possible lignite yard) ........................................................................20 Figure 3.15 Site 4, Palaj .....................................................................................................................21 Figure 3.16 Potential areas containing toxic wastes ..........................................................................22


1 INTRODUCTION The pre-feasibility study for the new thermal power plant (TPP) in Kosovo includes as the second task site selection. The new “mine mouth” plant is planned to utilize the lignite resources of the Sibovc field. The field is estimated to support some 2000 MW power generation for 40 years i.e. a technical life of a plant. The field is also assumed to feed the existing power plants as the present mines will exhaust by 2011.

The existing 2 x 300 MW Kosovo B power plant is very close to the Sibovc field and has vacant space for expansion but the Consultant has been advised to look after other potential sites for the proposed new development as the potential foreign investors might prefer to have complete independence and start from a clean site.

A site able to accommodate 4-6 units having unit sizes between 300-600 MW is searched and potential sites briefly analyzed.

2 SITE REQUIREMENTS

2.1 Area A footprint for a single unit is approximately 100 x 320 meters and the diameter of the evaporative natural draft cooling tower being the decisive factor in width. If a stag-gered arrangement of the cooling towers is applied the length of the “unit space” should be increased to 400 metres. It is assumed that the conventional high stack is eliminated by taking the flue gases into the cooling tower. The length of a unit is de-pendent on the need of flue gas desulphurization plant (FGD) as the following sche-matic drawing illustrates.


400 m

Turbine Turbine Turbine

Boiler Boiler Boiler

ESP ESP ESP

320 m

FGD FGD FGD

Figure 2.1 Length dependency of a conventional high stack

The actual plant with 2000 MW capacity would need approximately 600 x 400 m i.e. 24 hectares. That area can also accommodate the auxiliary functions like offices, wa-ter treatment, oil storage yard, (limestone shed) and maintenance shop for heavy items e.g. crushers and pulverizer wheels.

The lignite supply will need an intermediate storage yard between the mine and the boilers although the normal operation is directly from the mine to the boiler bunkers. That storage can either be directly attached to the plant or located along the transporta-tion route. The recommended storage capacity is for 14 days i.e. 750.000 tons. The area for the storage yard is 200 x 500 meters i.e. 10 hectares.

2.2 Connections The main tie-ups of a lignite fired power plant are illustrated in the following block-diagram made for a single block:


Electrical power 300 / 500 MW

Power plant 400 kVWater 850 / 1400 m3/h

300 / 500 MW unit

(Limestone 2 / 3 t/h) Waste water 175 / 250 m3/h

Lignite fuel 360 / 600 t/h Ash 60 / 100 t/h

Other minor flows:Heavy/light fuel oilCausticHydrochloric acid(Ammonia)

Figure 2.2 The main tie-ups of a lignite fired power plant

2.2.1 Lignite fuel The lignite fuel from the Sibovc mine is transported by a belt conveyor system. This system calls for a relatively short distance from the mine. The transport distance pref-erably should be less than five kilometres but in any case it should not exceed ten kilometres. It will need an unobstructed corridor from the mine to the power plant.

A belt conveyor of 1,5-2 metres wide would able to transport the fuel volume, ap-proximately 2500 t/h, required by the plant. The belt conveyor can easily cross any public road or railroad occurring on its route.

2.2.2 Raw water The power plant will need raw water 1400 m3/h per 500 MW i.e. the fully built 2000 MW plant would consume 5600 m3/h (1,6 m3/s). Most of that water would go to the evaporative cooling tower. All the water received needs pre-treatment (softening and filtration) before its use at the plant.

The industrial water is coming to the Pristine area trough a multipurpose (irrigation and industrial use) system built in the early eighties and financed by the World Bank. It originates from the Lake Gazivodo in the northwestern corner of Kosovo. Partly the lake is beyond the border. The lake has a storage capacity of 350 million cubic metres. The water is coming trough a 40 km long channel system. Mostly it is made of open concrete lined channels and partly in conduits crossing valleys etc. The water supply system is operated by Ibër-Lepenc, a public enterprise created for the task. Kosovo B power plant is currently paying 5 cents per cubic metre for the raw water delivered by Ibër-Lepenc.

The water department of MESP (Ministry of Environment and Spatial Planning) indi-cates that an overall water usage plan is under preparation and that will be completed


in 2006. Anyhow MESP assures that there is water available from the Qazivodo Lake and new power generation will have priority in allocating those water resources.

Originally the water supply system for Kosovo B plant has been designed for 21.000 m3/h (5,8 m3/s). Currently the plant uses around 1500 m3/h (0,4 m3/s). The de-livery limit between Ibër-Lepenc and KEK is within one kilometre from the power plant.

The raw water quality is said to be relatively stable due to large storage capacity. As the channels are open heavy rains may cause occasional disturbances in its quality.

2.2.3 Limestone In case of applying pulverized firing concept in the new steam boilers they will most probably need a separate flue gas desulphurization plant. That will consume some limestone. Tentatively its volume will be very low if compared with the fuel require-ments. The daily consumption is around 300 tons and that will be transported to the site by trucks. The limestone is sourced from local mines in the south.

2.2.4 Electrical power The electrical power from the plant will be transferred to the Kosovo´s main 400 kV switchyard close to the Kosovo B power plant by 400 kV lines. Each new unit would have its own line if the plant would be aside the Kosovo B plant. For other potential locations a single line can transport up to 1000 MW as the distance would be less than 15-20 km. For the full capacity of the plant two lines as a minimum would be required or double conductors could also be built on single towers.

The concept presented above for new sites will need a 400 kV switchyard close to power plant where individual generating units are combined for the single/double line delivery to the receiving switchyard. In case of building only large 500 MW units in-dividual 400 kV lines could be taken straight to the Kosovo B switchyard.

2.2.5 Ash One 500 MW unit produces close to 100 t/h of ash and the fully completed 2000 MW plant would produce 400 t/h of ash. Mostly it is in the form of fine fly ash and the rest is slag/bottom ash depending on the firing concept (PF/CFB). That ash has to be dumped. Preferably the place should be in the mine. There will be approximately 100 millions tons of ash to be dumped during the life of the new plant.

The ash is classified in many European countries as waste and its dumping is strictly controlled. Especially old fashioned hydraulic transportation systems are prohibited. Water can be used only to an extent to get the ash solidify or reduce its dusting during its transportation. It is assumed that the ash has to be dumped to a special dumping area separately from the overburden. The dump area bottom has to be sealed to pre-vent ash contaminated alkaline waters seep into the surrounding soils.

A dry transport could be either a belt conveyor or truck transportation. In case of a hy-draulic system only systems having ash/water ratio below 1 can be considered..

Lot 1, Task 2 February 6, 2006 Site selection Page 8 (27) 2.2.6 Waste water

Approximately 20 % of the plant water consumption has to be dumped as waste water. Most of it comes from the purge of the cooling towers or washing water of the sand filters at the initial purification of the water. That stream can be used to moisturize ash if required.

Other streams will be neutralized / purified as required by the receiving waters.

2.2.7 Road access A power plant needs good road access as heavy transports arrive especially during its construction phase or during operation transports leaving/arriving for/from repairs. The heaviest pieces are typically generators, step-up transformers and steam drums. They can weigh up to 500 tons.

2.2.8 Railroad Railroad can also be used for heavy transports if the track can easily be built up to the site.

Kosovo B has the railroad connection but it appears to be unused for several years.


3 SITES TO CONSIDER Four potential sites to accommodate the new 2000 MW power plant utilizing the lig-nite resources of the Sibovc mine. They are:

Site 1, Expansion are to the north at Kosovo B power plant

Site 2, Area in the north-eastern corner of the Sibovc field in Bivolak

Site 3, Area in the valley to the north of Grabovc on the western side of the Si-bovc field

Site 4, Area to the west of Palaj and the lignite conveyor to Kosovo B

The following map illustration points out the proposed sites in relation to the Sibovc field.

Figure 3.1 Site alternatives for 2000 MW new TPP

1

2

3

4


3.1 Site 1 at Kosovo B power plant There is 700 x 500 metres free space to the north of the existing power plant reserved for future blocks as the initial plan was already to locate 2100 MW generating capac-ity to the site. To the west of this free area there is a huge fly ash pile of approximately 15 million tons. The ash piles occupy an area of 50-60 hectares (600 x 1000 m). The plant is now stopping to dump its ash onto the piles as the new pipeline to the Mirash mine is taken into use. A part of that ash pile area could serve as the lignite storage yard for the new blocks. The existing lignite yard can hold up to 360.000 tons.

The 400 kV switchyard receives all the cross border 400 kV lines and it is only few hundred meters away form the plant.

There is double conveyor belt system feeding the existing B1 and B2 units from the mines.

The water supply channel to the plant has been designed for 21.000 m3/h and only 1500-2000 m3/h is currently used by the plant. The delivery limit between Ibër-Lepenc and KEK is on the western side of the Sitnica river abt. 1 km from the plant.

The site topography is flat. The whole site is above the lignite seam. The foundation conditions are reasonable. The existing plant structures (350 MW units) are sitting on a reinforced concrete slab of 3,5 metres thick immersed at 7 metres depth. The site is bordered by the Sitnica river in the west. It was said that there is a slight risk of flood-ing along the river banks.

The operation at this site makes possible to have many joint auxiliary functions with Kosovo B units if considered advantageous and acceptable for both parties. Possibly the most important item could be joint mining operation of the Sibovc as the recently completed feasibility study envisages. The site makes also possible to develop entirely separate lignite feeding systems as the Sibovc field border line is just one kilometre from the plant site.

Another important common function could the use of the common ash dump at the Mirash mine.

The following picture illustrates the areas currently controlled by KEK (green lined with red borders).

Later in the presentation workshop also an idea to locate the new plant on the eastern (opposite) side of the railroad was identified. The area is sufficient and basically va-cant but the Consultant considers it to be too close to the main 400 kV switchyard.


Figure 3.2 A possible new location on the eastern side of the railroad.

The area is bordered by the railroad to the east and the 400 kV switchyard is on the eastern side of the railroad just 3-400 metres away. There is municipality of Ple-mentini next to the north from the proposed site. It is mostly located on the western side of the railroad. The following photos illustrate the proposed site:

Ash piles

New units

Water supply


Figure 3.3 Kosovo B from the west.

The huge ash pile contains around 15 million tons of fly ash. The new plant would be located behind the piles. At least half of the pile should be removed to accommodate the lignite yard for 14 days´operation. The existing lignite yards are located to the right of the ash piles.

Figure 3.4 The 400 kV switchyard seen from Kosovo B access road.


3.2 Site 2, Bivolak The area outside of the north-eastern corner of the Sibovc field is relatively flat agri-cultural land suitable for the proposed new power generating units with their fuel stor-age yard. There are no physical limitations to locate the plant and the desired ar-rangement is easy to make. The land is owned by private persons.

The site is on the top of the lignite seam as Kosovo B and the foundation systems could be similar as for Kosovo B. The lignite seam is close to the surface in the Si-bovc river valley making start of independent mining operation there relatively easy (Alternative 3.2. in the Sibovc feasibility study). Even the ash dumping might be pos-sible to organize within the mining operations.

The water supply is close as the bifurcation station of Ibër-Lepenc (Feronikel and Kosovo B) is just to the north of the Sibovc mine boundary. The following topog-raphic picture illustrates the area close to the mine boundary.

The area needs a better access road and the Sitnica river has to be crossed with a good bridge. The estimated length of the access road is 5-6 km from Milosevo.

There are 400 kV transmission lines crossing the area towards to the north. They may have to be relocated by the mining operation and by the selected site. The distance to the 400 kV Kosovo substation is approximately 3 km.


Figure 3.5 Site 2 location (gridlines 1 x 1 km)

The area is illustrated by the following photographs:


Figure 3.6 View to the east

Figure 3.7 Ibër-Lepenc water supply channel to Kosovo B and diversion to Feronikel (to the left before the gate)


Figure 3.8 Roads in the area

3.3 Site 3, Grabovc This site is located on the western side of the Sibovc field. The area is more rugged and wooded hills are there limiting potential sites to a place in a valley in the south-western corner of the Sibovc field. There is a 3 kilometres long and 5-600 metres wide area. The ridge separating the valley from the Sibovc field is 50-100 metres high and getting higher towards to the northern direction. In the west there is a mountainous area where the peaks are 200-250 metres above the valley bottom. The plant could be located there if the lignite yard is more separated from the plant itself. In the valley it-self there are few scattered farmhouse groups and in the south there is the village of Grabovc.

The site is outside the lignite seam. There are some rocky hills visible in the ridge separating the valley from the Sibovc field. Generally the foundation conditions there are considered slightly better than for the sites 1 & 2.

There is a small stream called Drenica passing trough the valley towards southeast. The local people did not report any major floods in the area.

A single track railroad is passing trough the valley to Glogovci. Its use appears to be very limited. Just south of Grabovc in Belacevac (3 km) there is a marshalling yard that is in active use. A gravel road follows the railroad in the valley. The railroad and adjoining dirt road have to be relocated onto the western slope of the valley.


The following map illustrates the location:

Figure 3.9 Site 3, Grabovc, the railroad and stream to be relocated (grid 1 x 1 km)

The site will need longer lignite transport systems than the sites 1 & 2. The approxi-mate length is double 6 km vs. 3 km. The same applies to the 400 kV transmission lines to the Kosovo switchyard. The distance is around 12 km if the northern route around the Sibovc field is selected. The water channel to Feronikel crosses the valley but Ibër-Lepenc has not indicated whether that channel is capable to supply also the new plant with water. The water supply distance from the bifurcation station in Bivolak is approximately 8 km.

Regarding to ash dumping possibilities the old mine of Bardhi is near by and that may be used to deposit the fly ash in an orderly way. The distance is only 3 km.

The valley is in agricultural use at the moment and the properties are private. KEK controls some ash dumping areas and the southwestern corner of the new Sibovc min-ing area as the following extracts from the KEK´s property map indicates.


Figure 3.10 KEK controlled areas around Grabovc (green lined areas)

The same applies to the area just south of the Bardhi and Mirash mines:

Water to Feronickel


Figure 3.11 KEK controlled ash dumps southwest of Bardhi

Figure 3.12 KEK controlled areas south of the existing mines


The potential site is illustrated by the following photographs:

Figure 3.13 Plant site seen from the south

Figure 3.14 View to the south (possible lignite yard)


3.4 Site 4, Palaj This site is close to the existing lignite conveyors to Kosovo B and the future border line of the new Sibovc field. The area is relatively flat hill 30-40 meters above the Sit-nica river and Kosovo B site. The following extract from KEK´s property map illus-trate the potential location.

Figure 3.15 Site 4, Palaj

The site is on the lignite seam and relatively close to the mines that may be a slight risk in the soil stability with heavy structures. Additionally the environmental section on the Sibovc mine feasibility study indicates that the area south of Lajthiste may con-tain some environmental risks as the attached picture Fig. 3.3.2. illustrates.


Figure 3.16 Potential areas containing toxic wastes

This area has been excluded from the further evaluation for being too risky although it is ideally located.


4 OTHER CONSIDERATIONS

4.1 Zoning and historic sites MESP has indicated that there is no valid plan at the moment and the national zoning plan is currently worked out to be introduced for discussion / approvals in 2006. The area in and around the Sibovc field is basically agricultural land and suitable for min-ing of lignite and its large scale use for electricity generation.

There is a previous general plan for energy industry in Kosovo by the Institute of Ar-chitecture and Town Planning of Serbia dated 15.11.1990. A brief analysis of that re-port does not reveal any major obstacles to develop the area as above. The mountains west of the Sibovc field are pointed out as a potential natural park but apparently no actions in this respect have been taken up to date.

Regarding to archaeological sites the plan above indicates two prehistoric sites close to the proposed sites: One is close to site 2 but up to date it has not been possible to locate its exact location in the area. The other one is west of the Sibovc field on the hills.

4.2 Seismic activity The seismic map of the area indicates that there is an area of 9 at Mercalli scale in the Pristine region bordering the western regions of Pushe Kosove and Obiliq i.e. the area where the city is located. The power plants Kosovo A and B are in the area classified as 8 at Mercalli scale. However, the design of those plants have been made for Mer-calli scale 9.

The new sites 2 and 3 may be in this respect as the areas to the west are classified as Mercalli scale 7.

4.3 Environmental aspects Regarding to the atmospheric pollution i.e. flue gas emissions the prevailing winds are from the northeast out of the main population centres. The maximum ground concen-trations of the existing power plants are found some 2,0-4,0 km to the southwest in less populated areas. The same can be expected from the new plant although the emis-sion concentrations at the source (cooling tower plume) will be less than in the stacks of the existing plants.

The plant noise level especially in case of Kosovo B location (Site 1) has to be coor-dinated as the village of Plementina is relatively close on the northern side. The main issue is the night time requirements of 45 dB(A) at the boundary. Other sites are not as critical in this respect.

The areas that are used for the past mining operations or to locate the existing power plants contain/may contain toxic wastes and therefore a new investor interested in oc-cupation of any of those areas should have a protection against potential claims in the future.


During the workshops on the site selection a proposal to utilize the site of the old gasi-fication plant at Kosovo A has been raised. It has been rejected as there are phenols in the soil. To clean phenolic soil typically is estimated to cost 50-70 €/m3. A case that 1 meter thick layer of the soil is removed from the 25 hectare power plant area would cost around 150 million €. Additionally there would be difficulties to assure a foreign investor that he will not be liable for any past contamination at the site as the ground-water appears to be contaminated.

4.4 Future considerations The Sibovc field can support the continuous operation of 2000 MW base load plant for the next 40 years. The life of a conventional power plant is 250-300.000 operating hours i.e. 40 years. The machinery itself is worn out and most probably also outdated. The power plant site has a certain infrastructure that could serve new generating sets and partly the civil structures can be utilized. Another fact is that the permitting of en-tirely new virgin sites is coming more difficult.

Most of the unused lignite resources are located south of the existing mines Bardhi and Mirash. In that respect it might be wise to locate the new plant as close as possible to those remaining deposits (Site 3).

5 INITIAL COST COMPARISON A brief initial cost comparison between the potential sites has been made to explore whether there is any substantial cost difference between the proposed sites. The land cost has not been taken into consideration as it is assumed to be almost equal for all the proposed sites. The following table lists the distances/volumes as well as the ap-plied unit prices. For example the cost of the electrical connection is just the line per kilometre as the sending/receiving end facilities would be the same in all those alter-natives.

Site initial cost comparisonSite 1 Site 2 Site 3

Item €/unit units cost units cost units costLignite transport 3000 3000 9 000 000 3000 9 000 000 6000 18 000 000Fly ash 2500 4000 10 000 000 8000 20 000 000 3000 7 500 000400 kV line 500 500 250 000 3000 1 500 000 12000 6 000 000Water supply 1000 1000 1 000 000 1000 1 000 000 8000 8 000 000Road 100000 0 0 6 600 000 3 300 000Railroad relocation 200000 0 0 0 0 3 600 000River relocation 200000 0 0 2 400 000Flyash removal 3,5 15000000 52 500 000 0 0Houses 100000 0 0 5 500 000 30 3 000 000Grand total 72 750 000 32 600 000 43 800 000

Table 5.1 Site initial cost comparison

The outcome is that Site 2 is slightly less costly than the others. Site 1 at Kosovo B would be the lowest cost option provided that the ash pile removal cost is not charged to the new TPP project. In this evaluation it has been assumed that the whole ash pile is relocated.


The differences are marginal if compared with the overall cost of the proposed 2000 MW and 2 billion EUR power plant.


6 CONCLUSIONS AND RECOMMENDATIONS The proposed sites can be summarized and commented in the following table:

Site 1 (Kosovo B) 2 (Bivolak) 3 (Grabovc)

Space - type - power plant - fuel yard - construction

dedicated site sufficient ash pile removalcan be found

green field total freedom total freedom total freedom

valley 500m wide sufficient “remote” can be found

Accessibility - by road - by rail

existing existing

6 km new road possible if desired

3 km new road existing, reloca-tion

Main tie-ups - lignite fuel - water - power, 400 kV - ash

3 km transport at site boundary < 0,5 km 4 km to Mirash

3 km transport < 1 km < 3 km 8 km to Mirash

6 km transport 8 km 12 km 3 km to Bardhi

Site - land use - soil conditions - seismic risk - zoning - ownership

power plant clay & lignite Mercalli 9 power plant KEK

agricultural clay & lignite Mercalli 9/8 no restrictions private

agricultural not lignite, rock Mercalli 9/8 no restrictions private

Other considerations - plant visibility - noise - flue gas - mining from

south in Sibovc

high Plemetina close open area location ok

high no open area long distance in the beginning

hidden no hills to the west location ok.

Table 6.1 Comparison of the sites for new TPP

The site 1 aside of Kosovo B power plant would be the most ideal place to locate the new power plant. This is valid provided that the potential foreign investor/plant owner can have absolute security on the fact that he will not be liable for the potential envi-ronmental pollution caused by the existing operations. The site has all the infrastruc-ture and the new lignite field is close by.

Site 2 Bivolak in the north will offer complete freedom as a green field site without any doubtful past. It is located above the lignite deposit and the site is far away from the future lignite mines in the south.

