SNC-Lavalin International Inc

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Transmission & Distribution Division CENTRAL ASIA - SOUTH ASIA ELECTRICITY TRANSMISSION AND TRADE (CASA-1000) PROJECT FEASIBILITY STUDY UPDATE Final Report February 2011 SNC-Lavalin International Inc.

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Transmission & Distribution Division

CENTRAL ASIA - SOUTH ASIA ELECTRICITY TRANSMISSION AND TRADE (CASA-1000) PROJECT FEASIBILITY STUDY UPDATE

Final Report

February 2011

SNC-Lavalin International Inc.

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NOTICE This document contains the expression of the professional opinion of SNC-Lavalin International. ("SLI") as to the matters set out herein, using its professional judgment and reasonable care. It is to be read in the context of the agreement dated April 15, 2010 (the "Agreement") between SLI and The World Bank (the "Client’), and the methodology, procedures and techniques used, SLI’s assumptions, and the circumstances and constrains under which its mandate was performed. This document is written solely for the purpose stated in the Agreement, and for the sole and exclusive benefit of the Client, whose remedies are limited to those set out in the Agreement. This document is meant to be read as a whole, and sections or parts thereof should thus not be read or relied upon out of context. Unless expressly stated otherwise, assumptions, data and information supplied by, or gathered from other sources (including the Client, other consultants, etc.) upon which SLI’s opinion as set out herein is based has not been verified by SLI; SLI makes no representation as to its accuracy and disclaims ail liability with respect thereto.

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TABLE OF CONTENTS

EXECUTIVE SUMMARY 1 INTRODUCTION ............................................................................................. 1 2 EXPORT POTENTIAL OF TAJIKISTAN AND KYRGYZ REPUBLIC ......... 2-1 2.1 Demand Projections ..................................................................................... 2-1 2.2 Existing and Committed Supply .................................................................... 2-6 2.3 Surplus Analysis ......................................................................................... 2-10 2.4 Sensitivity Analysis ..................................................................................... 2-14

3 IMPORT POTENTIAL OF PAKISTAN ......................................................... 3-1 3.1 Generation Capacity ..................................................................................... 3-1 3.2 Electricity Demand ........................................................................................ 3-3 3.3 Evaluation of Supply-Demand Balance ........................................................ 3-5

4 IMPORT AND EXPORT POTENTIAL OF AFGHANISTAN ......................... 4-1 4.1 Power Generation Assessment .................................................................... 4-1 4.2 Power Demand Situation in Kabul Region and Country ............................... 4-2 4.3 Supply-Demand Balance .............................................................................. 4-2 4.4 Review of Power Purchase Agreements (PPAs) .......................................... 4-3

5 COST OF SUPPLY ...................................................................................... 5-1 6 PROJECT SELECTION AND EXPORTABLE SURPLUS .......................... 6-1 6.1 Assessment of Optimum Size of the Project ................................................ 6-1 6.2 Project Configurations .................................................................................. 6-3 6.3 Summary of Project Options ......................................................................... 6-6 6.4 Exportable Surplus ....................................................................................... 6-8

7 TRANSMISSION LINE ROUTE ................................................................... 7-1 7.1 HVDC Transmission Line Route ................................................................... 7-2 7.2 HVAC Transmission Line (Kyr-Taj) Route .................................................... 7-4

8 TRANSMISSION NEEDS OF EXISTING NETWORKS ............................... 8-1 8.1 Transmission Needs of the Existing Network in Tajikistan ........................... 8-1 8.2 Transmission Needs of the Existing Network in the Kyrgyz Republic .......... 8-4 8.3 Transmission Needs of the Existing Network in Afghanistan ....................... 8-4 8.4 Transmission Needs of the Existing Network in Pakistan ............................ 8-4 8.5 Interconnection between the Kyrgyz Republic and Tajikistan ...................... 8-4

9 PROJECT COST AND COUNTRY WIDE ALLOCATION ........................... 9-1 9.1 Cost Estimates of the Proposed HVDC Transmission Interconnection

(Tajikistan – Afghanistan - Pakistan) ............................................................ 9-1 9.2 Cost Estimates of the Proposed HVAC Transmission Interconnection (the