Site 3 in Grabovc would offer a long term solution as a “not so visible” power plant site. It is outside of the lignite seam and may offer slightly better foundation condi-


tions but the width of the valley means that the lignite storage yard cannot be so closely integrated with the plant.

The final selection of the site is also pending on the mining concept in Sibovc whether there will be two separate mining operations or just one single operation as described in the recently completed feasibility study.

At the moment the Consultant recommends to look at the Site 1 at Kosovo B provided that sufficient assurances are available on the limitation of the liabilities for the past pollution there. Another crucial issue is to agree with KEK on the joint operation of the site as well as the cost of its use. If those conditions are not satisfactory to the plant investor the Consultant would recommend to look at Site 3 in Grabovc for its long term benefits.

60R05429.01-Q070-004

February 6, 2006




Draft report on power plant technology review

Draft final

Lot 1, Task 3 February 6, 2006 Technology review Page 2 (37) Contents

1 INTRODUCTION 4

2 STEAM CYCLE POWER PLANTS 4

2.1 Steam parameters and plant overall efficiency 4 2.2 Materials for high temperatures 5

3 STEAM BOILERS 8

3.1 Lignite analysis 8 3.2 Pulverized fired boilers 9 3.3 Circulating Fluidized Bed combustion 12

4 EMISSION CONTROLS 15

4.1 Desulphurization 15 4.2 Wet scrubbers for SO2 control 15 4.3 Spray dry scrubbers for SO2 control 17 4.4 Sorbent injection systems for SO2 control 18 4.5 Dry scrubbers for SO2 control 18 4.6 Regenerable processes for SO2 control 19 4.7 Combined SO2/NOx removal processes 19 4.8 NOx-controls 20 4.9 Selective catalytic reduction (SCR) for NOx control 20 4.10 Selective non-catalytic reduction (SNCR) for NOx control 21 4.11 Combined SO2/NOx removal processes 21

5 STEAM TURBINES 22

5.1 Material selection 22 5.2 Steam turbine High pressure and Intermediate pressure casings 23 5.2 Number of LP turbine casings 23 5.4 Turbine condenser 24 5.3 Material Selection 24 5.5 Generator 25

6 IGCC (INTEGRATED GASIFICATION COMBINED CYCLE) 26

6.1 Background 26 6.2 Process description 26 6.3 Classification of gasifiers 27 6.4 Performance without CO2 capture 28 6.4.1 Efficiency 28 6.5 Capital cost and performance in lignite based IGCC 34 6.6 Conclusions 34

7 PRESSURIZED FLUIDIZED BED COMBUSTION (PFBC) 36

Lot 1, Task 3 February 6, 2006 Technology review Page 3 (37) Figures Figure 2.1 Efficiency vs. fuel and CO2 NPV 5 Figure 3.1 Pulverizer arrangement in Kosovo B (Stein/Alstom) 10 Figure 3.2 Schematic diagram of CFB-boiler plant (Foster Wheeler) 13 Figure 4.1 Wet scrubber SO2 removal process / “Wet gypsum process” (Scholven) 16 Figure 4.2 Process diagram for Spray dry scrubber based SO2 control 17 Figure 4.3 Combined NOx/SO2 removal system 20 Figure 6.1 IGCC process without CO2 capture 27 Figure 6.2 IGCC availability history (excluding operation on back-up fuel). Graph provided by Jeff

Phillips, EPRI 30 Tables Table 2.1 Typical steam parameters in a single reheat plant firing conventional steaming coal 4 Table 2.2 Commonly applied materials for different service locations 7 Table 5.1 Material properties of the compared tube materials 25 Table 6.1 Characteristics of different gasifier types// source: C. Higman and M. van der Burgt,

“Gasification”, Elsevier, 2003 28 Table 6.2 Environmental performances 30 Table 6.3 Effect of coal type on E-gas IGCC systems. Adapted from 31 Table 6.4 Commercial scale coal/petcoke based IGCC demonstration plants 32

Lot 1, Task 3 February 6, 2006 Technology review Page 4 (37)

1 INTRODUCTION

This report summarizes potential technical concepts for large scale power generation on lignite.

2 STEAM CYCLE POWER PLANTS

2.1 Steam parameters and plant overall efficiency

The initial selection of the steam parameters has a fundamental effect on the plant overall efficiency. It basically fixes the plant operating parameters for the whole life as their modification especially upwards would be far too costly. In order to have an idea on the impact of the following table summarizes the typical overall efficiency (LHV) vs. steam parameters in a single reheat plant firing conventional steaming coal:

Table 2.1 Typical steam parameters in a single reheat plant firing conventional steaming coal

Steam temperature HP / RH °C

Pressure bar 538/538 565/565 590/590

165 41,0 % 41,8 % 42,2 %

250 42,0 % 42,7 % 43,3 %

300 42,2 % 43,0 % 43,5 %

Other factors affecting to the plant overall efficiency are boiler efficiency and plant auxiliary power consumption. The flue gas loss is the largest single item in the boiler efficiency. A temperature difference of around 20 °C in the exit temperature means one percent in the boiler efficiency and 0,4 % in the plant overall figure. Additional heat recovery systems in the flue gas systems have increased the boiler efficiency from typical 92 % to 95 %. Those systems in more details are presented in section “Boilers”. Regarding to combustion of wet fuels like lignite or brown coal the flue gas loss goes up lowering the boiler efficiencies 1-2 percentage points. Typically 8-10 % of the gross generation is used by the plant auxiliaries. The boiler feed water pump drive being the largest single consumer. Large plants >300 MW have condensing steam turbine drives using reheat steam and discharging it into the main condenser or may have its own condenser. Those plants have electric motor driven start-up pumps. One decisive fact to switch to steam turbine drive is as the unit size and steam pressure go up the power requirement of a boiler feed pump exceeds the available motor


size (18-20 MW). The steam turbine concept reduces the plant auxiliary electrical power requirement to 4-5 %. A wet desulphurization plant typically adds 1,5-2 percentage points to the auxiliary power if applied. It is also assumed that the cooling tower will be of natural draft type and there the required pumping head is low i.e. the distribution channels are only 10-12 metres above ground. In Germany there has been a development project on a high efficiency 600 MW coal fired power plant by VGB, Power producers and power plant machinery manufacturers. It was called “North Rhine-Westphalia”. The concept was based on designs and materials currently available and tested in the actual operation. The plant has steam parameters of 285 bar/600°C/620°C. The base line efficiency is 45.9 % and that could be increased up to 47,3 % with an additional cost of less than 35 EUR/kW, %-pt. For the new TPP in Kosovo the following discounted benefits can be applied in the plant optimization what comes to its efficiency:

Kosovo New TPPEfficiency vs. Fuel & CO2 NPV

-400,0

-300,0

-200,0

-100,0

0,0

100,0

200,0

300,0

30 35 40 45 50

Efficiency %

Euro

per

kW

Fuel CO2-credit Combined

Figure 2.1 Efficiency vs. fuel and CO2 NPV

It has been calculated by using 1 EUR/GJ total fuel cost, 7500 hrs/a base load, 8 %/a discounting factor over 40 year life. The CO2-credit is assumed to be 20 EUR/ton.

2.2 Materials for high temperatures


The following table summarizes the commonly applied materials for different service locations:


Table 2.2 Commonly applied materials for different service locations

Steam values HP Pressure (bar) 250 250 270 300 300 - 350 HP Temperature (oC) 540 566 580 600 650 - 720 IP Temperature (oC) 560 566 600 620 650 - 720

High temperature components

13 CRMo 44 HCM 2S HCM 12

Water wall panels

7 CrMoVTiB1010 T91, A617

X20 CrMoV 121

Final SH / RH outlet sections

T91, T92 Austenitic materials Ni-base alloy

NF616 / E911

Main pipes and boiler headers P91

P92 Ni-base alloy

Turbine parts and valve bodies 1 - 2 % Cr 9 - 12 % Cr Ni-base alloy

Today Future

The limit at the moment is in the range of 600-620 °C.


3 STEAM BOILERS

3.1 Lignite analysis

The huge lignite resource found in Kosovo can be characterized with the following analysis as received from the Sibovc (>8000 samples analyzed) mine: Heat value, LHV kJ/kg 8200 - range kj/kg 6000-9500 Ash % 15,3 - range % 10-20 Moisture % 42 - range % 40-45 Sulphur, total % 1,1 - range % 0,7-1,5 Sulphur, combustible % 0,35 - range % 0,1-0,7 Carbon % 22,0 Hydrogen % 2,1 Nitrogen & oxygen % 13,0 Chlorine % 0,0 Its typical ash analysis is assumed to be as follows based on the information of the ad-joining Bardhi and Mirash fields: SiO2 % 38 Al2O3 % 6,8 Fe2O3 % 5,4 CaO % 35 MgO % 2,2 SO3 % 8,3 Others % 4,3 Grand total % 100 The typical ash melting temperature parameters are indicated to be: Sintering °C 980 Half ball °C 1250 Melting point °C 1300 This Kosovo lignite can be characterized by its relatively low ash content, low combustible sulphur as the most of the sulphur is found in sulphate/sulfite form and the existence of ample calcium in the fuel. The ash softening and melting temperatures are low and cause problems in conventional combustion process if not properly considered at the design..


Unfortunately there are very limited information on the existence of harmful elements in the Sibovc lignite like Na, K, Cl, F, Hg, Zn, Pb, Cd, Si, V etc. These elements have significant impacts on the melting temperature of the ash, hot corrosion in the boiler as well as flue gas emissions. It is therefore recommended to start a special testing program on the Sibovc field e.g. one drill hole per square kilometre (total 21 km2) and samples from the top, middle and bottom of the lignite seam for exhaustive analysis. This information would be fundamental in the actual combustion concept/boiler furnace design as well as in the production of the environmental impact assessment study report. The presence of calciumcarbonate, CaCO3, in the fuel has not been analyzed extensively but the records of the the existing power plants indicate that the percentage of calciumoxide, CaO, in the ash varies between 25 and 45 %. It has to be kept in mind that the calcinizing process (CaCO3 to CaO) consumes 178 kJ/kmol (Ca) and respectively formation of calcium sulphate (CaSO4) releases 500 kJ/kmol. If there is a substantial surplus of calcium carbonate in fuel the loss of heating value has to be taken into consideration. Emission requirements It is assumed that the new thermal power plant, TPP, will fully comply with the EU Large Combustion Plant, LCP, rules. That will mean the following emission levels from the beginning of the operation: Sulphur dioxide, SO2 mg/nm3 200 Nitrogen oxides, NOx mg/nm3 200 Particulates mg/nm3 30 Applicable combustion methods The unit sizes considered for the new TPP are 300 and 500 MWe net and that means heat release capacities in the range 750 to 1200 MJ/s. For such a heat release capacity the following combustion methods can be considered:

• Pulverized firing, PF or • Circulating Fluidized Bed combustion, CFB

Regarding to the combustion products and the required emission levels into the atmosphere it appears that the CFB-combustion can meet the SO2- and NOx-emission limits straight from the combustion chamber. PF would need separate flues gas treatment for reducing those emissions to the required levels as discussed below. Both combustion systems will need particulate removal to meet the allowable dust concentration in the exhaust. These combustion systems and the associated steam boilers are more discussed in the following section.

3.2 Pulverized fired boilers

Traditionally pulverized firing has been used for large scale boilers. Pulverized firing means to process the fuel into fine powder that has mean particle size around 0,05 mm


and the maximum size should not exceed 0,3 mm. That powder is injected into the furnace with preheated air and the ignition takes place by the radiation of the surrounding flame. The actual combustion lasts only few parts of a second. The hottest parts of the furnace are relatively close to the theoretical combustion of the used fuel i.e. with this wet lignite 1300-1400 °C temperatures can be expected. The heat flux to the furnace walls is intense in this burner zone and is one of the main design criteria for the furnace sizing. This high temperature means also that the ash particles may melt and become sticky as the ash melting temperature is equal or lower to the actual temperature in the flame. The lignite fuel is delivered to the boiler silos pre-crushed i.e. the maximum size of the fuel is typically 30-40 mm. For pulverizing of wet lignite beater wheel pulverizers are most commonly used. There hot flue gases from the upper furnace are sucked for drying the wet fuel. The fuel is fed into the hot inlet duct and the drying fuel flue gas mixture passes trough the radial fan type pulverizer where the actual pulverizing takes place by gravitational force as the fuel clumps collide against the fan enclosure wall made of abrasion resistant wear parts. The upper part of the pulverizer has a classifier that allows only fine particles to pass and coarse fraction is recycled back to the pulverizing process. The maximum capacity of a single pulverizer is approximately 150-200 t/h i.e. 500 MW unit needs four-six pulverizers depending on the fuel design basis (8200 or 6000 kJ/kg). In order to have continuous operating capability there has to be one spare pulverizer as they need periodic maintenance at 3000-4000 hrs intervals as the Kosovan lignite is relatively “soft”.

Figure 3.1 Pulverizer arrangement in Kosovo B (Stein/Alstom)

Ball mill type pulverizer would make more uniform fuel powder for combustion but it has been less used with voluminuous soft and wet lignites. The high hot flue gas flow is one of the limiting factors in this respect. For large boilers tangential firing method is commonly applied and each pulverizer is feeding its own four burners i.e. one level at each corner. The burners fed by different


pulverizers are in stacked form either in the furnace corners or close to the corners to produce a swirl in the centre of the furnace. The burners are so called Low NOx-type where the combustion air is staged to reduce the absolute maximum temperatures in combustion thus effectively reducing the formation of thermal NOx. The burners may be either of a fixed or tilting type. In case of tilting burners they may be used to control for example the reheat steam temperature by raising or lowering the flame in the furnace. From the performance point of view it is a method without any loss to control that temperature. Another burner arrangement is to locate them on the front and rear walls. In that case the burners are fixed and one pulverizer feeds one level. The furnace size and height for this capacity size, 700 – 1200 MW heat release is such that the residence time for the particles is 6-8 seconds and the exit gas temperature around 1000 °C or below. The air pre-heaters are normally of rotary type and due to the volume of flue gas stream there are two parallel units each designed for 50 % flow. The steam boiler itself is either built in tower form or as two-pass unit. The furnace and the boiler walls in the hot sections are of membrane construction welded gastight. Tower format saves space as the super-, reheater and economizer heating surfaces are stacked above the furnace. The upper part of the boiler is split into two sections by a wall that also acting as a heating surface. The flue gas after the economizer are leaving high up and there has to be a duct to bring those flue gases down to the air preheaters. That duct is also an ideal location for placing a Selective Catalytic Reactor, SCR, for removal of nitrogen oxides whenever it is required. The flue gas temperature is there in the range of 400-350 °C and that is ideal for the operation of SCR. A a boiler of two-pass configuration will need slightly more space in longitudinal direction than the tower boiler but the benefit is that the connecting external pipelines are slightly shorter. Pulverized fired boilers are the largest conventional steam boiler units built today. Their maximum capacity is around 1100 MWe and steam parameters can go up to 300 bar/600-620 °C. The ash in fuel exits the furnace mostly in form of fly ash but a small fraction of the ash sticks onto the furnace walls and first heating surfaces. That slag is either removed by sootblowing (steam/air/water/acoustic) or just peeling off by its own weight. The slag is typically removed from the conical bottom through a wet slag drag chain conveyor. There might be a small grate type collection area before the actual conveyor for afterburning. The slag is cooled, crushed and transported by trucks/belt conveyors. During recent years the following large brown coal / lignite fired plants have been built in Europe: Plant Capacity MWe Year Neurath 2 x 1100 MW 2008 Niederaussem 1000 MW 2003 Boxberg 900 MW 2000 Lippendorf 2 x 933 MW 1999 Schwartze Pumpe 2 x 800 MW 1997/8 Schkopau 495 MW 1996


Regarding to the large lignite or brown coal fired boilers firing wet fuel the formation of the thermal nitrogen oxides is low due to the low actual combustion temperature in the furnace. If the nitrogen content of the fuel is low the large boilers can meet the requested EU/LCP-emission limit of 200 mg/nm3 with proper Low-NOx -burner design. The largest 800-1100 MW units can even go down to 150 mg/nm3 levels without any additional measures.

3.3 Circulating Fluidized Bed combustion

Fluidized bed combustion was initially developed for metallurgical purposes for roasting plants i.e. the combustible part of the feed material was removed and not to destroy/melt the base material which came out as ash. The combustion took place around 900 C. The partial introduction of combustion air underneath of the bed made it bubbling and that gave the name Fluidized Bubbling Bed, FBB. Gradually this bubbling bed technology was introduced for steam generation from high moisture content fuels as the bubbling bed offered ideal place for particles requiring long combustion time and the bubbling hot ash made the ignition of wet fuel simple. In the 1970´s and early 1980´s the concept was attracting more and more interest by the boiler makers but a major obstacle was that full scale coal combustion was not possible as it created too high combustion temperature and the ash in the bed melted and then solidified. It was recognized that by increasing the fluidizing air volume under the fluidizing grate the bed started to fly. Circulating Fluidized Bed, CFB, was born. In that concept the upward velocity in the furnace area is 4-6 meters and all the material follows with the flue gases up to a separator cyclone. There the heavy particles are separated and they are recycled back to the bed trough a loop seal/ash cooler. The clean flue gases leave the separator to the further heating surfaces. This concept made it possible to introduce necessary combustion air in stages at different levels of the furnace and maintain the combustion temperature at the prescribed 900-950 °C level even with dry coals. It also made possible to utilize high ash fuels as the bubbling bed is choked by the high ash.


Figure 3.2 Schematic diagram of CFB-boiler plant (Foster Wheeler)

It was also recognized that the combustion temperature of 850-950 °C is quite ideal for calcination of limestone to calcium oxide. Burnt CaO is capturing the sulphur of the the fuel during its combustion process. The end product is a mixture of calcium sulphite, CaSO3 and inert calcium sulphate,CaSO4, in the ash and the sulphur dioxide emission is effectively reduced straight in the boiler. The desulphurization process is not as effective as in the separate flue gas desulphurization process. Compared with S-moles, typically 3 times more Ca-moles are required to reach 90 percent desulphurization degree vs. that of 1,1-1,2 for a downstream FGD. However, the process is simple and needs not any additional equipment except the pulverized limestone feeding into the furnace. The low combustion temperature of CFB results also in low thermal NOx-formation as the emission almost exclusively comes from the nitrogen in the fuel. In this particular case as the lignite contains a substantial amount of limestone, CaSO4 and the sulphur content of the fuel is low (Ca/S mole ratio >5) it can be expected that the sulphur dioxide emission will be extremely low. Typically the coal injected into furnace shall have an average particle size of 1 mm and the maximum of 10 mm. There should not be more than 5 % fine particles of 0,05 mm or less. Crushing of the fuel is normally executed outside of the boiler house at the fuel yard. To start the operation the boiler needs sand to create the necessary inventory of the circulating hot mass for ignition. During its normal operation the fuel ash may be sufficient to maintain that inventory level. If the fuel ash is not able to upkeep the inventory level some (quarz) sand has to be added every now and then.


The fuel ash exits the boiler mostly (above 90 %) in the form of fly ash and the rest is taken out in dry form as bottom ash. If the fuel has a very high ash content (>30 %) special bubbling bed type ash coolers may be installed to remove and cool the excess bottom ash directly from the bed. Structurally the most critical parts of CFB-boiler are the fluidizing grate, separator/ hot cyclone and recycling system of the particles from the separator/hot cyclone. Those items can be briefly described: The separator/hot cyclone has experienced substantial evolution during these 25 years. Initially it was made of heavy refractory as its operating temperature is around 900 °C. It was an independent uncooled structure outside the furnace. The thick refractory did not allow fast start-ups and many hot cyclone failures occurred. Erosion was also an issue. Gradually more experience has been gained in this respect. Nowadays there are designs where the separator is integrated into the furnace and its walls are water cooled membranes protected by a thin refractory. Some manufacturers (Alstom, Kvaerner, AEE) still use separate water or steam cooled cyclones even for large capacities. This type of design requires more space than the integrated approach. The expansion bellows between the furnace and the hot cyclone have also been the critical parts but sufficient design approaches have been developed to cope with the issue. To recycle hot ash and fuel mixture from the hot cyclone back to the bed needs a control device “check valve” to prevent the fludizing air from disturbing this recycling process. Typically there is a seal pot that blocks the route and the flow to the right direction is controlled/assissted by small fludizing nozzles. Initially Lurgi, one of the main developers of the concept, placed some heating surfaces in the loop to cool the ash. Nowdays final superheaters can be located in this ash recycling loop (eg. Intrex by Foster Wheeler). The heat transfer is very effective from the hot ash directly to water/steam surfaces. There the heat surfaces are protected from possible corrosive elements in the flue gases. Regarding the maximum capacity of a CFB-boilers the development has been relatively fast: The first 100 MWe range utility type boilers firing coal were built in the late 1980´s and now there are several units in 250-300 MW range. The largest CFB in operation is hard coal fired 350 MW unit in Sulcis, Italy by Alstom. Foster Wheeler has built several units of 250 MW range burning wet brown coal (equal to Kosovo lignite) in Poland. All these boilers are designed for subcritical steam parameters i.e. 160-170 bar/540-565 °C with reheat. There is one supercritical CFB-project about to start in Lagiza, Poland. Foster Wheeler will deliver 460 MWe CFB-boiler plant for 260 bar/580 °C/580°C steam parameters. The fuel is conventional bituminuous coal (<23 % moisture). The maximum sulphur content is 1,2 %. The design will apply new OTU straight tube concept. The plant is due to start early 2009.

To summarize the status of the CFB-development it can be stated that it is proven technology up to 350 MW with subcritical steam parameters.


4 EMISSION CONTROLS

The following paragraphs are a summary on the presentation to be found on the web-site of IEA (October 2005).

4.1 Desulphurization

Flue gas desulfurization can be classified into the following six main categories: • wet scrubbers; • spray dry scrubbers; • sorbent injection processes; • dry scrubbers; • regenerable processes; and • combined SO2/NOx removal processes

FGD units are widely installed in many countries as the emission requirements become stricter. Wet scrubbers take the lead followed by spray dry scrubbers and sorbent injection systems in the FGD market throughout the world. Regenerable and combined SO2/NOx processes have a small share and the trend is not expected to change in the short-term according to current plans for new FGD installations. New developments in sorbent injection technologies are in progress and this type of FGD is expected to become more widely used in older coal fired plants.

4.2 Wet scrubbers for SO2 control

Wet scrubbers are the most widely used FGD technology for SO2 control throughout the world. Calcium-, sodium- and ammonium-based sorbents have been used in a slurry mixture, which is injected into a specially designed vessel to react with the SO2 in the flue gas. The preferred sorbent in operating wet scrubbers is limestone followed by lime. These are favoured because of their availability and relative low cost. The overall chemical reaction, which occurs with a limestone or lime sorbent, can be expressed in a simple form as: SO2 + CaCO3 = CaSO3 + CO2 In practice, air in the flue gas causes some oxidation and the final reaction product is a wet mixture of calcium sulphate and calcium sulphite (sludge). A forced oxidation step, in situ or ex situ (in the scrubber or in a separate reaction chamber) involving the injection of air produces the saleable by-product, gypsum, by the following reaction: SO2 + CaCO3 + 1/2O2 + 2H2O = CaSO4.2H2O + CO2 Waste water treatment is required in wet scrubbing systems. A variety of scrubber designs is available including:

• spray tower • plate tower • impingement scrubber • packed tower design • The fluidized packed tower


In the simplest configuration in wet lime/limestone/gypsum scrubbers, all chemical reactions takes place in a single integrated absorber resulting in reduced capital cost and energy consumption. The integrated single tower system requires less space thus making it easier to retrofit in existing plants. The absorber usually requires a rubber, stainless steel or nickel alloy lining as construction material to control corrosion and abrasion. Fibreglass scrubbers are also in operation. Commercial wet scrubbing systems are available in many variations and proprietary designs. Systems currently in operation include:

• lime/limestone/sludge wet scrubbers; • lime/limestone/gypsum wet scrubbers; • wet lime, fly ash scrubbers; and • other (including seawater, ammonia, caustic soda, sodium carbonate, potassium

and magnesium hydroxide) wet scrubbers. Wet scrubbers can achieve removal efficiencies as high as 99%. Wet scrubbers producing gypsum will overtake all other FGD technologies, especially with the increased cost of land filling in Europe and the introduction of increasingly stricter regulations regarding by-product disposal. Figure 4.1 presents the process.

Figure 4.1 Wet scrubber SO2 removal process / “Wet gypsum process” (Scholven)

A wet desulphurization process needs a considerable amount of auxiliary power and that typically adds 1,5-2,0 %-points to the auxiliary power figure. If a conventional stack is used to discharge the flue gases they have to be reheated after the process up to 100 °C by a rotary preheater taking its heat from the flue gases entering the desulphurization process. In a case where the flue gases are taken into an evaporative cooling tower the flue gases can be taken directly without any preheating.

Lot 1, Task 3 February 6, 2006 Technology review Page 17 (37) 4.3 Spray dry scrubbers for SO2 control

Spray dry scrubbers require the use of an efficient particulate control device such as an ESP or fabric filter. A recycling facility would improve sorbent utilisation and disposal of the by-product is the norm. The sorbent usually used is lime or calcium oxide. The lime slurry, also called lime milk, is atomised/sprayed into a reactor vessel in a cloud of fine droplets. Water is evaporated by the heat of the flue gas. The residence time (about 10 seconds) in the reactor is sufficient to allow for the SO2 and the other acid gases such as SO3 and HCl to react simultaneously with the hydrated lime to form a dry mixture of calcium sulphate/sulphite. Waste water treatment is not required in spray dry scrubbers because the water is completely evaporated in the spray dry absorber. The by-product also contains unreacted lime which may be recycled and mixed with fresh lime slurry to enhance sorbent utilisation as not all of the lime reacts with the SO2. Factors affecting the absorption chemistry include flue gas temperature, SO2 concentration in the flue gas and the size of the atomised or sprayed slurry droplets. The absorber construction material is usually carbon steel making the process less expensive in capital costs compared with wet scrubbers. However, the necessary use of lime in the process increases its operational costs. Spray dry scrubbers are the second most widely used FGD technology. However, their application is limited to flue gas volume from about 200 MWe plants on average. Larger plants require the use of several modules to deal with the total flue gas flow. This is why in general the technology is used in small to medium sized coal fired power plants. Spray dry scrubbers in commercial use have achieved removal efficiency in excess of 90% with some suppliers giving >95% SO2 removal efficiency as achievable.

Figure 4.2 Process diagram for Spray dry scrubber based SO2 control

Lot 1, Task 3 February 6, 2006 Technology review Page 18 (37) 4.4 Sorbent injection systems for SO2 control

Sorbent injection systems can be divided into four types. These are: • furnace sorbent injection; • economiser sorbent injection; • duct sorbent injection; and • hybrid sorbent injection.

The simplest technology is furnace sorbent injection where a dry sorbent is injected into the upper part of the furnace to react with the SO2 in the flue gas. The finely grained sorbent is distributed quickly and evenly over the entire cross section in the upper part of the furnace in a location where the temperature is in the range of 750-1,250°C. Commercially available limestone (CaCO3) or hydrated lime (Ca(OH)2) is used as sorbent. Whilst the flue gases flow through the convective pass, where the temperature remains above 750°C, the sorbent reacts with SO2 and O2 to form CaSO4. This is later captured in a fabric filter or ESP together with unused sorbent and fly ash. Removal efficiency of up to 50% can be obtained with a Ca/S ratio of 2 with Ca(OH)2 used as sorbent. If CaCO3 is used as sorbent the removal efficiency will be considerably lower, or the Ca/S ratio will have to be much higher. In an economiser sorbent injection process, hydrated lime is injected into the flue gas stream near the economiser zone where the temperature is in the range of 300-650°C. In duct sorbent injection, the aim is to distribute the sorbent evenly in the flue gas duct after the preheater where the temperature is about 150°C. At the same time, the flue gas is humidified with water if necessary. Reaction with the SO2 in the flue gas occurs in the ductwork and the by-product is captured in a downstream filter. Removal efficiency is greater than with furnace sorbent injection systems. An 80% SO2 removal efficiency has been reported in actual commercial installations. The hybrid sorbent injection process is usually a combination of the furnace and duct sorbent injection systems aiming to achieve higher sorbent utilisation and greater SO2 removal. Various types of post furnace treatments are practised in hybrid systems, such as:

• injection of second sorbents such as sodium compounds into the duct; and • humidification in a specially designed vessel.

Humidification reactivates the unreacted CaO and can boost SO2 removal efficiency up to 90% depending on the process. The hybrid process offers the following advantages: relatively high SO2 removal;

• low capital and operating costs; • easy to retrofit; • easy operation and maintenance with no slurry handling; • reduced installation area requirements due to compact equipment; and • no waste water treatment.

4.5 Dry scrubbers for SO2 control

Circulating fluid bed and moving bed technologies, which utilise a dry sorbent to reduce SO2 emissions in a flue gas stream in a dedicated reaction chamber are categorised as dry scrubbers.


In the circulating fluid bed (CFB) dry scrubber process, hydrated lime is injected directly in the CFB reactor. Water is also injected into the bed to obtain an operation close to the adiabatic saturation temperature. The process achieves SO2 removal efficiency of 93-97% at a Ca/S molar ratio of 1.2-1.5. Flue gas enters the CFB reactor at the bottom, then flows vertically upwards through a venturi section and enters an upper cylindrical vessel. The height of the vessel is designed to accommodate the mass of bed-material required to achieve the desired residence time of about three seconds. All external inputs of recirculating material, fresh sorbent and gas humidifying water are introduced to the gas on the diverging wall of the ventur. The process is easy to maintain and operate because it does not require high-maintenance mechanical equipment such as abrasion resistant slurry pumps, water atomisers or sludge dewatering devices. The process can achieve >95% SO2 removal efficiency. In the moving bed dry scrubber, a dry absorbent made of coal ash and lime is injected into the absorber. There is currently one plant using this technology and achieving 90% SO2 removal efficiency.

4.6 Regenerable processes for SO2 control

In regenerable processes, the sorbent is regenerated chemically or thermally and reused. Elemental sulphur or sulphuric acid is recovered from the SO2 removed. The revenue from these by-products can compensate partially for the higher capital costs required in such FGD systems. Although these processes can achieve high SO2 removal efficiencies (>95%) they have in general high capital costs and power consumption.

4.7 Combined SO2/NOx removal processes

Combined SO2/NOx removal processes remain considered fairly complex and costly. However, emerging technologies have the potential to reduce SO2 and NOx emissions for less than the combined cost of conventional FGD B for SO2 control and selective catalytic reduction (SCR) B for NOx control. Most processes are in the development stage, although some processes are commercially used on low to medium-sulphur coal fired plants.


Figure 4.3 Combined NOx/SO2 removal system

4.8 NOx-controls Flue gas treatment for NOx control can be categorised into three areas: • selective catalytic reduction (SCR) • selective non-catalytic reduction (SNCR) • combined SO2/NOx control systems

4.9 Selective catalytic reduction (SCR) for NOx control In SCR systems, ammonia vapour is used as the reducing agent and is injected into the flue gas stream, passing over a catalyst. NOx emission reductions over 80-90% are achieved. The optimum temperature is usually between 300°C and 400°C. This is normally the flue gas temperature at the economiser outlet. The catalysts can have different compositions: based on titanium oxide, zeolite, iron oxide or activated carbon. Most catalysts in use in coal fired plants consist of vanadium (active catalyst) and titanium (used to disperse and support the vanadium) mixture. However, the final catalyst composition can consist of many active metals and support materials to meet specific requirements in each SCR installation. SCR technology has been used commercially in Japan since 1980 and in Germany since 1986 on power stations burning mainly low-sulphur coal and in some cases medium-sulphur coal. There are now about 15 GWe of coal fired SCR capacity in Japan and nearly 30 GWe in Germany, out of a total of about 53 GWe worldwide. During the


1990s SCR demonstration and full scale systems have been installed in US coal fired power plants burning high-sulphur coal. Their commercial use has followed the introduction of stringent limits to regulate NOx emissions in each country.

4.10 Selective non-catalytic reduction (SNCR) for NOx control

In SNCR systems, a reagent is injected into the flue gas in the furnace within an appropriate temperature window (between 900°C and 1100°C). Emissions of NOx can be reduced by 30% to 50%. The NOx and reagent (ammonia or urea) react to form nitrogen and water. A typical SNCR system consists of reagent storage, multi-level reagent-injection equipment, and associated control instrumentation. The SNCR reagent storage and handling systems are similar to those for SCR systems. However, because of higher stoichiometric ratios, both ammonia and urea SNCR processes require three or four times as much reagent as SCR systems to achieve similar NOx reductions. SNCR technologies came into commercial use on oil- or gas fired power plants in Japan in the middle of the 1970s. In Western Europe, SNCR systems have been used commercially on coal fired power plants since the end of the 1980s. In the USA, SNCR systems have been used commercially on coal fired power plants since the early 1990s.

4.11 Combined SO2/NOx removal processes

Combined SO2/NOx removal processes remain considered fairly complex and costly. However, emerging technologies have the potential to reduce SO2 and NOx emissions for less than the combined cost of conventional FGD B for SO2 control and selective catalytic reduction (SCR) B for NOx control. Most processes are in the development stage, although some processes are commercially used on low to medium-sulphur coal fired plants.


5 STEAM TURBINES

Main parameters guiding the steam turbine construction are: • Admission steam parameters • Reheat steam parameters • Cold end optimisation • Manufacturers proven design These factors define the selection of steam turbine construction materials, number of casings and turbine process thermal efficiency potential. The investment cost develops in steps following the changes in the materials, number of turbine casings, and size of the casing. Turbine casings and shaft are standard components that are designed for limited process parameters while the steam path is tailored for each case. Turbine process efficiency develop partly linearly following the process parameter development and partly in steps following the number of feed heating stages and selection of LP last stage selection and number of steam turbine casings.

5.1 Material selection

In general the steam inlet parameters define the turbine material selection. The steam admission pressure mainly effect to the pressure casing construction while the temperature effect to material selection. It shall though be understood that the steam admission parameters are always an optimised pair where benefit of one parameter depend on the other. Increasing only pressure does not improve the efficiency unless the temperatures follow with the pressure and visa versa. In the unit size in question the turbine high pressure steam path from steam admission to cold reheat - and intermediate steam path from hot reheat to the low pressure casing inlet may be in one integrated HP/IP casing or in two separate casings. The main key factor in the casing construction is the main steam parameters – mainly pressure. In case conventional pressures – that is drum boiler pressures up to <170 barabs are used the most common solution is one combined HP/IP casing while supercritical steam parameters usually require separate high pressure and intermediate pressure casings. Supercritical steam pressures mean usually separate HP and IP casings. Separate or common HP and IP casings is turbine manufacturers strategic decisions and some vendors have chosen the construction where there are always separate casings for the main steam admission and hot reheat steam. The expansion in the turbine steam path with the selected steam parameters and one reheat passes far above the erosion-corrosion area (today known better as FAC = Flow Assisted Corrosion). Also the cooling tower cold end mean relatively warm cooling water and exhaust steam moisture content remain relatively low (7…10 % moisture).


Erosion-corrosion does not effect to the LP steam path and casing material selection, but though LP turbine exhaust moisture is moderate it is still proposed that protection measures against last turbine stage water drop erosion are applied. Such measures are mechanical moisture removal through grooves in the last LP guide vanes and flame hardening of the last rotating stages. Last rotating stages of Titanium are expensive solution, but are also durable against water drop erosion. The cold end optimisation may also result one casing LP turbine with longest LP last stages – which are usually of titanium because of the better strength/weight ratio. Using of titanium is though not necessity and shall be left to the turbine manufacturer’s decision.

5.2 Steam turbine High pressure and Intermediate pressure casings 300 MW Unit 300 MW net unit size is still a little bit small to fully utilize supercritical steam parameters. The main factor is steam volumetric flow at the HP steam path first stages. The steam volumetric flow is so small that the turbine blade length is relatively small and the tip and root losses decrease the expansion efficiency from supercritical pressures to conventional pressure. Benefit from more advanced steam parameters are partly eliminated by the losses due too small volumetric flow. Nevertheless supercritical steam parameters are not here exclude as an alternative, but the benefit of such steam parameters are limited in 300 MW unit size. CFB technology does not have references other than drum boiler type units. This mean moderate steam parameters meaning pressures <170 barabs and temperatures optimal to this main steam pressure level (< 560 °C). Considering both the unit size and combustion technology it seem obvious that the 300 MW unit will be with sub-critical type main steam parameters being 165 – 200 barabs 545-560 °C and intermediate steam pressures 35-45 barabs 545-560 °C. High pressure and Intermediate pressure steam paths will probably be in one common casing. 500 MW Unit In 500 MW net unit size the CFB technology may not be considered due lack of references. The main steam flow does support the utilizing of supercritical steam parameters. Due lack of references of very high steam parameters main steam parameters shall anyhow be limited to 245 barabs 560/560 °C. In steam turbine the 560 °C temperature does not request very high grade materials. Basically these temperatures could even be handled with conventional 1-2 % Cr steel – at least 12 % steel is though preferred to be used for the steam path blading. In case of welded rotor construction the steam admission part and first stages could preferably be of more heat resistant material though this is an advantage of the construction and not necessity. Supercritical steam parameters mean separate High pressure and Intermediate pressure casings as basic solution.

5.2 Number of LP turbine casings 300 MW unit: Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 300 MW net unit only one LP casing solution is quite probable. The key


issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 300 MW units with only one two flow LP casing. 500 MW unit: Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 500MW net unit only one LP casing solution is quite possible though optimal solution may also be two LP casing solution. The key issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 500 MW net units with only one two flow LP casing but this will request increased exhaust pressure and large losses in the cold end.

5.4 Turbine condenser

A cooling tower has been selected as the plant’s main cooling system. As is enough water available the tower type will be wet cooling tower. In wet cooling tower – like in once through cooling – the shell and tube type main condenser is basically the only solution. Shell and tube type vacuum condenser is also in general the most commonly used condenser type. In the shell and tube surface condenser the steam is exhausted from the turbine LP section into the condenser steam chamber through which the cooling water pipes are routed in tube bundles. Steam is condensed on cooling water tube outer surfaces and the condensed water is removed by gravity force downwards to the bottom of the condenser corpus where the condensate hotwell is located. The system is proven and reliable and well adapted to various load cases from back-pressure load to full condensing load. It is easy to adopt the bypass steam supply to this type of condenser. The number of cooling water flows determines the number of independent flows into which the cooling water supply is divided in the condenser. Each flow will then consist of a large number of cooling water tubes. Main condenser ought to have at least two flows. Each shall be such that it may be separated from the water side for cleaning or plugging of ruptured cooling water tube.

5.3 Material Selection

The main condenser surfaces are in contact with ambient air (shell), main cooling water (tubes and water chambers) and circulating steam/water (tubes, shell and hotwell). The chemical composition of these elements is decisive for the selection of materials to be used.

Condenser tubes The main cooling water will come from the wet cooling tower. The composition of cooling water is decisive when selecting main condenser tubes. In general, the material properties of the compared tube material with assumed cooling water quality may be simplified as follows:


Table 5.1 Material properties of the compared tube materials

General Corrosion

(2)

Pitting in Running Water

Pitting in Stagnant

Water

Pitting / Stress Corr.

Erosion Corr. (WTR side)

Water Drop

erosion

Stainless steel (*) +++ ++ ++ ++ +++ +++

Copper based + + + + + +

Titanium +++ +++ +++ +++ ++ +++ (*) Grade AISI 316L or better +++ Best resistance in comparison to the other two alternatives + Lowest resistance in comparison to the other two alternatives Stainless steel (SS) tubes have in general better resistance against corrosion than copper based materials. Also, SS resistance against water drop erosion is better than copper alloy’s. Titanium has very good properties and good references but is not used here because its price is very high and because the high grade stainless steel has sufficiently good mechanical properties and is significantly cheaper at the same time. As the chlorine content of the main cooling water is estimated to reach values of 90 .. 140 ppm, the SS tube material AISI 316L will be considered. AISI 304 should not be used if the chlorine content of the cooling water exceeds 70 ppm.

5.5 Generator

The maximal reliable and proven size of the air cooled generators has been increasing continuously. Most generator manufacturers have expanded their line of air cooled generators close to the 300 MW unit size. Also the efficiency of the air cooled generator have been increasing so that in the 300MWenet unit size the most efficient air cooled generators have closely the same efficiency as the hydrogen cooled generators have in general. Due there are no hydrogen system and thereby no sealing oil systems etc. the operational costs of the air cooled generators are lower then the hydrogen cooled generators. Based on the marginal efficiency difference and higher operation costs the air cooled generator is more probable solution in the 300 MW unit. Due the lack of references of air cooled generator in the 500 MW size hydrogen cooled generator remain only alternative in the 500 MW unit.


6 IGCC (INTEGRATED GASIFICATION COMBINED CYCLE)

6.1 Background

The basic IGCC process consists of the following functions; gasifying coal to produce synthetic gas (syngas), burning the gas in a power producing gas turbine and using the hot exhaust gas from the gas turbine to produce power in a steam water cycle process. Thus the IGCC process is basically a combination of two well known processes, 1) coal gasification process and 2) gas fired combined cycle power plant process. The gas fired combined cycle process is commonly used in natural gas fired power plants in utility and industrial power plants. The characteristics of the process are high power production efficiency and low NOx emissions compared to the Rankin cycle process. The coal gasification has been known for a long time now. The first larger coal gasification applications were implemented already during the Second World War in Germany to produce transportation fuel. But the process has not made an actual break through in normal market conditions because of the relatively high investment cost of the gasification process and good availability of Oil and Natural Gas throughout the world. Integrated coal gasification combined cycle process development started in the US during the first oil crisis in the 1970’s. The development and demonstration projects were resulted with three 120 MWe class IGCC plants by 1987. The primary driver for starting to develop and build IGCC plants was the potential of combining the benefits of having a cheap and abundant domestic fuel to the efficiency of the combined cycle process. At the same time low cost natural gas supply grew fast and natural gas fired combined cycle plants that did not require any investments to a gasification plants offered a more attractive solution at the time and were built extensively. On the other hand the pressure to shift from the Rankin cycle process to IGCC in coal based power production decreased as critical and supercritical steam values were applied in the Rankine cycle process increasing its power production efficiency to the same level that had been achieved with IGCC. More recently IGCC has been discussed again as it offers lower cost for CO2 capture than the Rankin cycle process and also because it still has potential for achieving higher efficiency than the Rankin Cycle process even if it has not been achieved yet. The following paragraphs are mostly based on the recently published report “An Overview of Coal based Integrated Gasification Combined Cycle (IGCC) Technology by MIT (LFE 2005-002 WP).