Kyrgyz Republic - Tajikistan) ........................................................................ 9-2 9.3 Network Reinforcement Costs ...................................................................... 9-3 9.4 Environmental and Social Costs ................................................................... 9-3 9.5 Estimation of Total Project Costs ................................................................. 9-4 9.6 Currency Split ............................................................................................... 9-5

10 ECONOMIC ANALYSIS ............................................................................. 10-1 10.1 Methodology ............................................................................................... 10-1

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10.2 Interconnection Option for Economic Analysis ........................................... 10-3 10.3 Major Assumptions and Input Data ............................................................ 10-3 10.4 Result Summary of Economic Analysis ...................................................... 10-5 10.5 Levelized Cost of Transmission .............................................................. 10-6 10.6 Sensitivity Analysis ..................................................................................... 10-7 10.7 Country-Wise Benefit Allocation ................................................................. 10-9

11 MAJOR RISKS WITH IMPLEMENTATION AND OPERATION ................ 11-1 11.1 Security ....................................................................................................... 11-1 11.2 IGC Management ....................................................................................... 11-1 11.3 Technical .................................................................................................... 11-1 11.4 Schedule ..................................................................................................... 11-3

12 FUNCTIONAL SPECIFICATIONS ............................................................. 12-1 12.1 HVDC Transmission Line ........................................................................... 12-1 12.2 Converter Stations ...................................................................................... 12-1 12.3 Control System Concept ............................................................................. 12-2 12.4 HVAC Transmission Line ........................................................................... 12-2

13 PROJECT IMPLEMENTATION SCHEDULE ............................................ 13-1 13.1 Typical Sequence of Milestones ................................................................. 13-1 13.2 Typical Implementation Schedules ............................................................. 13-1 13.3 Award of EPC-Turnkey Contracts (18 months) .......................................... 13-7 13.4 500kV HVDC Converter Stations and Control Centre (36 months) ............ 13-7 13.5 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan (34 months)

.................................................................................................................... 13-7 13.6 500kV HVAC Transmission Line Kyrgyz-Tajikistan (30 months) ................ 13-7 13.7 Commissioning of Overall Project (4 months) ............................................ 13-8 13.8 Bidder Participation .................................................................................... 13-8

14 OPERATION AND MAINTENANCE PLAN ............................................... 14-1 15 CONCLUSIONS AND WAY FORWARD ................................................... 15-1 15.1 Conclusions ................................................................................................ 15-1 15.2 Way Forward .............................................................................................. 15-1

APPENDICES A. SDDP – Transmission Constrained Stochastic Hydro-Thermal Dispatch B. Energy Balance C. HVDC Transmission Line Route D. HVAC Transmission Line Route E. Details of Functional Specifications of HVDC Transmission Line F. Details of Functional Specifications of HVAC Transmission Line G. Details of Functional Specifications of Converter Stations and Control Scheme H. Details of Operation and Maintenance (O&M) Plan I. Notes J. Terms of Reference K. Comments to Draft Final Report

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LIST OF TABLES

Table 2-1 Kyrgyz Republic Load Forecasting Input Values Original CASA1000 Feasibility Study (Phase I) ............................................................................ 2-2

Table 2-2 Kyrgyz Republic Load Forecasting Input Values CASA1000 Feasibility Study Update .......................................................................................................... 2-2

Table 2-3 Kyrgyz Republic Projected Demand Average Growth Rates ....................... 2-3 Table 2-4 Tajikistan Load Forecasting Input Values Original CASA1000 Feasibility