6.2 Process description

Figure 4 shows the main blocks of a coal based IGCC plant. The coal is supplied to the gasifier where it is partially oxidized under pressure (30-80 bar). The plant uses oxygen as oxidant and therefore has an air separation unit (ASU). In the gasifier, which is of the entrained flow slagging type, the temperature may exceed 1500 °C. The high


temperature ensures that the ash is converted to a liquid slag with low vis-cosity, so that it may easily flow out of the gasifier.

Figure 6.1 IGCC process without CO2 capture

In addition to its chemical energy (heating value), the hot raw syngas contains sensible heat which may be recovered in heat exchangers to produce steam for the steam turbine. In the gas clean up process, particles, sulphur and other impurities are removed. At this point, CO2 may also be captured. Because of the high partial pressures of the species and the low volume flow of syngas, the gas clean up process is very efficient and low cost compared to traditional flue gas cleaning. The clean syngas is then fed to the gas turbine for generation of electricity. Gas turbines for syngas operation are commercially available. Compared to natural gas operation, some minor modifications in combustors and operating conditions are required. The gas turbine may also be integrated in two different ways with the ASU. If not conflicting gas turbine operation characteristics, any excess nitrogen from the ASU should always be utilized by the gas turbine for NOx reduction and increased power generation. Most of the sensible heat in the hot gas turbine exhaust gas is recovered in the heat recovery steam generator (HRSG) which supplies the steam to a turbine for additional electricity production. The separation between different IGCC processes is based on the differences between gasification technologies and whether CO2 is captured or not.

6.3 Classification of gasifiers

A number of gasifier technologies have been developed to various extents, and they may be classified as shown in Table 1 below. Operating temperature for the different gasifiers is to a large extent dictated by the ash properties of the coal. Depending on the gasifier, it is desirable either to remove the ash dry at lower temperatures (non-slagging gasifiers) or as a low viscosity liquid at high temperatures (slagging gasifiers). For all


gasifiers it is essential to avoid that soft ash particles stick to process equipment and terminate operation. Table 6.1 Characteristics of different gasifier types// source: C. Higman and M. van der Burgt, “Gasification”, Elsevier, 2003

Gasifier type Fixed bed Fluidized bed Entrained flow Outlet temperature

Low (425-600 °C) Moderate (900-1050 °C)

High (1250-1600 °C)

Oxidant demand Low Moderate High Ash conditions Dry ash or slagging Dry ash or

agglomerating Slagging

Size of coal feed 6-50 mm 6-10 mm < 100 µm Acceptability of fines

Limited Good Unlimited

Other characteristics

Methane, tars and oils present in syngas

Low carbon conversion

Pure syngas, high carbon conversion

Fluidized bed gasifiers are less developed than the two other gasifier types. Operating flexibility is more limited for this class of gasifiers because of performing several functions (e.g. fluidization, gasification, sulfur removal by limestone injection) at the same time, and there are too few independent variables for the desired process optimization. Still the fluidized bed technology perhaps offers better potential for utilizing low rank coals with high ash and moisture content. The four major commercial gasification technologies are (in order of decreasing capacity installed):

1. Sasol-Lurgi Dry Ash 2. GE (originally developed by Texaco) 3. Shell 4. ConocoPhillips E-gas (originally developed by Dow)

6.4 Performance without CO2 capture

6.4.1 Efficiency Electrical efficiencies around 40 % (LHV) have been achieved in existing commercial scale demonstration plants. Because the power block of an IGCC plant is similar to that of a natural gas combined cycle (NGCC) plant, the efficiency of the latter is a natural reference for the IGCC plant. Currently, NGCC efficiencies are approaching 60 % (LHV). The efficiency penalty of an IGCC compared to an NGCC is mainly explained by effects in the gasification process. In order to reach the slagging temperatures, the fuel is partially combusted which means that chemical energy is converted into heat. The ratio of the chemical energy in the product syngas and the chemical energy in the coal feed (LHV cold gas efficiency) is typically around 0.7–0.8. Depending on configuration, some of the produced heat may or may not be recovered. Either way, a significant


efficiency penalty or energy loss arises because heat is a lower quality energy form than chemical energy. Furthermore, the production of the oxygen for gasification requires auxiliary compression work. In addition to these major points, current IGCC gas turbines may be less efficient because of restrictions in turbine firing temperatures. Several factors influence the efficiency: Coal type: Coals of high rank can be gasified more efficiently than coals of low rank. The higher moisture and ash content of low rank coals require a higher degree of oxidation (more oxygen) to achieve slagging temperatures because of the energy needed to vaporize the moisture and melt the ash. Most recent studies have focused on high rank coals. Gasification technology: Gasifiers with a dry feed are more efficient than gasifiers with a slurry feed because less water must be vaporized. Gasifier technologies which include syngas coolers for heat recovery of the sensible heat of the hot gas, are more efficient than those with a water quench. Degree of ASU integration: Integration of the air separation unit with the gas turbine increases the electrical efficiency. By supplying part or all of the ASU air from the GT compressor outlet, less efficient compression in a separate compressor is reduced or avoided. Technology level: Gas turbine technology and turbine inlet temperature will together with the choice of steam cycle have a significant impact on electrical efficiency. While the three first bullets addresses the efficiency gap between an IGCC and an NGCC, the last bullet points to the fact that improvements in combined cycle technology will also benefit the IGCC. A review of recent studies of IGCC plants indicates efficiencies in the range 38.0-47.4 % (LHV). The wide range is explained by the above factors. Availability The risk of low IGCC availability is still an issue. Figure 2 shows the history of availabilities for the demonstration IGCC plants. It can be seen that most of the plants were able to reach the 70-80 % range after a number of years. However, by adding a spare gasifier, it seems likely that IGCCs can provide availabilities equivalent to that of NGCCs. At the Eastman Chemicals plant the gasifier has been 98 % onstream over a three year period. According to Bechtel, a next IGCC plant should be able to achieve around 85 % availability without back-up fuel or a spare gasifier.


Figure 6.2 IGCC availability history (excluding operation on back-up fuel). Graph provided by Jeff Phillips, EPRI

Environmental performance An inherent advantage of the IGCC process is the potential for low emissions by using fuel gas clean up – instead of flue gas clean up. Because of the high partial pressures, impurities can be removed more effectively and economically compared to conventional clean up of the large volume flow of the combustion flue gas. Table 6.2 Environmental performances

Pollutant/ Environmental issue

Performance

SO2 Commercial processes such as MDEA and Selexol can remove more than 97 % of the sulfur so that the clean syngas has a concentration of sulfur compounds < 20 ppmv. The more expensive Rectisol process can similarly achieve a concentration of < 0.1 ppmv. SO2 emissions of 68 g/MWh has been demonstrated at the ELCOGAS plant in Puertollano, Spain

NOx The emissions are similar to those of a natural gas fired combined cycle plant. Dilution of syngas with nitrogen and water are used to reduce flame temperatures and lower thermal NOx

formation to levels < 15 ppm

4 . Further reduction to single digit levels are

possible with selective catalytic reduction (SCR), but have some disadvantages such as ammonia slip, increased requirement for sulfur removal and reduced power output.

Mercury Commercial technology for mercury removal is available. 99.9 % removal from syngas has been demonstrated. The cost of Mercury removal has been estimated to $ 7 522/ kg for IGCC vs. $ 83 333/


kg for PC plants.

Other emissions

Emission of CO is caused mainly by incomplete combustion in the gas turbine. Permit levels are typically 15 ppm. VOC5

emissions also result from incomplete combustion, and compliance with permit levels is normally done by calibrating VOC emissions to CO emissions. PM6 includes solid charcoal and slag particles and liquid drops from cooling tower operation.

Trace elements

A large number of the periodic table is present in coals in trace amounts, and currently there is an incomplete understanding of how these trace elements partition between the slag, fly ash, syngas and gas clean up streams.

Solid wastes IGCC produces about half the amount compared to conventional PC plants. The solid waste is also less likely to leach toxic metals which are encased in the solidified slag [30]. The slag is a useful by product with a value.

Water use IGCC use 20 % - 50 % less water than conventional coal plants. The reason is that the steam cycle represents a smaller part of power generated.

4Short for ppmvd@15% (parts per million dry at 15 % O2) 5Volatile organic compounds 6Particulate

matter Key IGCC technology issues Gasifiers The range of choices in gasifier technology may be represented by the slurry feed GE gasifier with a water quench and no heat recovery versus the dry feed Shell gasifier with syngas coolers. This results in the GE gasifier having lower costs, but also lower efficiencies. For high rank coal (bituminous coal), studies conclude that the slurry feed GE quench gasifier has lowest capital cost for plants without and with CO2 capture. For low rank coals such as lignite, less data are available, but the Shell gasifier seems to be the lower cost option. For an IGCC based on the slurry feed E-gas gasifier, Table 2 shows that both the efficiency (heat rate) and the capital cost is affected significantly by the increased moisture and ash content of the lower rank coals such as lignite. Although data are not available for the less efficient GE gasifier, it seems likely that the negative impact of coal rank would be similar or worse. A study by the Canadian Clean Power Coalition indicated that the dry feed Shell gasifier was the more economical than slurry feed E-gas and GE gasifiers for an IGCC with CO2 capture. If this is the case, the Shell gasifier would also be more economical for a plant without capture. This latter point is explained by the higher penalty of Shell IGCCs for CO2 capture. Table 6.3 Effect of coal type on E-gas IGCC systems. Adapted from

Coal type Pittsb. #8 Illinois #6 PRB Lignite


Heatin value, Btu/lb (HHV ar) 13100 11000 8200 7500 Ash %, dry basis 7.5 12.5 17 20 Slurry conc. (% dry solids) 66 63 56 50 Relative feed rate 1 1.25 1.8 2 Number of gasifiers 2 2 3 4 Relative heat rate, Btu/kWh HHV (Base 3830) 1.00 1.06 1.14 1.22 Relative capital cost, (per kW) 1.00 1.09 1.24 1.39

Gas turbines Gas turbines need only minor modifications to use syngas as fuel and are available from manufacturers like GE and Siemens. There are some effects of using syngas as fuel which influences the gas turbine performance. Because of the low heating value of syngas, more mass flow of fuel is supplied to achieve a certain limiting turbine inlet temperature. In addition nitrogen from the ASU and syngas saturation contribute to higher mass flow through the turbine and more power output. Compared with the natural gas as fuel, depending on syngas composition, there may be a higher fraction of water vapor in the gas turbine exhaust. This will increase heat transfer and put more strain on materials, and it will be required to decrease the turbine inlet temperature to maintain design material life. This reduction means a lower efficiency for the power block. Maturity Experience with coal based IGCC plants on commercial scale exist from a few demonstration projects with government support (see Table 3). Table 6.4 Commercial scale coal/petcoke based IGCC demonstration plants

Project participant/ Plant name

Location Electric output (net)

Gasifier type

(current owner)

Gas turbine

Dates of operatio

n

Southern California Edison/ Cool Water

Barstow, CA 100 MW GE with heat recovery GE 7E 1984 -

1988

Dow (Destec)/LGTI

Plaquemine, LA 160 MW ConocoPhilli

ps E-gas

Siemens SGT6-3000E

1987 - 1995

Nuon/ Nuon Power

Buggenum, The 253 MW Shell Siemens

SGT5-1994 - present


Buggenum Netherlands 2000E

Destec and PSI Energy/ Wabash River

West Terre Haute, IN 262 MW ConocoPhilli

ps E-gas GE 7FA 1995 - present

Tampa Electric Company/ Polk Power Station

Mulberry, FL 250 MW GE with heat recovery GE 7 FA 1996 -

present

Elcogas/ Puertollano

Puertollano, Spain 298 MW Prenflo

Siemens SGT5-4000F

1998 - present

Sierra Pacific Power Company/Pinon Pine

Reno, NV 99 MW KRW air

blown fluidized bed

GE 6FA

1998 – 2000 (18 start-up

attempts, failed to achieve steady state

operation)

In 2004, several commercial alliances formed to offer IGCC customers “one stop shopping” in the future. GE purchased ChevronTexaco’s gasification business and announced cooperation with Bechtel. ConocoPhillips announced a similar alliance with Fluor. Also, Black & Veatch joined Uhde for execution of Shell gasification projects in the US. All the components needed in an IGCC plant are commercially available. Several demonstration projects based commercial gasifiers have been carried out and they have shown that problems have occurred – but also that they have been manageable. Performance with CO2capture When considering capture of CO2 in the IGCC design, two additional process blocks are needed (besides the compression of CO2 for transportation): A shift reactor in which the CO reacts with H2O to H2 and CO2 An absorption process for capture using the Selexol process or other processes based on physical solvents, or an MDEA process based on chemical solvents In the shift reactor, the heating value of the CO is transferred to H2 and the carbon atoms end up in the CO2 molecules. It has been found that a so called sour shift up-stream the sulfur removal. The reduction in electrical efficiency for a plant with CO2 capture is explained by the following factors: Exothermic shift reaction produces heat from syngas fuel and required coal feed rate to provide necessary rate of chemical fuel energy to the gas turbine increases. The produced heat is less efficiently converted to electricity than chemical energy (fuel heating value). If steam/carbon ratio is to low (as for Shell gasifiers), steam must be supplied from the steam cycle and is equivalent to an electricity production loss


CO2 compression work If a chemical solvent such as MDEA has been used (as opposed to a physical Selexol solvent), there is also a significant energy loss for regeneration of the solvent. Restrictions on the firing temperature of current gas turbines will also result in an efficiency reduction. For example, one study showed that the efficiency penalty (LHV) for a case with the GE gasifier was 6.5 %-points (from 38.0 % to 31.5 %), and 8.6 %-points (from 43.1 % to 34.5 %) for the Shell case. Most processes required for CO2capture from IGCCs have been demonstrated at commercial scale. For example, commercial chemical plants for production of ammonia require hydrogen and therefore include a shift reaction and separation of CO2. An advanced gas turbine (F class or higher) has not been demonstrated on near 100 % hydrogen fuel. However, for an IGCC application which involves an air separation unit, there is no reason to combust a pure hydrogen stream in the turbine, rather it is beneficial to dilute with nitrogen to reduce NOx emissions and increase power output. Current GE guarantees involve fuel specifications, which limit maximum CO2 capture to around 85 %. According to Norman Shilling, GE these limitations are related to the current fuel supply system and does not represent a major challenge to modify. A fuel mixture of 50 % H2 and 50 % N2 by volume would be an acceptable fuel and would therefore impose no limitation on CO2capture.

6.5 Capital cost and performance in lignite based IGCC

When the power generation is based on high quality coal, the net power generation efficiency of different IGCC processes varies between 42% and 46% and the investment cost is around € 1200 per kWe. The gasification of low rank coal offers considerably worse net efficieny (see Table 2), the relative heat rate being around 1.22 compared to gasification of high rank coal. Thus the net efficiency for lignite based IGCC generation should be around 34%-38%. Lignite based IGCC requires also higher investment for the gasification process. The share of the gasifying process is generally around 50% of the total IGCC investment, when the production is based on high rank coal. Lignite gasification requires higher investment cost, the relative capital cost for lignite gasifier being ~1.49 (see Table 2) compared to a high rank coal gasifier. Thus the investment cost should be around € 1500 per kilowatt for a IGCC plant utilizing lignite. (50% x 1200 + 1.49 x 50% x 1200 = 1500).

6.6 Conclusions

In order to compete with pulverized coal plants or CFB coal plants, the major challenges for new large IGCCs will be to demonstrate higher availabilities and lower capital costs. The capital cost compared to a CFB plant is especially high in a case where low rank coal such as the Kosovo lignite is used. Thus unless the IGCC investment costs drops dramatically and higher availabilities are realized the only feasibility argument for favoring IGCC over Rankin Cycle based power generation is the easier and cheaper capture of CO2. However so far in most cases the CO2 capturing option does not offer


any advantage as there is no use for the CO2 and the capturing and storing cost (€ 40-60 per ton) is well above the cost of purchasing CO2 emission rights (€ ~20 per ton).


7 PRESSURIZED FLUIDIZED BED COMBUSTION (PFBC)

FBC in boilers can be particularly useful for high ash coals, and/or those with variable characteristics although PFBC has also been used on a commercial scale in Sweden and Japan with traded coals of higher quality. It is used with a combined cycle system incorporating both steam and gas turbines. Considerable effort has been devoted to the development of PFBC during the 1990s, and the other demonstration units were in Germany, Spain and the USA. The following chapters are a summary from the presentation in the IEA website. FBC in pressurized boilers can be undertaken in compact units, and can be potentially useful for low grade coals and those with variable characteristics. As with atmospheric FBC, two formats are possible, one with bubbling beds, the other with a circulating configuration. Currently commercial scale operating units all use bubbling beds, and hence the acronym PFBC is normally used in the literature to refer to pressurized bubbling bed units. A pressurized circulating fluidized bed combustion (PCFBC) demonstration unit was considered, but no gas turbine was available for the combined cycle configuration. In PFBC, the combustor and hot gas cyclones are all enclosed in a pressure vessel. Both coal and sorbent have to be fed across the pressure boundary, and similar provision for ash removal is necessary. For hard coal applications, the coal and limestone can be crushed together, and then fed as a paste, with 25% water. As with atmospheric FBC (CFBC or BFBC), the combustion temperature between 800-900°C has the advantage that NOx formation is less than in PCC, but N2O is higher. SO2 emissions can be reduced by the injection of a sorbent, and its subsequent removal with the ash. Characteristics Units operate at pressures of 1-1.5 MPa with combustion temperatures of 800-900°C. The pressurized coal combustion system heats steam, in conventional heat transfer tubing, and produces a hot gas supplied to a gas turbine. Gas cleaning is a vital aspect of the system, as is the ability of the turbine to cope with some residual solids. The need to pressurize the feed coal, limestone and combustion air, and to depressurize the flue gases and the ash removal system introduces some significant operating complications. The combustion air is pressurized in the compressor section of the gas turbine. The proportion of power coming from the steam:gas turbines is approximately 80:20%. PFBC and generation by the combined cycle route involves unique control considerations, as the combustor and gas turbine have to be properly matched through the whole operating range. The gas turbines are rather special, in that the maximum gas temperature available from the FBC is limited by ash fusion characteristics. As no ash softening should take place and alkali metals should not be vaporised (otherwise they will recondense later in the system), the maximum gas temperature is around 900°C. As


a result a high pressure ratio gas turbine with compression intercooling is used. This is to offset the effects of the relatively low temperature at the turbine inlet. Heat release per unit bed area is much greater in pressurized systems, and bed depths of 3-4 m are required in order to accommodate the heat exchange area necessary for the control of bed temperature. At reduced load, bed material is extracted, so that part of the heat exchange surface is exposed. Unit size The current PFBC demonstration units are all of about 80 MWe capacity, but two larger units have started up in Japan at Karita and Osaki. These are of 360 and 250 MWe capacity respectively, and the Karita unit uses supercritical steam. (Their size is tied to the capacity of the gas turbine). Thermal efficiency PFBC units are intended to give an efficiency value of over 40%, and low emissions, and developments of the system using more advanced cycles are intended to achieve efficiencies of over 45%. Flue gas cleaning/emissions Combustion takes place at temperatures from 800-900°C resulting in reduced NOx formation compared with PCC. N2O formation is, however, increased. SO2 emissions can be reduced by the injection of sorbent into the bed, and the subsequent removal of ash together with reacted sorbent. Limestone or dolomite are commonly used for this purpose. Residues The residues consist of the original mineral matter, most of which does not melt at the combustion temperatures used. Where sorbent is added for SO2 removal, there will be additional CaO/MgO, CaSO4 and CaCO3 present. There may be a high free lime content and leachates will be strongly alkaline. Carbon-in-ash levels are higher in FBC residues that in those from PCC.

60R05429.01-Q070-006 February 6, 2006




Lot 1, Task 4

Baseline Design of New Thermal Power Plant Options

Draft final

Lot 1, Task 4 February 6, 2006 Baseline design Page 3 (33)

Table of contents

1 INTRODUCTION..............................................................................................................5

1.1 Plant Net Capacity................................................................................................................5 1.2 Steam Parameters .................................................................................................................6

2 STEAM BOILER ...............................................................................................................9

2.1 Design fuel and emissions....................................................................................................9 2.2 Design Capacity .................................................................................................................10 2.3 Pulverized fired boilers 300 and 500 MW .........................................................................11 2.4 Circulating Fluidized Bed boiler for 300 MW...................................................................12 2.5 Flue Gas Cleaning ..............................................................................................................12 2.6 Air Preheater – Flue Gas Cooling ......................................................................................12 2.7 Boiler Feed Water Pumps ..................................................................................................13

3 STEAM TURBINE PLANT............................................................................................14

3.1 Steam Turbine Concepts ....................................................................................................14 3.1.1 300 MW unit with CFB combustion ..................................................................................14 3.1.2 300 MW unit with PC combustion.....................................................................................15 3.2 500 MW unit with PC combustion.....................................................................................15 3.2.1 Turbine modelling ..............................................................................................................15 3.3 Cooling Water System .......................................................................................................15 3.3.1 Condensing Method ...........................................................................................................15 3.3.2 Material Selection ..............................................................................................................16 3.3.3 Circulation system..............................................................................................................16

4 BALANCE OF PLANT ...................................................................................................17

4.1 Lignite Supply ....................................................................................................................17 4.2 Ash Systems .......................................................................................................................20 4.3 Water Treatment.................................................................................................................20 4.4 Oil / Start-up Systems ........................................................................................................23

5 ELECTRICAL SYSTEMS..............................................................................................25

6 AUTOMATION ...............................................................................................................27

7 CIVIL STRUCTURES ....................................................................................................29

8 PERFORMANCE OF THE PLANT..............................................................................30

Lot 1, Task 4 February 6, 2006 Baseline design Page 4 (33) 9 PERSONNEL REQUIREMENTS..................................................................................31

10 PLANT CONSTRUCTION SCHEDULE......................................................................34

Figures Figure 1.1 Annual variation of monthly dry bulb temperatures...........................................................5 Figure 1.2 Annual monthly variation of wet bulb temperatures ..........................................................6 Figure 1.3 Simplified flowsheet for 300 MW CFB-boiler plant..........................................................7 Figure 1.4 Simplified flowsheet for 300 MW PC-boiler plant ............................................................8 Figure 1.5 Simplified flowsheet for 500 MW PF-boiler plant .............................................................8 Figure 2.1 Air preheater .....................................................................................................................13 Figure 2.2 Boiler feed water pumps ...................................................................................................14 Figure 4.1 Proposed feeding system for 300 MW CFB plant ............................................................17 Figure 4.2 Proposed feeding system for 300 MW PF plant ...............................................................18 Figure 4.3 Prosposed feeding system for 500 MW PF plant .............................................................18 Figure 4.4 Ash disposal system..........................................................................................................20 Figure 4.5 Illustrating diagram for water treatment system...............................................................21 Figure 4.6 Typical deminaralising plant design .................................................................................22 Figure 4.7 Lignite fired power plant 300 MW / 500 MW unit, Preliminary water balance ..............23 Figure 4.8 Heavy and light fuel oil storage tanks for start-ups and shutdowns .................................24 Figure 5.1 Single line diagram for 300 MW unit ...............................................................................25 Figure 5.2 Single line diagram for 500 MW unit ...............................................................................26 Figure 6.1 The hierarchical structure of the supervise and control system........................................27 Figure 9.1 Organisational structure of the new power plant ..............................................................33 Figure 10.1 “Fast track approach” schedule for the power plant project ...........................................34

Tables Table 8.1 Auxiliary power demand for each alternative....................................................................30 Table 9.1 Personnel requirements of a new plant ..............................................................................32


1 INTRODUCTION This report presents proposed preliminary designs for the new mine mouth thermal power plant of 2000-2100 MW total capacity for further analysis and development. It has been agreed to make these designs for two different unit net capacities, namely 300 MW and 500 MW. Additionally the smaller units would either utilize Circulating Fluidized Bed (CFB) or Pulverized Fired (PF) combustion method. The 500 MW units will be based on pulverized firing as there is no existing CFB-units of this size. The plant is assumed to be built in two phases; the first phase would consist of either 3 x300 MW or 2 x 500 MW units. The second phase would follow after few years.

1.1 Plant Net Capacity The plant will have conventional evaporative cooling towers to dissipate the heat from the turbine condensers. The average ambient temperature of Pristine is slightly above 10 °C and the average relative humidity is close to 80 %. The following figure illus-trates the annual variation of monthly dry and wet bulb temperatures.

Dry Bulb Temperatures in Pristina 2002

-5,0

0,0

5,0

10,0

15,0

20,0

25,0

30,0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Month

Deg

rees

C

7:00 AM 2:00 PM 9:00 PM

Figure 1.1 Annual variation of monthly dry bulb temperatures


Wet Bulb Temperatures in Pristina 2002

-5,0

0,0

5,0

10,0

15,0

20,0

25,0

30,0

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Month

Deg

rees

C

7:00 AM 2:00 PM 9:00 PM

Figure 1.2 Annual monthly variation of wet bulb temperatures

The plant is currently assumed to have an exhaust pressure of 0,05 bar equalling to 20 °C cooling water temperature from the evaporative cooling tower. The above am-bient temperatures would make possible also slightly lower condenser pressures i.e. 0,040..0,045 bar if the annual average figures are used for the design base or a larger cooling tower is built.

The electricity market analysis does not give any clear premium for the capacity dur-ing hot weather peaks i.e. the plant can be designed as base load energy producer. Later a cold end optimization (turbine LP-part – condenser – cooling tower) may jus-tify that lower condenser pressure especially if CO2-credits are included. The current concept is a low initial cost approach with fairly good performance – a standard con-figuration in many power plants all around the world.

1.2 Steam Parameters The new power plant units have single reheat system and the following steam parame-ters at the turbine inlets:

300 MW

CFB 165 bar/545 °C , 41 bar/545 °C

PF 220 bar/560 °C, 41 bar/560 °C

500 MW PF 242 bar/560 °C, 41 bar/560 °C

The selection of the steam parameters is based on the following considerations:


There are no proven CFB-units using supercritical steam parameters and therefore a drum type boiler have been selected with a maximum steam pressure.

The 300 MW PF-boiler has supercritical steam pressure and higher steam tempera-tures (560 vs 545 °C) in order to make it more competitive against the CFB-boiler as its auxiliary power demand is higher than with the CFB-boiler. On the other hand its HP-turbine is suffering from the low inlet volume flow if compared with the CFB-concept.

The 500 MW unit has typical steam parameters (3500 psia) for this capacity range.

The following simplified flowsheets illustrate the proposed plant concepts with their main parameters:

300 MW CFB-boiler plant

Figure 1.3 Simplified flowsheet for 300 MW CFB-boiler plant

CFB

767 MWfG

326 MW

G

326 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

545 °C, 165 bar(a), 248 kg/s

545 °C, 41 bar(a), 230 kg/s

168 kg/s

9200 kg/s

Lot 1, Task 4 February 6, 2006 Baseline design Page 8 (33) 300 MW PF-boiler plant

Figure 1.4 Simplified flowsheet for 300 MW PC-boiler plant

500 MW PF-boiler plant

Figure 1.5 Simplified flowsheet for 500 MW PF-boiler plant

PF

1238 MWfG

543 MW

G

543 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

560 °C, 242 bar(a), 400 kg/s

560 °C, 42 bar(a), 352 kg/s

13 kg/s

259 kg/s

14500 kg/s

12 bar(a), 316 kg/s

PF

752 MWfG

335 MW

G

335 MW

185 °C, 11.2 bar(a)185 °C, 11.2 bar(a)

560 °C, 220 bar(a), 235 kg/s

560 °C, 41 bar(a), 223 kg/s

166 kg/s

9000 kg/s

12 bar(a), 203 kg/s


2 STEAM BOILER

2.1 Design fuel and emissions The huge lignite resource found in Kosovo can be characterized with the following analysis as received from the Sibovc (>8000 samples analyzed) mine:

Heat value, LHV kJ/kg 8200 - range kj/kg 6000-9500 Ash % 15,3 - range % 10-25 Moisture % 42 - range % 40-45 Sulphur, total % 1,1 - range % 0,7-1,5 Sulphur, combustible % 0,35 - range % 0,1-0,7 Carbon % 22,0 Hydrogen % 2,1 Nitrogen & oxygen % 13,0 Chlorine % 0,05 Its typical ash analysis is assumed to be as follows based on the information of the ad-joining Bardhi and Mirash fields: SiO2 % 38 Al2O3 % 6,8 Fe2O3 % 5,4 CaO % 35 MgO % 2,2 SO3 % 8,3 Others % 4,3 Grand total % 100 The typical ash melting temperature parameters are indicated to be: Sintering °C 980 Half ball °C 1250 Melting point °C 1300 This Kosovo lignite can be characterized by its relatively low ash content, low com-bustible sulphur as the most of the sulphur is found in inorganic sulphate/sulfite form and the existence of ample calcium in the fuel. The ash softening and melting tem-peratures are low and may cause problems in conventional pulverized combustion process if not properly considered at the design phase.


The presence of calciumcarbonate, CaCO3, in the fuel has not been analyzed exten-sively but the records of the existing power plants indicate that the percentage of cal-ciumoxide, CaO, in the ash varies between 25 and 45. Emission Requirements It is assumed that the new thermal power plant, TPP, will fully comply with the EU Large Combustion Plant, LCP, rules. That will mean the following emission levels from the beginning of the operation:

Sulphur dioxide, SO2 mg/nm3 200 Nitrogen oxides, NOx mg/nm3 200 Particulates mg/nm3 30

2.2 Design Capacity The steam boilers are designed to be able to reach their full capacity also on the fol-lowing low quality lignite as there will not be any homogenization of the lignite ex-tracted from the mine before its introduction into the combustion process:

Heat value, LHV 6,0 MJ/kg Moisture 45 % Ash 25 % Sulphur, combustible 0,7 % The boiler capacities in different unit sizes and combustion methods are tentatively as follows: Alternative Capacity MWth Steam HP kg/s RH kg/s 300 MW, CFB 767 248 230 300 MW, PF 752 235 223 500 MW, PF 1238 400 365 The typical lignite consumption and ash generation are with the design fuel (average LHV of 8,2 MJ/kJ) as follows: Alternative Lignite Ash t/h t/MWh t/h 300 MW, CFB 337 1,12 52 300 MW, PF 330 1,10 51 500 MW, PF 544 1,09 83

Lot 1, Task 4 February 6, 2006 Baseline design Page 11 (33) 2.3 Pulverized fired boilers 300 and 500 MW

The lignite fuel is delivered to the boiler silos pre-crushed i.e. the maximum size of the fuel is <40 mm. For pulverizing of wet lignite beater wheel pulverizers are most commonly used. There hot flue gases from the upper furnace are sucked for drying the wet fuel. The fuel is fed into the hot inlet duct and the drying fuel flue gas mixture passes trough the radial fan type pulverizer where the actual pulverizing takes place by gravitational force as the fuel clumps collide against the fan enclosure wall made of abrasion resistant wear parts. The upper part of the pulverizer has a classifier that al-lows only fine particles to pass and coarse fraction is recycled back to the pulverizing process. The maximum capacity of a single pulverizer is approximately 150-200 t/h i.e. 500 MW unit needs four-six pulverizers depending on the fuel range (8200, mini-mum 6000 kJ/kg). In order to have continuous operating capability there has to be one spare pulverizer as they need periodic maintenance at 2-4000 hrs intervals with Kos-ovan lignite.

For large boilers tangential firing method is commonly applied and each pulverizer is feeding its own four burners i.e. one level at each corner. The burners fed by different pulverizers are in stacked form either in the furnace corners or close to the corners to produce a swirl in the centre of the furnace. The burners are so called Low NOx-type where the combustion air is staged to reduce the absolute maximum temperatures in combustion thus effectively reducing the formation of thermal NOx. Another burner arrangement is to locate them on the front and rear walls/ side walls. In that case the burners are fixed and one pulverizer feeds one level.

The air pre-heaters are normally of rotary type and due to the size of flue gas stream there are two parallel units each designed for 50 % flow.

The steam boiler itself is either built in tower form or as two-pass unit. The furnace and the boiler walls in the hot sections are of membrane construction welded gastight. Tower format saves space as the super-, reheater and economizer heating surfaces are stacked above the furnace. The upper part of the boiler is split into two sections by a wall that also acting as a heating surface. The flue gas after the economizer are leaving high up and there has to be a duct to bring those flue gases down to the air preheaters.

A two-pass configuration will need slightly more space in longitudinal direction than the tower boiler but the benefit is that the connecting pipelines are slightly shorter.

At the moment it is assumed that the pulverized fired boilers can meet the nitrogen ox-ide emission limits with proper burner arrangement without any additional treatment of the flue gases after the furnace.

Regarding to sulphur dioxide emissions it is expected that wet desulphurization proc-ess is installed after the PF-boilers. If the proposed continuous measuring programme at Kosovo B or any other testing will verify the high degree of sulphur capture in the furnace also dry or semi dry desulphurization approaches can be considered.

Lot 1, Task 4 February 6, 2006 Baseline design Page 12 (33) 2.4 Circulating Fluidized Bed boiler for 300 MW

The CFB-boiler is a conventional drum type steam boiler with reheat as there are no proven units running at supercritical steam parameters.

The applied combustion temperature of 850-950 °C is quite ideal for calcination of limestone in the fuel to calcium oxide. The CaO captures sulphur of the the fuel in the combustion process. That kind of desulphurization process is not as effective as in the separate flue gas desulphurization process. Compared with S-moles, typically 3 times more Ca-moles are required to reach 90 percent desulphurization degree vs. that of 1,1-1,2 for a downstream FGD. However, in this particular case as the lignite contains a substantial amount of limestone, CaSO4 and the sulphur content of the fuel is low (Ca/S mole ratio >5-10) it can be expected that the sulphur dioxide emission will be extremely low..

The low combustion temperature of CFB results also in low thermal NOx-formation as the emission almost exclusively comes from the nitrogen in the fuel.

Typically the lignite injected into furnace shall have an average particle size of 1 mm and the maximum of 10 mm. There should not be more than 5 % fine particles of 0,05 mm or less. Crushing of the fuel is executed outside of the boiler house at the fuel yard.

To start the operation the boiler needs sand to create the necessary inventory of the circulating hot mass for ignition. During its normal operation the fuel ash may be suf-ficient to maintain that inventory level. If the fuel ash is not able to upkeep the inven-tory level some (quarz) sand has to be added every now and then.

The fuel ash exits the boiler mostly (about 90 %) in the form of fly ash and the rest is taken out in dry form as bottom ash through ash cooling screws.

2.5 Flue Gas Cleaning All the boilers have two parallel flue gas lines and there are electrostatic precipitators after the air preheaters. Those ESP´s have 4-5 electrical fields and the final dust con-tent is reached with one field out of operation. In case of PF-boilers and wet FGD-plant the particulate content may be designed slightly higher as the wet scrubbers ab-sorb the particulates (quality of gypsum coming out of the process has to be consid-ered).

2.6 Air Preheater – Flue Gas Cooling In order to effectively utilize the heat of the high flue gas flow coming from wet lig-nite special heating surfaces can be arranged as the following sketch illustrates:


Figure 2.1 Air preheater

The rotary air preheater does not need all the flue gas flow from the furnace and a par-allel duct with heating surfaces can be built. The flue gas can be cooled from ap-proximately 350 °C down to 160 °C as the air preheater. It is proposed to use LP-condensate after the main condensate pumps up to 150 °C (as the condensate is enter-ing the deaerator) and HP-boiler feed water parallel to the HP-heaters. The flows are adjusted to utilize the available heat in the flue gas i.e. there are controls on the con-densate and feedwater flows as well as on the flue gas flow. The primary target is anyhow that the air preheater receives sufficient flow to maintain the outlet tempera-ture of the combustion air constant at approximately 300 °C.

Another boiler efficiency improvement is to cool the flue gases after the electrostatic precipitator by installing a heating surface to heat a closed loop circulation water to preheat the combustion air prior to its introduction to the air preheater. The materials have to be plastic coated in order to reduce the risk of acid corrosion as the tempera-tures are there below the dew point.

2.7 Boiler Feed Water Pumps The boilers for 300 MW units have three 50 % boiler feed water pumps with electric motor drives with hydraulic couplings for speed control.

HPBFW

LP condensate

ESP160oC 100oC

55oC

120oC

Rotary AH

SAH

350oC300oC

ID Fan

Air to combustion from FD fans

Flue gas from economizer


Figure 2.2 Boiler feed water pumps

The 500 MW unit is assumed to have turbine driven main pump (abt. 16 MW) and two 25 % electric motor driven pumps for start-up. The turbine drive can either dis-charge its steam (appr. 13,5 kg/s RH-steam) into a separate condenser or it may be ducted to the main condenser.

3 STEAM TURBINE PLANT

3.1 Steam Turbine Concepts

3.1.1 300 MW unit with CFB combustion Unit based on CFB boiler will have relatively conservative main steam parameters. Moderate admission steam parameters favour solution with combined high pressure and intermediate pressure steam paths. Some steam turbine manufacturers do not have this solution and having combined HP/IP casing or separate casing is matter of cost and efficiency optimisation. Technically separate casings might be better while com-bined casing reduces losses and is thereby more efficient solution.

Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 300MWenet unit only one LP casing solution is quite probable. The key issue is the electricity valuation price and steam turbine vendor standard LP cas-ing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 300 MWenet units with only one two flow LP casing.

Optimal number of feed heating stages is 7+1 where there are two heaters in the high pressure side.

x °C, x bar(g)x °C, x bar(g)

3 x 50%electric

CFB/PF 300 MW

2 x 25%electric

x °C, x bar(g)x °C, x bar(g)x °C, x bar(g)

100%

PF 500 MW

Lot 1, Task 4 February 6, 2006 Baseline design Page 15 (33) 3.1.2 300 MW unit with PC combustion

300 Mwenet unit size is still a little bit small to fully utilize supercritical steam parame-ters. The main factor is steam volumetric flow at the HP steam path first stages. Ad-mission steam parameters are still a bit higher that in the CFB solution. Increased ad-mission steam pressure will favour separate high pressure and intermediate pressure casings though it still may be possible to combine these steam path to one common casing.

Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 300MWenet unit only one LP casing solution is quite probable. The key issue is the electricity valuation price and steam turbine vendor standard LP cas-ing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 300 MWenet units with only one two flow LP casing.

Optimal number of feed heating stages is 7+1 where there are two heaters in the high pressure side.

3.2 500 MW unit with PC combustion In 500 Mwenet unit will have supercritical main steam parameters. Due lack of refer-ences of very high steam parameters and still moderate unit size the main steam pa-rameters shall anyhow be limited to 245 barabs 560/560 oC.

Supercritical steam parameters mean separate High pressure and Intermediate pressure casings as basic solution.

Number of the low pressure casings depends on unit size and turbine process cold side optimisation. In 500MWenet unit only one LP casing solution is quite possible though optimal solution may also be two LP casing solution. The key issue is the electricity valuation price and steam turbine vendor standard LP casing exhausts areas. Most vendors though have large enough LP last stage blades to handle the 500 MWenet units with only one two flow LP casing but this will request increased exhaust pressure and large losses in the cold end.

Optimal number of feed heating stages is 8+1 where the 8ht heater is in the high pres-sure side and supplied from high pressure turbine bleeding.

3.2.1 Turbine modelling The TURSIM model sheets can be found in Annex 1. The sheets illustrate the turbine process including the deviations of the LP-condensate and HP-feedwater to the fluegas heating surfaces parallel to the rotary air preheater.

3.3 Cooling Water System

3.3.1 Condensing Method The main condenser will be of shell and tube type surface condenser.


The number of cooling water flows determines the number of independent flows into which the cooling water supply is divided in the condenser. Due availability reasons there should be at least two flows per each main condenser.

3.3.2 Material Selection The main condenser surfaces are in contact with ambient air (shell), main cooling wa-ter (tubes and water chambers) and circulating steam/water (tubes, shell and hotwell).

The estimate for the circulating cooling water analysis is based on that there will not be lack of makeup water and thereby the circulation rate will be relatively low keeping the water chemistry in reasonable concentrations. Based on the CW chemistry the main condenser will have stainless steel tubing (pref-erably high grade SS) Titanium tubing being even better but not necessary if CW chlorine concentration is maintained within prescribed limits by blow down and make-up water.

3.3.3 Circulation system The cooling water is circulated from the evaporative cooling tower basin to the turbine condenser and back by two 50 % circulation pumps. Additionally there will be two small pumps for start-up phases. The estimated circulation volumes are as follows:

Concept Flow kg/s 300 MW CFB 9200 300 MW PF 9000 500 MW PF 14 500

The pumping head is typically around 20 m and will be defined at the actual design phase of the plant. The pumps need 2,2 – 3,5 MW electrical power.

The circulation system has a continuous rubber ball cleaning for the turbine condens-ers. The auxiliary cooling needs (generator, turbine lub. oil system and boiler plant miscellaneous users) are served be a closed loop system. That is connected to the main cooling water circulation system through plate type heat exchangers (2 x 100 % capac-ity). That arrangement secures trouble free operation and the cleaning of the interme-diate exchangers can be done while the plant is at its full power.