Report Phase I .............................................................................................. 2-4 Table 2-5 Average Tariff Hikes as Planned by Barki Tojik ........................................... 2-4 Table 2-6 Summary of Key Assumptions – Tajikistan .................................................. 2-5 Table 2-7 Tajikistan Projected Demand Average Growth Rates .................................. 2-6 Table 2-9 Kyrgyz Republic Existing Hydro System ...................................................... 2-7 Table 2-10 Kyrgyz Republic Committed Hydro Plants .................................................... 2-8 Table 2-11 Kyrgyz Republic 2016 System – Installed Capacity and Annual Energy ...... 2-8 Table 2-12 Tajikistan Existing Thermal System .............................................................. 2-9 Table 2-13 Tajikistan Existing Hydro System ................................................................. 2-9 Table 2-14 Tajikistan Committed Hydro Plants ............................................................ 2-10 Table 2-15 Tajikistan Imports ....................................................................................... 2-10 Table 2-16 Tajikistan 2016 System – Installed Capacity and Annual Energy .............. 2-10 Table 2-17 Selected Variations of the Three Parameters (Kyrgyz Republic) ............... 2-15 Table 2-18 Average Growth Rates (Kyrgyz Republic) .................................................. 2-16 Table 2-19 Selected Variations of the Three Parameters (Tajikistan) .......................... 2-17 Table 2-20 Average Growth Rates (Tajikistan) ............................................................. 2-18 Table 3-2 Generation Capacity Development ............................................................... 3-2 Table 3-3 Demand Forecast ......................................................................................... 3-4 Table 3-4 Supply-Demand Assessment ....................................................................... 3-5 Table 6-1 Total Project Costs for the Different Size Options (in million US$) ............... 6-2 Table 6-2 Economic Evaluation for Size Optimization .................................................. 6-3 Table 6-3 Options Analysed for Optimization of Project Size ....................................... 6-7 Table 6-4 Project Configurations Analysed for 1,300 MW Taj-Afg-Pak HVDC

Interconnection ............................................................................................. 6-7 Table 6-5 Project Scenarios Analysed for Kyr-Taj HVAC Interconnection ................... 6-8 Table 8-1 Tajikistan Proposed High Level Transmission Reinforcements for the

Different CASA Options ................................................................................ 8-3 Table 8-2 Interconnection Options between the Kyrgyz Republic and Tajikistan – High

Level Cost Estimation and Transmission Losses ......................................... 8-5 Table 9-1 EPC Cost Estimate for the HVDC Tajikistan - Afghanistan - Pakistan

Interconnection (US $ Million) ...................................................................... 9-2 Table 9-2 EPC Cost Estimate for the HVAC Kyrgyz Republic - Tajikistan

Interconnection (US $ Million) ...................................................................... 9-3 Table 9-3 Network Reinforcement Costs in MUSD ...................................................... 9-3 Table 9-4 Environment and Social Costs for Pakistan, Afghanistan and Tajikistan (US $

Million) .......................................................................................................... 9-4 Table 9-5 EPC Cost Estimate for HVDC Tajikistan-Afghanistan-Pakistan and HVAC

Kyrgyz Republic-Tajikistan Interconnections (US $ Million) ......................... 9-4 Table 9-6 Total Project Cost (US $ Million) .................................................................. 9-5 Table 9-7 Total Project Costs Currency Split ................................................................ 9-5 Table 10-1 Total Project Cost of the Selected Alternative for Economic Analysis ........ 10-4 Table 10-2 Economic Analysis Results ........................................................................ 10-6 Table 10-3 Annual Transmission Costs ........................................................................ 10-7 Table 10-4 Results of Sensitivity Analysis .................................................................... 10-8

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LIST OF FIGURES

Figure 2-1 Kyrgyz Republic Demand Forecast 2010-2030 – Base Case ...................... 2-3 Figure 2-2 Tajikistan Demand Forecast 2010-2030 – Base Case ................................. 2-6 Figure 2-3 Kyrgyz Republic Average Yearly Surplus (GWh) ....................................... 2-12 Figure 2-4 Tajikistan Average Yearly Surplus (GWh) .................................................. 2-13 Figure 2-5 Combined Average Yearly Surplus (GWh) ................................................. 2-14 Figure 2-6 Kyrgyz Republic – Highest and Lowest Demand Scenarios ...................... 2-16 Figure 2-7 Tajikistan – Highest and Lowest Demand Scenarios ................................. 2-18 Figure 3-1 Energy Generation, Demand and Shortfall in 2006-07 (GWh) ..................... 3-3 Figure 3-2 Energy Generation, Demand and Shortfall in 2007-08 (GWh) ..................... 3-3 Figure 3-3 Energy Generation, Demand and Shortfall in 2008-09 (GWh) ..................... 3-4 Figure 6-2 Diagram of Recommended CASA Project .................................................... 6-6 Figure 6-3 Monthly Distribution of Exportable Surplus (1300 MW) ................................ 6-8 Figure 7-1 Proposed Transmission Line Route for CASA Project ................................. 7-1 Figure 7-2 Alternate Route to Bypass Salang Pass ....................................................... 7-3 Figure 7-3 Right of Way Constrained Existing Peshawar Substation ............................ 7-5 Figure 7-4 Proposed Converter Location for Sangtuda-II Substation ............................ 7-6 Figure 8-1 Diagram of the power flow between Nurek and Sangtuda power stations and