4 BALANCE OF PLANT

4.1 Lignite Supply The fuel supply system from the mine is assumed to be the following with a storage yard of capable to hold for 14 days´ full load consumption. In normal operation it is expected that the lignite is directly conveyed to the boiler silos from the mine. The fol-lowing diagrams illustrate the proposed feeding system:

Figure 4.1 Proposed feeding system for 300 MW CFB plant

Belt conveyor,1 x 200 %

14 daystorage

Screens &crushers4 x 40%

MineLoading andunloading of storage with 2 x stacker-reclaimers

Boilersilo, 24 h

Boilersilo, 24 h

Boilersilo, 24 h

Beltconveyor1 x 160%


Figure 4.2 Proposed feeding system for 300 MW PF plant

Figure 4.3 Prosposed feeding system for 500 MW PF plant

The block-diagrams above present the main functions of the fuel transport and han-dling from the mine to the boiler silos in the two different plant concepts. At the lig-nite mines there are no actual storing facilities. The lignite extracted at the mine with bucket wheel excavators is pre-crushed to transportable particle size (< 40mm) and fed directly to a conveyor system that transports the lignite from the mine to the power plant area. The conveyor is a single line covered belt conveyor that supplies the de-


14 daystorage

MineLoading andunloading of storage with 2 x stacker-reclaimers

Boilersilo, 24 h

Boilersilo, 24 h


Boilersilo, 24 h


14 daystorage

Mine Loading andunloading of storage with 2 x stacker-reclaimers

Boilersilo, 24 h

Boilersilo, 24 h



mand of all the three/two 300 MW/ 500 MW power plant units. The 3-5 km long con-veyor has a capacity of 2000 tph, which is two fold if compared with the total fuel demand of the boilers with average fuel quality. The belt conveyor is approximately 1.2 meters wide and has a velocity of 3-4 m/s. In normal operation most of the material coming from the conveyor belt is fed directly to the screens and crushers that are followed by a conveyor line that feeds all three 24 hour capacity boiler silos. In the PF boiler case the screening and crushing is not needed as the incoming particle size is small enough for the boiler plant pulverizers. For a case of interruptions in the lignite mining or interruptions in transportation from the mine to the power plant there is a 14 days´ storage yard at the power plant area. Two stacker-reclaimers load and unload the storage field when needed. One stacker-reclaimer serves two stacks at a time, one stack at each side of the stacker-reclaimer line. (See the lay-out in Annex 2). Also the normal balancing between fuel demand and supply from the mine is done by using the 14 day stock pile. If the power plant is operating at full load with the average heating value of the fuel the lignite stockpile can be filled up within two weeks. Even with the worst quality lignite the fill up time will not exceed 4 weeks. In the CFB boiler case there is a screening and crushing station before the conveyor leading to the boiler silos. The plant is dimensioned to be 4 x 40%, ie. 4 x 400 tph units that deliver an average/maximum particle size of 1 mm / 10 mm. In normal op-eration only three crusher units are used and one is at stand by for a failure of one unit or need of higher capacity when filling up the boiler silos. It means that the first unit has two crushers and thereafter every boiler gets its crusher. Dimensioning part of the fuel transport system for the whole 2000 MW should be considered already when investing in the first 1000 MW. The two stacker-reclaimers are allready sufficient also for the future needs. Upgrading the conveyor capacity for the needs of 2000 MW would add cost only around 30% of the conveyor cost and should thus be considered. The screening and crushing capacity consists of numerous units and thus there is now reason for investing in extra capacity at the first phase. The experience of the Kosovo B power plant is that the lignite has tendency of arching in the boiler fuel silos and therefore special care has to be paid on the design and ma-terial selections of the silos and their cones.


4.2 Ash Systems The ash disposal system is basically the same for all the investigated unit concepts. The following diagram illustrates the configuration:

Figure 4.4 Ash disposal system

For large fly ash collection systems pneumatic conveying with transmitters are used as there are numerous collection points. The fly ash silo has a capacity of 24 hours at plant full load.

Blow down water of the evaporative cooling tower can be used for moisturizing the ash prior to its transport to the final depositing site.

4.3 Water Treatment The power plant will receive raw water from the Ibër-Lepenc system. All the raw wa-ter needs to be (flocculated and) filtered before its use.

The units are estimated to need the following average amounts of raw water:

300 MW CFB or PF 850 m3/h (236 kg/s)

500 MW PF 1400 m3/h (389 kg/s)

In the contracting phase with the water supplier a certain safety margin have to be added to these figures.

Silo24 hrs

3-5 km coveredbelt conveyor to mines

Mine landfill

loaders

< 10%

> 90%

Moistu-rizing

FLY ASHFROM ESP

BOTTOM ASHFROM BOILER

Silo24 hrs


The water treatment system is basically as the following diagram illustrates:

Figure 4.5 Illustrating diagram for water treatment system

The existing Kosovo B is using lime for softening the raw water for its cooling tower but it is recommended to use acid (HCl) regenerated softeners for that service and get rid of the lime sludge problems.

The boiler water has to be demineralised but its average consumption is very low, typically 1-2 % of the steam generation i.e. 3-5 kg/s (10-20 t/h). Especially in case of supercritical boilers as there is no continuous blow down the consumption is low but the quality requirements are high.

A typical demineralising plant design is illustrated below:

Flocculationfiltration

Soft-ening

Neutrali-zation

COOLINGTOWERS

DEMI PLANT

POTABLEWATER

5 % (dimensioning)

< 1% (dimensioning)

FLY ASHMOISTURIZING

**1 x 100 %

*2 x 100 %

**1 x 100 %

*2 x 100 %

100%

**Phase 2: +2 x 600 MW / 2 x 500 MW

*Phase 1: 3 x 300 MW / 2 x 500 MW

**Phase 2: +2 x 600 MW / 2 x 500 MW

*Phase 1: 3 x 300 MW / 2 x 500 MW

**3 x 33 %

*4 x 33 %

**3 x 33 %

*4 x 33 %

**1 x 100 %

*2 x 100 %

**1 x 100 %

*2 x 100 %

HCL forregener.

NaOH

Storagetank

Storagetank

IBER-LEPENC

95 % (dimensioning)


Figure 4.6 Typical deminaralising plant design

The demineralised water storage tank is at least 1000 m3 and that should allow two start-ups without any additional waiting time. The demineralising plant continuous ca-pacity is typically only 3-5 % of the steam generation i.e. 10-20 kg/s to cover the losses during the normal operation. The first unit would have two full capacity trains and thereafter the following units one full capacity train added.

The steam-water cycle has a condensate polishing plant of 2 x 50 %. That is basically a mixed bed ion exchange filter installation after the main condensate pumps. The wa-ter quality during normal operation is controlled with oxygen and ammonia. This sys-tem is widely used and it is cheaper than the conventional hydrazine injection.

The preliminary water balance is illustrated in the following blockdiagram.

WAC/SAC

**1 x 100 %

*2 x 100 %

**1 x 100 %

*2 x 100 %

100%

**Phase 2: +2 x 600 MW / 2 x 500 MW

*Phase 1: 3 x 300 MW / 2 x 500 MW

**Phase 2: +2 x 600 MW / 2 x 500 MW

*Phase 1: 3 x 300 MW / 2 x 500 MW

WAC = weak acid cation1 SAC = strong acid cationWBA = weak base anionSBA = strong base anion

WBA/SBA MB

Demi-wtank

1000m3

Demi-wtank

1000m3

HCL forregener.

NaOH forregener.

Neutralization

FLY ASH MOISTURIZING

RAW WATERPLANTSTORAGETANK


Lignite fired power plant 300 MW / 500 MW unit, Preliminary water balance

2 m3/h 15/25 m3/h

2/3 m3/h

850/1400 m3/h 800/1320 m3/h 12/20 m3/h 0- 15/25 m3/h

Raw water demand 769 m3/h (300 MW) 5Design 750/1250 m3/h 1270 m3/h (500 MW)Peaks 1000/1700 m3/h

650/1050Figures Average/Peak m3/h m3/h

Closed cooling circuit will be usedfor TG oil, generator and misc. othercooling needs at the plant.

50/80 m3/h

188/328 m3/h(for ash moisturizing)Drains to sewer

Flocculation/filtration

Softening

Potable waterplant

Demineralizers 2 x 50/75 m3/h

Demineralized water tank 1000/1500 m3

Boiler feed water system

Condenser

Condensate polishing system

Cooling tower

Figure 4.7 Lignite fired power plant 300 MW / 500 MW unit, Preliminary water balance

4.4 Oil / Start-up Systems The plant needs heavy and light fuel oil storage tanks for start-ups and shutdowns. The following diagram (see next page) illustrates the complete system.

Heavy fuel oil needs continuous heating and that steam is normally drawn from the turbine extractions when the plant is running. For start-ups steam from the auxiliary boiler is required and for its start-up light fuel oil or electric heater has to be used.

Light fuel oil, LFO is used for first ignition and to fill the lines for shutdowns.

For a black start capability a light fuel oil gas turbine is recommended for the first unit. It could be a reconditioned old unit as its running hours will not be high but its starting reliability will be of utmost importance.


Figure 4.8 Heavy and light fuel oil storage tanks for start-ups and shutdowns

The power plant needs a LP-steam boiler for starting the main unit and for heating the facility in a case that it is down for any reason during cold weather conditions. Steam is required for combustion air preheating and providing deaerating steam to the main feed water tank. The capacities are just indicative and should be verified with the se-lected boiler. In case of locating the new plant aside Kosovo B power plant it is advis-able to draw the start-up and /or heating steam from that plant. In case of the black start gas turbine a heat recovery steam generator (HRSG) can be installed after the gas turbine. A 40 MW gas turbine can produce 15-25 kg/s (54-90 t/) LP-steam while oper-ating at full power.

The main and reheating steam lines have the normal 2 x 50 % fast acting by-pass sys-tems for the turbine trip and start-up. The by-pass system discharges the steam into the neck of the main condenser.

PFBoiler

PFBoiler

LPBoiler36 t/h

140 °C140 °Cmake up water

>150 t/h

120 t/h

30 t/h

Blow downIn start up,

FW-pump

Gas turbine 40MWe

LFOLFOLFO

HFO5000 m3

HFO5000 m3

HFO5000 m3

start upelectricity use

G

x MW

G

x MW

G

x MW


5 ELECTRICAL SYSTEMS Each power generating unit is basically independent and is blocked directly to the main 400 kV system of Kosovo as the following single line diagrams illustrate:

Figure 5.1 Single line diagram for 300 MW unit

The generator voltage is in the range of 15-22 kV and it is connected through an en-closed bus duct to the step-up transformer. There is an unit breaker as the bus duct feeds also a three winding auxiliary transformer. Three winding transformer is pro-posed to feed separately boiler feed water pump drives at 10 kV and other auxiliaries at 6 kV.

There is a double bus bar 400 kV system to concentrate the power generation in a case that all the units cannot individually be connected to the Kosovan main 400 kV swith-cyard.

Additionally the plant has a maintenance/start-up power supply at 110 kV (20 kV). In case to locate the plant aside Kosovo B the connection to its 110 kV start-up trans-former is recommended.


Figure 5.2 Single line diagram for 500 MW unit

The generators are dimensioned for 0,9 power factor and their preliminary capacities are:

300 MW units 375 MVA 500 MW units 600 MVA

The 375 MVA generators are assumed to be air cooled and the 600 MVA generator is hydrogen cooled (stator may be water cooled). The cooling water design temperature is 35 °C (closed loop system).

The plant will have the following voltage levels:

Transmission 400 kV Maintenance/start-up (110 kV) Generator 15- 20 kV BFW-pump drives 10 kV MV 6 kV LV 690 V Service 400 V The units are connected to each other to furnish sufficient back-up service. A black-start gas turbine is recommended to be able to get the plant up in case of the grid failure. The plant has a small diesel generator to provide back-up power for the control and supervisory systems, for safe shutdown of the plant as well as for the emergency light-ing of the plant area.


6 AUTOMATION The plant will have modern digital distributed control system to supervise and control various systems of the plant. It will also incorporate all the necessary safety features (steam turbine & generator, burner management and boiler protections etc.). The hier-archical structure of the system is illustrated in the following picture:

M XM XX

MCC

Process

Drive Control LevelSingle drive ControlsClose Loop Controls

Sub-group Controls

Group Controls

Unit Controls GT1/HRSG1 GT2 /HRSG1 Steam Turbine

Block Control Block Coordinator

Protections

Functional Hierarchy

Operator access

M XM XX

MCC

Process

Drive Control LevelSingle drive ControlsClose Loop Controls

Sub-group Controls

Group Controls

Unit Controls GT1/HRSG1 GT2 /HRSG1 Steam Turbine

Block Control Block Coordinator

Protections

Functional Hierarchy

Operator access

Figure 6.1 The hierarchical structure of the supervise and control system

On the top of the above system there will be power dispatching communicating with the Kosovan TSO and all the internal management reporting and supervisory systems of the power company.

The field instruments are intelligent and are executed by using HART protocol. Most critical items are executed by using 2/3 concept.


The supercritical units are operated with gliding pressure principle whenever they are required to run at partial loads.

The plant overall control system and the turbine process will also have possibility to have running reserve capability by abruptly shutting down the condensate preheating and increase the turbine power to stabilize the grid. The exact requirements should be coordinated with TSO.

The emission measuring and recording system will be in full compliance with the European standards.


7 CIVIL STRUCTURES The preliminary lay-out of the power plant is presented in Annex 2. The site is Kos-ovo B and the fly-ash pile is removed to accommodate the lignite yard. That area also would be the location for the new raw water treatment facilities (flocculation, filtration plant and demineralization plants). There are two concepts namely one for 7 units of 300 MW and 4 units of 500 MW. There are sufficient space for those concepts as the cooling towers are located “staggered” in order to save space in width of a single unit.

As there is a seismic risk the foundation system needs to be integrated i.e. the plant/unit will be placed onto a single reinforced concrete slab immersed into the ground well above the lignite seam (Kosovo B or Bivolak).

The structures are conventional: the boilerhouse is made of structural steel with weather enclosure walls of corrugated painted/plastic covered steel panels. The turbine house is also of steel frames with reinforced concrete slab as the main operationg floor. The turbine pedestal is a reinforced concrete separate structure or alternatively the whole turbine building is integrated and the turbine is supported by springs on that structure.

The evaporative cooling tower is a slip-formed reinforced concrete structure supported by a solid concrete slab that serves also as the water basin of the tower. The cooling water channels are either made of reinforced concrete or steel pipes in concrete cul-verts due to their size.

The lignite yard has the concrete/steel supporting structures for the belt conveyors, stacker-reclaimers and retaining walls.

Special care has to be paid onto the surface treatment/painting or material selection of the structures outdoors.

The power plant area floor drains and rain waters are separated as far as possible. The floor drains are passed through oil traps. The rainwaters from the roofs and open areas are collected to a central location and discharged trough a settling basin. Specific ef-fluents are piped separately to their treatment plants if necessary.

The spaces for electrical and control equipment are furnished with air conditioning and their make-up air is filtered for added reliability.

Special emphasis is paid onto fire prevention / minimizing the effects a fire, separation of spaces. The electrical and cable spaces are provided with automatic fire detection and extinguishing systems. The transformers are located in protective enclosures and provided with sprinklers and oil catchment traps.

The control room and offices of the operating team in the power plant building are lo-cated in structures entirely separated from the main buildings in order to minimize the effects of vibration and noise. The same applies to laboratory for the fuel and waters and local small maintenance spaces.


8 PERFORMANCE OF THE PLANT The plant performance has been established for each of those three alternative con-cepts. The auxiliary power demand is estimated as follows:

Alternative CFB PF PFkW kW kW kW kW kW

Gross generation 326 466 334 657 557 069Boiler plant 15 800 24 606 41 034 BFW-pumps 7 950 8 376 13 968 Fuel system 1 100 3 681 6 139 Fans 3 224 6 449 10 754 ESP & FGD 1 500 4 000 6 671 Misc. 2 026 2 100 3 502Turbine plant 1 250 1 250 2 085Coal handling 2 873 2 155 3 593Water treatment 648 648 1 080Cooling water circulation 2 389 2 327 3 880Compressed air 600 700 950Miscellaneous 1 500 1 500 2 000Total power plant auxiliaries 25 060 25 060 33 185 33 185 54 623 54 623Transformer losses 1 406 1 406 1 471 1 471 2 447 2 447

Net at 400 kV 26 466 300 000 34 657 300 000 57 069 500 000

Auxiliary power percentage % 8,8 11,6 11,4

Table 8.1 Auxiliary power demand for each alternative

The pulverized fired boilers have remarkably higher power consumption than the CFB-boiler as a wet FGD is assumed as well as the beater wheel pulverizers are using 5-10 kWh/t power.

The overall efficiency calculation in MW can be done as follows:

Alternative 300 CFB 300 PF 500 PF Net power 300,0 300,0 500,0

Heat in steam-water 712,5 697,4 1148,6 Boiler losses, stack 43,5 43,0 70,5 , radiation 7,7 7,7 12,4 , UBC 3,8 3,8 6,2 Grand total heat release 767,5 751,9 1237,7 Efficiency % 39,0 40,0 40,4

The crucial issues in improving the overall efficiency are: auxiliary power demand and how the excess heat content of the wet flue gases is utilized.


9 PERSONNEL REQUIREMENTS The staffing of the new plant is based on the assumption that the foreign investor brings the plant management and some key persons for the operation. The staffing level is assumed to follow general western European practice. All the service func-tions are outsourced/subcontracted (like maintenance, security, canteen, health etc.).

The operating crews are directly employed by the plant as well as the supervisory per-sonnel for maintenance and the maintenance persons working in shift. The following table outline the number and origin (expatriate/local) of each function.


Personnel estimate First unit Following units

number type number typePlant manager 1 expat. 0 expat.Deputy plant manager 1 local 0 localOperations manager 1 expat. 0 expat.Finance director 1 expat. 0 expat.Personnel manager 1 expat. 0 expat.Secretaries 3 local 1 local

Operation div.Operations planner & efficiency control 2 local 1 localShift engineers 5 local 1 localOperators 30 local 30 local

Technical department-maintenanceEngineersBoilers 2 exp./local 1 exp./localTurbines 2 exp./local 1 exp./localChemist (water & fuel) 2 exp./local 0 exp./localElectrical 2 exp./local 1 exp./localI&C 2 exp./local 1 exp./localScheduling 2 exp./local 1 exp./local

SupervisorsMechanical 9 local 5 localElectrical 4 local 2 localI&C 4 exp./local 2 exp./localMisc. 2 local 2 local

Shift maintenanceMechanical 5 local 2 localElectrical 5 local 1 localI&C 5 local 1 local

DayMechanical 5 local 5 localElectrical 5 local 5 localI&C 5 local 5 localLaboratory 3 localMisc. drivers 10 local 5 localGrand total 119 73

Table 9.1 Personnel requirements of a new plant

It is assumed that each function in shift needs five persons. The actual operation of the first unit means one shift engineer and 8 operators/maintenance technicians. The fol-lowing units would add only 5 operators for the continuous shift work. The mainte-nance team would get some back-up persons that can work either shift or day.

The actual maintenance services of the plant are outsourced and the maintenance su-pervisors above are only to contract and supervise those services with the help of the few day workers (mechanical, electrical, I&C).

The organizational structure of the new power plant is as follows:


Figure 9.1 Organisational structure of the new power plant

Plantdirector

OPERATION

Financialmanager

Secretaries

Operationmanager

Technicaldirector

Personnelmanager

Deputy plantdirector

Shiftengineers5 x eng.

Planning &control2 x eng.

Shiftoperators5 x 6 = 30

MAINTENANCE

Boilers 2 x eng.

Turbines2 x eng.

Chemists2 x eng.

Electrical2 x eng.

Schedul-ing.

2 x eng.

engineers

Mechanical9 x superv.

Electrical4 x superv.

Shiftmechanics5 x 1 = 5

Misc. drivers3 x day shift


I&C2 x eng.

I&C4 x superv.


Mechanics5 x day shift

Laboratory3 x day shift

Misc.2 x superv.




10 PLANT CONSTRUCTION SCHEDULE The development and construction of a power plant of this size (around 1000 MW in the first phase) needs a considerable time:

Basic engineering 3-6 months Selection of main machinery 6-8 months Permitting 6-12 months Financial closing 6-12 months Actual construction 30-36 months Commissioning 6- 8 months Grand total 50-70 months Therer are activities that can be done parallel especially in the development phase but it would mean “guessing” certain approaches as the environmental permitting typi-cally requires quite specific information of the power generating process and equip-ment. That cannot be disclosed too early partly due to commercial issues. The finan-cial closing typically needs the machinery contracts signed well in advance to allow the lenders do their due diligence on the agreed conditions. The following simplified bar-chart illustrates a “fast track approach” to get the power plant part of the project moving.

Year 1 2 3 4 5 6 7Item ´2006 ´2007 ´2008 ´2009 ´2010 ´2011 ´2012Basic engineeringITB documentsBidding-contractingEIA-permittingFinancingFinancial closeCivil worksMechanical erectionPrecommissioningTrials, power generationCommercial operation Figure 10.1 “Fast track approach” schedule for the power plant project

60R05429.01-Q070-007

February 6, 2006




Task 5,

Financial and economic analysis of the new TPP

Draft Final

Lot 1, Task 5 Page 3,17 Financial and economic analysis

Table of contents

1 INTRODUCTION..............................................................................................................4

2 OPERATIONAL COST ....................................................................................................5

3 INVESTMENT COST AND FINANCIAL ANALYSIS.................................................6

3.1 Investment Cost....................................................................................................................6 3.2 External Financing ...............................................................................................................8 3.3 Investment Return Calculations .........................................................................................11 3.3.1 Net Present Value and Free Cash Flow of Investment.......................................................11 3.3.2 Available Cash and Return on Investment .........................................................................13 3.3.3 Stress Testing .....................................................................................................................14

4 ECONOMIC BENEFITS TO KOSOVO.......................................................................16

4.1 Impact of Lignite Fee .........................................................................................................17


1 INTRODUCTION This report presents preliminary financial and economic figures for the new mine mouth thermal power plant of 2000-2100 MW total capacity for further analysis and development. It has been agreed to make these designs for two different unit net ca-pacities, namely 300 MW and 500 MW. Additionally the smaller units would either utilize Circulating Fluidized Bed (CFB) or Pulverized Fired (PF) combustion method. The 500 MW units will be based on pulverized firing as there is no existing CFB-units of this size. The plant is assumed to be built in two phases; the first phase would con-sist of either 3 x 300 MW or 2 x 500 MW units. The first unit will be operational by 2012 and the consecutive units a year a part. The second phase would follow after four years from the completion of the first phase i.e. 2017 - 2019 (as suggested in the tech-nology section).

The mine development and lignite production of 16-17 million tons annually for the 2000 MW capacity has been assumed to be an integral part of the new thermal power plant project.

The generation of the plant is assumed to be as the following graph illustrates:

Generation 2012-2050

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Figure 1: Generation Volumes


2 OPERATIONAL COST The plant operating costs have been estimated for a load factor of 85 % i.e.7500 full load hours a year.

The cost of lignite production excluding capital costs has been taken for this base cal-culation as 4 €/ton (8,2 MJ/kg) delivered to the power plant (Feasibility study on the Sibovc development, June 2004). The chemicals and water are priced as Kosovo B is currently paying for those services.

The operating costs are as follows:

Operation cost estimate €/MWh at 85 % load factor Consumptions Pulverized firing CFB-firing

units per hr Cost per MWhUnit size 300 500 300 500 300Lignite tons 330 544 4,40 4,35 4,51Limestone tons 1 2 0,14 0,12 0,00Water cu.m 850 1250 0,14 0,14 0,14Hydrochloric acid tons 0,20 0,30 0,09 0,08 0,09Caustic tons 0,10 0,15 0,08 0,07 0,08Ammonia tons 0,00 0,30 0,00 0,00 0,00Boiler water treatment chemicals kg 10 15 0,10 0,09 0,10Total consumables 4,94 4,85 4,92

Ash disposal tons 50 83 0,50 0,50 0,50Variable maintenance per MWh 2,00 2,00 2,00Grand total 7,45 7,35 7,42Fixed costs 3,27 3,11 2,84Total cost excl. capital 10,72 10,46 10,26

Table 1: Operational Costs

The fixed cost part includes the personnel cost, fixed maintenance and general admini-stration expenses of the new TPP. The lignite production cost includes the fixed costs of the mining operation.

The cost of generation excluding the capital costs varies from 10,26 €/MWh to 10,72 €/MWh. Based on the available information, the 300 MW CFB-plant is esti-mated to have the lowest operational cost. The differences in operational costs are very low (less than 5 %).

For comparison the same table can be presented for a case when the lignite cost in-cludes its capital charges with 10 %/a discounting factor i.e. the lignite cost is 6,84 €/ton according to the aforementioned feasibility study.


Operation cost estimate €/MWh at 85 % load factorLignite cost including capital 6,84 €/ton (10 %/a discounting factor)

Consumptions Pulverized firing CFB-firing units per hr Cost per MWh

Unit size 300 500 300 500 300Lignite tons 330 544 7,52 7,44 7,72Limestone tons 1 2 0,14 0,12 0,00Water cu.m 850 1250 0,14 0,14 0,14Hydrochloric acid tons 0,20 0,30 0,09 0,08 0,09Caustic tons 0,10 0,15 0,08 0,07 0,08Ammonia tons 0,00 0,30 0,00 0,00 0,00Boiler water treatment chemicals kg 10 15 0,10 0,09 0,10Total consumables 8,07 7,94 8,12

Ash disposal tons 50 83 0,50 0,50 0,50Variable maintenance per MWh 2,00 2,00 2,00Grand total 10,57 10,44 10,63Fixed costs 3,20 2,98 2,80Total cost excl. capital 13,77 13,41 13,43

3 INVESTMENT COST AND FINANCIAL ANALYSIS

3.1 Investment Cost The investment cost estimate is based on the information generally available on the large plants and discussions with the potential main machinery suppliers but no budg-etary bids have been requested at this phase. The values indicated are nominal values. The large PF plant seems to have the lowest cost per kW of output effect:

First units Following units300 300 500 300 300 500CFB PF PF CFB PF PF

Boiler plant 120,0 145,0 207,3 120,0 140,0 200,2Turbine plant 60,0 63,0 80,0 57,0 60,0 77,0Black start 15,0 15,0 15,0 0,0 0,0 0,0Fuel yard, ash 30,0 30,0 42,0 10,0 10,0 12,0Cooling towers 15,0 15,0 21,0 14,0 14,0 14,0Piping 12,0 15,0 20,0 11,5 13,5 17,5Electrical systems 20,0 21,0 28,0 19,0 20,0 26,5Instruments & DCS 14,0 16,0 20,0 13,0 15,0 19,0Water treatment 5,0 5,2 7,0 4,0 4,2 6,0Other 5,0 5,0 7,5 4,0 4,0 6,5Civil work 25,0 26,5 35,0 24,0 25,5 34,0InfrastructureOffice, maintenance shop 5,0 5,0 8,0 1,0 1,0 1,0Access roads 1,5 1,5 1,5 0,5 0,5 0,5Water supply 1,0 1,0 1,0 0,2 0,2 0,2Power lines 2,0 2,0 2,5 2,0 2,0 2,5Ash 3,0 3,0 4,0 1,0 1,0 1,0Subtotal 333,5 369,2 499,8 281,2 310,9 417,9CM & engineering 16,0 17,0 21,0 16,0 17,0 21,0Development costs 5,0 5,0 6,0 3,0 3,0 3,0Grand total 354,5 391,2 526,8 300,2 330,9 441,9

EUR/kW 1182 1304 1054 1001 1103 884 Table 2: Investment costs for three main options


The cost / effect ratio is the lowest (=best) for the Large PF plant, and the highest for the small PF plant. The overall difference is noticeable. The main concern regarding the large PF plant is that it would potentially not comply with the grid stability N-1 criteria, especially for the first unit. As the total generation capacity of Kosovo increases after the initial unit, the following units are not as criti-cal. Building two 300 MW units simultaneously (units 4, 5 and 6, 7) reduces the cost per unit by 15 % to the equivalent of 851 EUR/kW for the 300 MW CFB unit and 938 EUR/kW for the 300 MW PF unit. Thus the following CFB units have the lowest cost per kW! The associated mine development cost has been assumed to be in all cases 300 €/kW installed capacity. The disbursement of this capital outlay is almost evenly distributed over four years before the start-up of the unit to be served with lignite. As can be see from Figure 2, the large PF plant has the highest initial investment, and the 300 MW units have higher investments later on. The investments over time are the direct result of the building schedule, as specified in the technology section.

Investments over time

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2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

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Small CFBSmall PFLarge PF

Figure 2: Investments over time for the three main options

The overall construction time for the large PF plant is up to 48 months, which is higher than the estimated 39 months for the small CFB plant. The higher the interest rate, the more this will affect the overall financial viability of the different options.


The financial evaluation was calculated with the following assumptions:

Interest on cash assets 10,0 % Energy market price 40 EUR/MWh Tax rate 20,0 % Corporate tax in Kosovo Depreciation 5 % annually Amortization period 9,5 years Rest value 20 % of total investment Inflation 4 % Share of equity 30 % Share of debt 70 % Return on equity 20 % (required minimum) Interest on debt 10,0 % Lignite Fee 3,00 EUR/MWh Amortization percentage 90,0 % WACC 11,60 % (calculated with tax effect) Dividends max ROE (from retained earnings)

Table 3: Financial Assumptions

It should be noted, that a tariff-based system would not be viable as a long-term solu-tion, as the regional market is opening. The price of a PPA or electricity tariff would in any case be calculated as close as possible to the expected future market price - oth-erwise either the investor (IPP) or the Government of Kosovo (or any other concerned party buying electricity from the IPP) would lose money through price subvention. The estimated 40 EUR/MWh is close to the average of several market price estimates (with a marginal downward adjustment).

3.2 External Financing The debt repayment plan used is basically the same for all three options (9.5 years per unit), for comparability. Due to the slightly different building schedule of the 300 MW (3 * 300 MW and 2 * 600 MW units) and the 500 MW units (4* 500 MW units), there are small differences, which can be seen from Figure 3 below.


Loans

1041,7

1148,2

924,7

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1200,0

1400,0

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

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EUR


Figure 3: Debt repayment

The maximum required external financing is 924,7 MEUR for the 500 MW PF units, 1041,7 MEUR for the 300 MW CFB units, and 1148,2 MEUR for the 300 MW PF units. It should be noted, that for a power plant with an expected life cycle of 40 years, a 10-year debt repayment time is generally considered to be too short. Normally, some portion of external financing would be retained throughout the whole plant lifetime. In this example, an interest rate of 10% has been assumed for cash assets. An IPP with a ROE requirement of 20% would normally reinvest the cash with the same 20% ROE requirement.

In Figure 4 we have illustrated the individual repayment plan for each unit, in this ex-ample for the 300 MW CFB units (3 * 300 MW and 2 * 600 MW units).


300 MW CFB Loans

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Figure 4: Loan Cycles for 300 MW CFB plant

Please also note that with a longer debt repayment period, the overall value of the in-vestment will be slightly higher (NPV will rise).


3.3 Investment Return Calculations

3.3.1 Net Present Value and Free Cash Flow of Investment The Net Present Value calculated over 20 years and expected plant lifetime (until 2050) indicate that the 500 MW PF units are the most profitable, but the difference to the other alternatives decreases over time.

Net Present Value

431,3

1 353,1

331,2

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544,5

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Till 2027 Till 2050

NPV Period

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Figure 5: Net Present Value

The Free Cash Flow curves illustrate the effect of the slightly higher power output of the 300 MW units (total of 2100 MW) compared to the 500 MW units (2000 MW to-tal). NPV Calculated over the total expected lifetime of the power plant (as long as the lignite resources will suffice, the difference is very small between the options.


Free Cash Flow

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Large PFSmall PFSmall CFB

Figure 6: Free Cash Flow

After the initial investment (notice the early pattern which is a mirror of the invest-ments over time), all alternatives have high available cash flow before financing ex-penditures. Based on the above assumptions, and the investment plan, the highest cumulative cash flow (both Free Cash Flow and Cash Flow after financing costs (amortization)) are the best for the 300 MW CFB plant over the entire expected plant lifetime. For a shorter period, the FCF for the 500 MW PF plant is slightly better.

Cumulative Free Cash Flow

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Large PFSmall PFSmall CFB

Figure 7: Cumulative Free Cash Flow


Based on the above assumptions, and the investment plan, the highest cumulative cash flow (both Free Cash Flow and Cash Flow after financing costs (amortization)) are the best for the 300 MW CFB plant over the expected plant lifetime.

3.3.2 Available Cash and Return on Investment In the financial model used, dividends have been calculated at a maximum of 20% of retained profits. Dividends will, according to the model, be paid starting 10 to 12 years after the initial investment.

Cash and Dividends

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] Large PFSmall PFSmall CFBSmall CFB CashSmall PF CashLarge PF Cash

Figure 8: Available Cash and Dividends Paid

Return on Equity

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Large PFSmall PFSmall CFBSmall CFB Share ROESmall PF Share ROELarge PF Share ROE

Figure 9: Return on Equity


Return on Equity over time has been estimated for total Equity (Shareholder Equity + Retained Profits) and Shareholder Equity alone. ROE will move closer to the required 20% over time, as dividends are paid out, whereas ROE (Shareholder Equity) will de-pend upon the maximum needed equity during the investment phase.

Turnover and Profit

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Turnover, Large PFTurnover, Small PFTurnover, Small CFBNet Profit, Large PFNet Profit, Small PFNet Profit, Small CFB

Figure 10: Turnover and profit for the three main alternatives (please note that the small

CFB and PF plants have identical turnover curves)

The turnover and profit estimates indicate earlier profits for the large PF plant, but over time the difference will be very small. Average profit margins vary between 38% and 43 % (calculated until 2027), and 65% and 67% (until 2050).

3.3.3 Stress Testing With a higher average electricity price (60 EUR/MWh), all alternatives become ex-tremely profitable, with average profit margins of between 81% and 83% (until 2050). The NPV calculation shows that the investment value increases significantly at a higher market price:

• Small CFB 1 609,8 MEUR (to 2027), 3 174,3 MEUR (to 2050) • Small PF 1 512,1 MEUR (to 2027), 3 025,0 MEUR (to 2050) • Large PF 1 817,9 MEUR (to 2027), 3 289,5 MEUR (to 2050)

Correspondingly, at an energy price of 20 EUR/MWh, the calculated profit margins are between 27% and 29%, but the external debt could not be paid off within the indi-cated time period (not within the entire lifespan of the power plant, in fact). The NPV calculation gives a clear indication of the insufficient cash flows at this market price:

• Small CFB -823,7 MEUR (to 2027), -572,0 MEUR (to 2050) • Small PF -940,5 MEUR (to 2027), -752,9 MEUR (to 2050) • Large PF -806,2 MEUR (to 2027), -582,7 MEUR (to 2050)


Turnover and Profit

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Turnover, Large PFTurnover, Small PFTurnover, Small CFBNet Profit, Large PFNet Profit, Small PFNet Profit, Small CFB

Figure 11: Turnover and profit for the three main alternatives at electricity price of 60

EUR/MWh (stress testing)

Changes in electricity prices, investment plan and construction timetables, profitabil-ity, interest rates, Debt/equity ratios, amortization and depreciation plans, and inflation and discount rates all have a significant impact on the financial viability of the power plants, so no final conclusions about which type of power plant should be used can be drawn at this stage. The two most promising unit alternatives with the given assump-tions seem to be the large PF plant and the CFB plant. The risk profile of a series of smaller investments is lower than for fewer large investments.

Lignite Fee vs. NPV

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Net

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sent

Val

ue [M

EUR

]

Small CFB 2050Small PF 2050Large PF 2050Small CFB 2027Small PF 2027Large PF 2027

Figure 12: Lignite Fee vs. Net Present Value of Investment


In Figure 1212, the linear relationship between the Lignite Fee and the Net Present Value of the investment (2027 and 2050) has been estimated, with an energy price of 40 EUR/MWh. The higher the Lignite Fee, the less attractive the investment is. It is expected that any IPP investor would require a low Risk/Return ratio. Thus the Lignite Fee should be expected to be toward the low end of the scale. The main conclusion at this point is that preliminarily it would make sense financially for an international investor to make an investment in a series of lignite-fired power plants, if the legal and regulatory issues and the financing can be solved in a satisfac-tory manner, and if the electricity market price expectation is sufficiently high.

4 ECONOMIC BENEFITS TO KOSOVO An estimate has been made what kind of revenue generation would come this power plant project during its construction and operation phase:

Regarding to economic benefits of the new power plant to the Kosovar economy the construction of the new mine and power plant will bring approximately € 60 million of foreign money every year over the ten year development time. When the fully built 2000 MW plant is in operation its turnover is around € 600 mil-lion (€ 40/MWh sales price and 15 TWh/a). One quarter i.e. 25 % of that revenue is estimated to benefit directly the Kosovar economy as follows: Revenue item Estimated value € millions/a Salaries, mine & plant 25 Maintenance services 25 Ash & water fees 10 TSO electricity transfer fee 30 Lignite fee 48 Land lease 2 Corporate tax 10 Grand total to Kosovo 150 It has also be noted that the plant revenue is mostly from the export sales i.e. fresh new funds into the Kosovar economy. PSIG can directly benefit with the lignite fee as that will be paid for the utilization of the Kosovar mineral resources. That fee is pro-posed to be the selection criteria for the foreign investor. The highest bid (€ per ton) should win. In this estimate it is assumed to be € 3 per ton. The ash disposal fee also 3 €/ton and the TSO will collect 2 €/MWh for the electricity transfer. The estimate is il-lustrated in the following figure 13.


Kosovo C contribution to Kosovan economy

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Corporate taxesLand leaseLignite royaltyTSO chargeAsh & waterPlant maintenancePlant personnelMine maintenanceMine personnelPlant investmentMine investment

Figure 13: Kosovo C contribution to Kosovan Economy

4.1 Impact of Lignite Fee The potential income from the Lignite Fee alone can be seen in Figure 144 and the cumulative income in Figure 155. All numbers are in nominal values.

Kosovo Benefit of Lignite Fee

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ion

EUR

1,02,03,04,05,06,07,08,09,010,011,012,0

Figure 14: Potential Lignite Fee Contribution (300 MW units)

The maximum for the Lignite Fee is expected to be around 3 EUR/MWh, as a higher fee would impact the return on investment for an IPP.

To maximise the potential Lignite Fee, we recommend that a tendering or auctioning process be held, where the main tendering parameter would be the Lignite Fee.


Kosovo Benefit of Lignite Fee (Cumulative, 300 MW units)

0

1000

2000

3000

4000

5000

6000

7000

2008

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

Year

Mill

ion

EUR

1,02,03,04,05,06,07,08,09,010,011,012,0

Figure 15: Cumulative Potential Lignite Fee Contribution (300 MW units)

60R05429.01-Q070-008

February 6, 2006




Tasks 6 & 7,

Legal and regulatory issues of the new TPP and action plan for its development

Draft Final

Lot 1, Tasks 6 & 7 February 6, 2006 Legal and regulatory & action plan Page 3 (10)

Table of contents

1 INTRODUCTION..............................................................................................................4

2 LEGAL & REGULATORY..............................................................................................5

3 ACTION PLAN..................................................................................................................9

3.1 Body to conduct the tendering process ................................................................................9 3.2 Vacate the mining area.........................................................................................................9 3.3 Prepare tendering documents ...............................................................................................9 3.4 Establishment of ash company...........................................................................................10 3.5 Legal changes.....................................................................................................................10 3.6 TSO operational .................................................................................................................10


1 INTRODUCTION This report presents proposed preliminary comments and recommendation on the legal and regulatory issues for the new mine mouth thermal power plant of 2000-2100 MW total capacity development. It is assumed that the plant and the associated mine will be made by a foreign investor. It will mostly serve the export market. The first unit of 300-500 MW capacity will be operational by 2012 and the consecutive units a year a part. The second phase would follow after few years i.e. 2017 and 2018.

Fair and fast selection of the foreign investor or investor group is of utmost impor-tance as that process involves two typically different sectors namely mining and power generation. In this case the mine would serve the power plant only and the power plant would not have any other commercially viable options to acquire its fuel. The revenue for the project comes from the electricity exports and the revenue to PSIG would come through lignite concession fees/royalties. There is no competitive transfer pricing between the mine and power plant i.e. the bidding process is recom-mended to be integrated and simultaneous.

The following block-diagram illustrates the position of the new power plant/mine in the liberalized electricity market conditions:

The new IPP power generator with its mining operation will be parallel with the cur-rent KEK operations. The electricity sales contracts can be made directly with large

IPP

IPP Mine

PSIG

KEKGen

KEKMine

AshCo

TSO

Exports

DistributionCoSupply Co

Small consumer

Large consumer

Contracts

Delivery

Subsidyif required

Competitive markets

Controlled markets


eligible domestic consumers, supply companies and clients at the export market. The physical delivery takes place through TSO.

2 LEGAL & REGULATORY

The report on these issues by IPAEnergy Consulting/Norton Rose (March 2005) han-dles the issues into details. However, the Consultant wants to make the following comments for further development of the project:

1. We suggest a tendering process where the premium (“license fee”) for lignite would be the main parameter (highest bid wins). Other parameters for tender-ing could include other fees, quality assurance, and economic and financial feasibility of the bidding parties. The lignite premium could be paid in cash (monthly fee), with a minimum monthly threshold level (to ensure continuous power supply and to keep plant downtime and services as short as possible), or as an energy contract, or both. A premium that would include both cash pay-ments and energy supply would limit the risk of fluctuating market prices for energy. (ex. initial contract of 50% cash and 50% energy (in cash equivalent at e.g. 40 EUR/MWh, both indexed to adjust for inflation). The fee should be linked to the energy content of the lignite provided, to balance any quality fluctuations.

2. We also suggest that, except for minimum requirements for installed and

available capacity and the lignite fee, the investor should be free to select the technological solution and unit size that they prefer. Legal requirements (envi-ronmental impact, Health & Safety, Grid Code etc.) naturally apply.

3. The Investor (IPP) should be given the opportunity to decide the location of

the power plant, based on more detailed studies. 4. All players on the energy market should be provided with equal opportunities

for operation. This means that KEK should also pay a lignite premium and any additional costs for mining and ash disposal. We recommend that there should be a separate “Ash Company” that would manage the proper disposal of ash from all lignite-fired power plants (including KEK) and charge a regulated fee for that provided service. This AshCo would have regulated returns from op-erations, similarly to services provided by the TSO.

5. A tariff-based system is not recommended, as it may have unpredictable ef-

fects due to the regional electricity market. The investment is for 40 years ahead, which means that short-term preferences should not impact on the in-vestment decisions. A separate (lower) price for the domestic market will ei-ther deter investors or incur extra costs to the government in the form of en-ergy subsidies. Neither is recommended. A long-term PPA could be feasible, at market price.

6. The Market Price in Kosovo will essentially be the export price minus trans-

mission tariffs on exports, if there is a local surplus in Kosovo, and the export price plus any import transmission tariffs in case of a local shortage. If the


transmission capacity is not sufficient (this happens seldom), the price has to be determined in a different way.

7. Any existing licenses (i.e. KEK) would have to be adjusted to equal that of the

new IPP (“grandfathering” issue). 8. The IPP should (within the limits of its license conditions and energy system

and grid codes, which have not all yet been defined in detail) be able to operate the power plant freely, as long as the lignite premium is paid (minimum threshold amount applied)

9. The lignite premium will affect the energy market price – it will raise the

minimum marginal cost of production, and thus eventually also the price for end users. The effect is similar to that of energy taxation, but achieved trough a bilateral contract instead of tax regulation.

10. Investors will require some political etc. risks to be mitigated through guaran-

tees (as MIGA guarantees are not available, they could be bridge guarantees or IPP’s home country governmental export guarantees). These guarantees would also lower the risk premium required from the investment, and potentially raise the amount available for the lignite premium.

11. The time for building one power plant is estimated to between 39 (300 MW

CFB) and 48 months (500 MW PF). This means that any actions to find and investor and proceed to commissioning of a plant will have to be finished by the end of 2007 and the construction started in 2008 if the plant should be run-ning by 2012. Any regulatory framework, tendering process, feasibility studies etc. will have to be completed much earlier than that (i.e. by the end of 2006).

12. The first major hurdle for any development of a new power scheme is that the

current electricity law of Kosovo on the supply of electricity limits the term of any electricity sale contract to five years. As noted in the report of IPA/Norton Rose, this term combined with the lack of liquid spot market place for electric-ity is too short for any serious power plant development. It is of utmost impor-tance that this limitation on the term of the power sales contract is relaxed or its impacts on generation will be clarified.

13. The electricity contracts have to cover a longer time period in order to facili-

tate a secure investment environment – energy contracts should potentially (at least for a part of the total energy sales portfolio of the IPP) cover the whole period of operation, i.e. 30-40 years. 10-year contracts are standard in some market areas for long-term risk management, although not used by all power producers. Recent examples include 12-year and 15-year PPA’s (Ireland and Bulgaria). A five-year limit will prevent most if not all IPPs from investing.

14. In accordance with the guidelines set by the Athens Treaty, Kosovo is cur-

rently undergoing major electricity sector reform. A new grid company will be established, and it will in turn define and set conditions for network connection and network access for third parties. The creation of network code, network connection and network access rules are a sine qua non condition for any new power plant development.


15. International arbitration should be used to resolve disputes concerning foreign investors.

16. The process for licensing a foreign-based IPP to build and operate a power

plant should be very clear and unambiguous in order to reduce investors’ un-certainty (and risk premium).

17. The new investor(s) will require a complete freedom from any liabilities re-

garding disputes, environmental impacts (ex. polluted soil or groundwater) etc. that have occurred or been caused by events prior to the building of the new power plant. This should be guaranteed by the government. This also means that extensive sampling and testing needs to be done before building the power plant, in order to establish the correct initial situation.

18. Environmental monitoring and reporting standards should be unambiguous and

the same standards applied to all generators in the same way. The same should apply for any regulatory requirements.

19. Taxation may be an issue for investors, especially double taxation , “hidden”

taxation in the form of other regulated fees, and short period of loss carry for-ward.

20. The procurement rules used in the tendering process should be published well

ahead of the start of the tendering. The tendering process should be fair and unbiased, and limited to a pre-specified set of quantifiable parameters, in order to avoid subjective treatment of tenders.

21. There is a very limited number of equipment manufacturers for the main parts

of the recommended types of lignite-fired thermal power plants. It should be considered whether to allow or not to allow equipment manufacturers to par-ticipate in several IPP tenders, independently.

22. Even if the neighbouring utilities in the SEE region trade electricity on short-

term basis among themselves, there is currently no open electricity market place in the region for non-firm supply of electricity. As most of the export ca-pacity of Kosovo is going to be non-firm, the creation of such market place would be in the interests of Kosovo and would give significant comfort to any power plant investor on functioning of the electricity market.

23. The Government of Kosovo should take care of any expropriation of land and

other concessions (such as water use, rights-of-way etc.), preferably much prior to the tendering process, and at regulated prices. A foreign investor can-not be expected to negotiate these even supported by legislation – this would probably prevent any investment. The cost of these concessions and expropria-tions should be well covered by the lignite premium and ash disposal fees. We suggest that the land should be leased to the IPP for the generation asset life-time, with the license fee linked to an inflation/cost index.

24. According to the Norton Rose study (policy review, 2005), there may be some

problems with granting securities for debt financing of the generation assets.


25. As the total investments are on the scale of several billion Euros over a long time period, special care should be taken to prevent corruption and other fringe elements. A secure, reliable and predictable investment environment is prefer-able to most investors.

26. The IPP should be able to trade power freely through bilateral contracts or on a

(future) power exchange. Only physical constraints should apply. There should be no limitation to the volume of energy designated for export. When using market prices, the physical balance is separated from the power market – i.e. the domestic supply will be secured through purchases from the same market where the IPP will sell the energy, and physical delivery will be balanced. Net transmission will thus be far smaller than the traded energy volumes. Imposing export restrictions will seriously curtail the financial viability of the investment and may prevent IPP investments.

27. It should be noted that currently the cross-border electricity trade in the SEE

region seems to be taking place in a legal vacuum. Any investor in a potential new power scheme will require clear rules for electricity exports and imports before committing to a power sector investment in Kosovo.

28. There are currently no sufficient regulatory framework and even calculation

tools to manage the stability of the electricity network in Kosovo, and e.g. sec-ondary regulation is handled from outside Kosovo. Potential investors will give careful consideration of grid stability issues, and will seek a situation where the roles of neighbouring grid companies in stabilizing the grid are clearly defined

29. To facilitate the IPP investment, separate investments will have to be made

into cross-border interconnectors (Kosovo-Albania), transmission network and transmission system in order to handle the increased energy volumes. These also have to be guaranteed (and completed before the power plant).


3 ACTION PLAN In order to further develop this lignite fired large power plant the following steps should be taken:

3.1 Body to conduct the tendering process As there are mining and power generation parts in the development scheme and they have separate licensing bodies (ERO and ICMM) there should be a unifying sys-tem/organization to integrate and conduct the tendering process. The best thing would be “one window at the government for the Sibovc development”.

3.2 Vacate the mining area In the discussions with relevant experts and authorities it has been emphasized how slow is the process to get mines licensed and the existing population moved before really getting to physical development of the mine. It appears that this time is much more than required for the construction of the new power plant.

The process should be started immediately and also stop the apparent land speculation in the Sibovc area. The issue is that at the moment there is no firm idea wherefrom the foreign investor would start to open the mine thus making these preliminary adminis-trative actions difficult. The selection of the investor may take one and half years i.e. before the fall 2007 the exact plan is not known. A “forced” solution should be made and start to vacate the area in the Sibovc valley (areas marked 3.x in the Sibovc mine feasibility study report) as that is the most probable location to start the new mine out-side the KEK territory.

3.3 Prepare tendering documents The tendering process could be in two stages: The first round will pre-qualify the po-tential bidders what regards to their technical and financial capability to build, own and operate the mine and power plant facility. The second round would be the actual commercial tendering process but giving the bidders a lot of freedom to select the concepts and unit sizes i.e. the tendering document only specifies certain minimum requirements on the plant start-up dates vs. capacity, efficiency, emissions application of Kyoto-protocol etc.

For tendering an information package on the Sibovc is recommended to be produced. One of the crucial information is the exact chemical composition of the lignite to be fired (for boiler designers). A drilling and testing program should be launched imme-diately to make eg. one drill/km2 and take samples from top, middle and bottom part of the lignite seam and make exhaustive analysis on contents of harmful elements in the fuel. (Typical fuel analysis extent can be seen in Lot2. Draft report Annex 4, En-closure 3).

Lot 1, Tasks 6 & 7 February 6, 2006 Legal and regulatory & action plan Page 10 (10) 3.4 Establishment of ash company

The depositing of ashes from the power generation needs a permanent and environ-mentally sound solution. The foreign investor should not be forced to get involved in the past neglects or potential liabilities arising from depositing the ash into the old mines. In this respect the most convenient solution is that there will be an entity taking care of the all the ashes coming from the power plants against a ash handling fee. The fee will cover the transportation, handling and recultivation costs and possibly gener-ate some surplus to make gradually clean and recultivate the abandoned ash or over-burden piles.

3.5 Legal changes The energy, mining, environmental and tax laws should be revised in order to make them more foreign investor friendly and encourage investment in Kosovo. A fast track approach would be to draft entirely separate new law on this integrated mine and power plant development.

3.6 Make TSO operational For credibility of the electricity market functioning the newly established TSO should be brought into full functionality as soon as possible and its financial viability secured. It should develop and adopt grid code and other operational rules that are also appli-cable for the new export oriented power generator.

3.7 Visualization of the TPP development process The development process is assumed to as follows by its main activities provided that there are no hindering obstacles:

Year 1 2 3Item ´2006 ´2007 ´2008Mine developmentInfo packagePrequalificationTendering timeEvaluation awardEstablish IPPCoSign development agrmtDevelopment phase Licensing EIA-permitting Finalize EPC-contract Organize financingFinacial closingStart constructionLand lease agreementTSO agreementsPower sales contracts

The crucial moment is the financial closing by when all the permitting prior to start the actual construction has to be in place and sufficient volume of long term energy


sales contracts or the regional energy market has demonstrated that it is working and open for new players.

$FILE$

$DATE$ $TIME$/ /$USER$

Name and address of object Contents of drawing

RevisionDrawing No.Field of planning

Work No.

Date/Dsgnd

Date/AppdDate/Chkd

Drawn

Scales

Tekniikantie 4 A FIN-02150 ESPOO tel.+358-9-469 11Tekniikantie 4 A FIN-02150 ESPOO tel.+358-9-469 11

Jaakko Pöyry Group

60R05429

M120 -1001 JVL

TJS TKM

Revision Quant. Description Dsgnd/Appd Date

A1 1/2000

A3 1/4000

PRELIMINARYISSUED

TAG01

21.12.05/JVL

EAR, Kosovo

Kosovo C power plant

Site Plan for

300MW units

1. BOILER PLANT

2. TURBINE PLANT

3. COOLING TOWER

4. LIGNITE YARD

5. WATER TREATMENT

6. SWITCH YARD

3.3.

3.

1.

1.

1.

2.

2.

2.

4.

4.

5.

7. OFFICES

6.

20m 40m 60m 80m 200m

ORIGINAL SCALE

0m 20m 40m 60m 80m 100m

7.

$FILE$

$DATE$ $TIME$/ /$USER$

Name and address of object Contents of drawing

RevisionDrawing No.Field of planning

Work No.

Date/Dsgnd

Date/AppdDate/Chkd

Drawn

Scales

Tekniikantie 4 A FIN-02150 ESPOO tel.+358-9-469 11Tekniikantie 4 A FIN-02150 ESPOO tel.+358-9-469 11

Jaakko Pöyry Group

60R05429

M120 -1002 JVL

TJS TKM

Revision Quant. Description Dsgnd/Appd Date

A1 1/2000

A3 1/4000

PRELIMINARYISSUED

TAG01

21.12.05/JVL

EAR, Kosovo

Kosovo C power plant

Site Plan for

600MW units

1. BOILER PLANT

2. TURBINE PLANT

3. COOLING TOWER

4. LIGNITE YARD

5. WATER TREATMENT

6. SWITCH YARD

3.

3.

1.

1. 2.

2.

4.

4.

5.

7. OFFICES

7.

6.

20m 40m 60m 80m 200m

ORIGINAL SCALE

0m 20m 40m 60m 80m 100m

bar kJ/kg deg C kg/s

Project Name

Project Number

Designed

Plant

Description

Run Name

Description

TURSIM MODEL

17:19:34 02/06/2006 C:\User\Esk60\eskproj\kosovo\TURSIM\5_050206.MDX

KOSOVO

ESK

-

500 MWe (net) Unit

esk_20C

Kosovo 500MWe (net)One LP casing

deg C 200.4

225.00 deg C

HPH1

kg/s 16.10

0.3

deg C 234.1

255.09 deg C

HPH2

kg/s 20.22

0.3deg C 130.0

150.00 deg C

LPH4

kg/s 15.09

3.2

deg C 100.0

120.00 deg C

LPH3

kg/s 14.43

3.2

deg C 70.0

90.00 deg C

LPH2

kg/s 13.83

3.2 2.9

LPH1

60.00 deg C

kg/s 13.93

deg C 62.9

399.75 kg/s

HL

TC 190.00 bar

HL

3322.29HL

kJ/kg=0.750η

384.69 kg/s

HL

T1 45.79 bar

HL

2967.28HL

kJ/kg=0.920η

352.01 kg/s

HL

T2 27.01 bar

HL

3434.80HL

kJ/kg=0.920η

335.91 kg/s

HL

T3 12.21 bar

HL

3199.39HL

kJ/kg=0.940η

316.53 kg/s

HL

T4 5.46 bar

HL

2997.55HL

kJ/kg=0.940η

301.44 kg/s

HL

T5 2.31 bar

HL

2817.90HL

kJ/kg=0.940η

287.02 kg/s

HL

T6 0.83 bar

HL

2643.89HL

kJ/kg=0.940η

273.18 kg/s

HL

T7 0.24 bar

HL

2463.37HL

kJ/kg=0.940η

259.26 kg/s

HL

CT 0.05 bar

HL

2314.97HL

kJ/kg=0.720η

543.101 HL

MW

G1

MNC

328.99 kg/s

5.13 kPa 20.00 deg C

33.51 deg C

0.652 MW

189.74 deg C

13.645 MW

FWT 328.99kg/s

185.00 deg C bar

11.23

42.13 bar

HL

HRH

560.0 deg C

223.744 MW

1242.1 HL

MW

242.00 bar

HL560.00 H

L deg C

kg/s 399.75

0.0 kg/s

=0.880ηBOI

deg C 261.7

275.00 deg C

HPH3

kg/s 15.06

2.1

399.75 kg/s

HL

TC2 64.66 bar

HL

3044.79HL

kJ/kg=0.920η

12.45 kg/s

HL

PTC 32.00 bar

HL

3513.03HL

kJ/kg

=0.680η

13.968 HL

MW

PTL

12.45 kg/s

HL

PT2 0.05 bar

HL

2418.59HL

kJ/kg=0.852η

PC

12.45 kg/s

5.41 kPa 20.00 deg C

34.28 deg C

-0.000 MW

242.00 3380.13 0.00 399.75

399.75 kg/s

HL

275.00 deg C

328.99 kg/s

HL

150.00 deg C

LPO

40.50 kg/s

HL

33.51 deg C

LPI

40.50 kg/s

HL

150.00 deg C

HPI

96.10 kg/s

HL

275.00 deg C

HPO

96.10 kg/s

HL

189.74 deg C


Project Name

Project Number

Designed

Plant

Description

Run Name

Description

TURSIM MODEL

15:59:27 02/06/2006 C:\User\Esk60\eskproj\kosovo\TURSIM\3_050206.MDX

KOSOVO

ESK

-

300 MWe (net) Unit

300_pc

Kosovo 300MWe (net)One LP casing; Main CW 20C

deg C 200.4

225.00 deg C

HPH1

kg/s 9.85

0.3

deg C 234.1

255.00 deg C

HPH2

kg/s 12.15

0.3

deg C 138.3

155.00 deg C

LPH4

kg/s 7.82

2.7

deg C 110.0

130.00 deg C

LPH3

kg/s 8.98

3.2

deg C 73.3

100.00 deg C

LPH2

kg/s 11.35

4.2 3.0

LPH1

60.00 deg C

kg/s 8.42

deg C 63.0

235.20 kg/s

HL

TC 190.00 bar

HL

3368.12HL

kJ/kg=0.750η

235.20 kg/s

HL

T1 45.72 bar

HL

3002.68HL

kJ/kg=0.920η

223.06 kg/s

HL

T2 27.01 bar

HL

3443.00HL

kJ/kg=0.920η

213.20 kg/s

HL

T3 12.21 bar

HL

3206.34HL

kJ/kg=0.940η

202.82 kg/s

HL

T4 6.13 bar

HL

3030.55HL

kJ/kg=0.940η

195.00 kg/s

HL

T5 3.13 bar

HL

2882.17HL

kJ/kg=0.940η

186.02 kg/s

HL

T6 1.24 bar

HL

2711.17HL

kJ/kg=0.940η

174.67 kg/s

HL

T7 0.24 bar

HL

2472.36HL

kJ/kg=0.920η

166.25 kg/s

HL

CT 0.05 bar

HL

2321.68HL

kJ/kg=0.727η

334.657 HL

MW

G1

MNC

202.82 kg/s

5.13 kPa 20.00 deg C

33.37 deg C

0.077 MW

189.77 deg C

7.735 MW

FWT 202.82kg/s

185.00 deg C bar

11.23

41.15 bar

HL

HRH

560.0 deg C

129.235 MW

759.9 HL

MW

220.00 bar

HL560.00 H

L deg C

kg/s 235.20

0.0 kg/s

=0.880ηPC

202.82 kg/s

HL

154.92 deg C

235.20 kg/s

HL

254.99 deg C

LPO

24.73 kg/s

HL

33.37 deg C

LPI

24.73 kg/s

HL

155.00 deg C

HPO

58.73 kg/s

HL

189.77 deg C

HPI

58.73 kg/s

HL

255.00 deg C


Project Name

Project Number

Designed

Plant

Description

Run Name

Description

TURSIM MODEL

17:08:50 02/06/2006 C:\User\Esk60\eskproj\kosovo\TURSIM\3B050206.MDX

KOSOVO

ESK

-

300 MWe (net) Unit

Modelling

Kosovo 300MWe (net)CFB; Main CW 20C

deg C 193.9

215.00 deg C

HPH1

kg/s 9.97

0.3

deg C 227.1

255.00 deg C

HPH2

kg/s 18.43

0.4

deg C 138.3

155.00 deg C

LPH4

kg/s 8.48

2.7

deg C 110.0

130.00 deg C

LPH3

kg/s 9.73

3.2

deg C 80.0

100.00 deg C

LPH2

kg/s 9.28

3.2 4.1

LPH1

70.00 deg C

kg/s 12.91

deg C 74.1

248.17 kg/s

HL

TC 135.00 bar

HL

3370.90HL

kJ/kg=0.750η

248.17 kg/s

HL

T1 45.79 bar

HL

3081.92HL

kJ/kg=0.920η

229.74 kg/s

HL

T2 22.29 bar

HL

3352.82HL

kJ/kg=0.920η

219.77 kg/s

HL

T3 12.21 bar

HL

3180.23HL

kJ/kg=0.940η

208.77 kg/s

HL

T4 6.13 bar

HL

3008.03HL

kJ/kg=0.940η

200.28 kg/s

HL

T5 3.13 bar

HL

2862.74HL

kJ/kg=0.940η

190.56 kg/s

HL

T6 1.20 bar

HL

2689.64HL

kJ/kg=0.940η

181.28 kg/s

HL

T7 0.39 bar

HL

2523.85HL

kJ/kg=0.920η

168.37 kg/s

HL

CT 0.05 bar

HL

2310.33HL

kJ/kg=0.771η

326.466 HL

MW

G1

MNC

208.77 kg/s

5.13 kPa 20.00 deg C

33.51 deg C

0.414 MW

184.67 deg C

-0.362 MW

FWT 208.77kg/s

185.00 deg C bar

11.23

41.21 bar

HL

HRH

545.0 deg C

106.991 MW

756.8 HL

MW

165.00 bar

HL545.00 H

L deg C

kg/s 248.17

0.0 kg/s

=0.899ηCFB

LPO

16.90 kg/s

HL

33.51 deg C

LPI

16.90 kg/s

HL

155.00 deg C

HPO

43.40 kg/s

HL

184.67 deg C

HPI

43.40 kg/s

HL

255.00 deg C

208.77 kg/s

HL

154.99 deg C

248.17 kg/s

HL

255.05 deg C

kosovo ipp study 2006

Documents

new lignite

new thermal power plant

power plant development

power plant concept

mw power plant

power plant site

kosovar lignite

tons of lignite