the load center at Dushanbe without the CASA project ............................... 8-2 Figure 8-2 Diagram of the power flow between Nurek and Sangtuda power stations and

the load center at Dushanbe with the CASA project .................................... 8-3 Figure 13-1 Typical Sequence of Milestones ................................................................. 13-1 Figure 13-2 CASA-1000 Project - Typical Implementation Schedule for Award of Turnkey

Contracts .................................................................................................... 13-3 Figure 13-3 CASA-1000 Project - Typical Implementation Schedule for 500kV HVDC

Converter Stations at Sangtuda, Kabul and Peshawar and for Control Centre .................................................................................................................... 13-4

Figure 13-4 CASA-1000 Project - Typical Implementation Schedule for 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan ................................... 13-5

Figure 13-5 CASA-1000 Project - Typical Implementation Schedule for 500kV HVAC Transmission Line Kyrgyz Republic-Tajikistan ........................................... 13-6

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EXECUTIVE SUMMARY

1 PROJECT OVERVIEW

Afghanistan, the Kyrgyz Republic, Pakistan, and Tajikistan have been pursuing the development of electricity trading arrangements and the establishment of a Central Asia - South Asia Regional Electricity Market (CASAREM). The initial plan was to export power in the range of 1,000 to 1,300 MW from the Kyrgyz Republic and Tajikistan to Pakistan and Afghanistan. The major share of the export will be used by Pakistan, and approximately 300 MW will be imported by Afghanistan. Pakistan has also expressed interest in increasing imports over the medium to long term beyond the initial power requirements of 1,000 MW.

SNC-Lavalin was commissioned to prepare a feasibility study, in two phases, for the regional interconnection. The final Phase 1 report was submitted in December 2007 and the Phase 2 report, in January 2009.

Since the 2009 report was issued, there have been significant changes in market conditions that could have an impact on the cost of the project. In addition, detailed work has been done by other consultants in the respective countries to provide additional information and allow a further assessment of the feasibility of the project.

Study Objectives

In 2010, SNC-Lavalin was again commissioned to prepare an update of the initial feasibility study. The specific objectives of this study are:

• Assessment of the availability and cost of power supply options in Tajikistan and Kyrgyz Republic;

• Assessment of the import potential of Pakistan and Afghanistan and the cost of alternatives of import;

• Assessment of the optimal size and configuration of the interconnection;

• Identification of the transmission needs of the existing networks in the countries;

• Update of line routing, control scheme, project cost, implementation plan, functional specifications, operations and maintenance plan and associated risks; and

• Update of the economic analysis.

Project Highlights

The project is based on the expectation that sufficient surplus power is available in the countries in the north to represent a substantial potential for trade with the countries in the south. Moreover, the cost of electricity in the sending countries is below the long-run marginal cost in the receiving countries, providing a justifiable rationale to invest in the transmission interconnection.

The HVDC link between Tajikistan, Afghanistan and Pakistan is comprised of 1,300 MW converters in Tajikistan and Pakistan, a 300 MW converter in Afghanistan and a 1,300 MW, 750 km transmission line. The CASA project also includes an HVAC transmission line between the Kyrgyz Republic and Tajikistan, 477 km long and rated at 1,000 MW. The recommended project following the optimization analysis is schematically shown in Figure E-1.

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The assessment of Afghanistan shows that it may have sufficient energy to meet its internal demand, and possibly have surplus energy during certain times of the year. An important feature of this configuration is that the converter capacity in Pakistan (Peshawar) is equal to that in Tajikistan (Sangtuda). This provides flexibility for Pakistan to absorb up to 1300 MW, should Afghanistan not need to import its entire share. Also, all converter stations are bi-directional; hence if the Kabul system has a surplus of power and the Tajikistan/Kyrgyz system is unable to provide the full 1,300 MW of export power, Kabul could export to Pakistan via its bi-directional converter station.

Figure E-1 Diagram of Recommended CASA Project

The proposed transmission line route for the CASA project is shown in Figure E-2. The route of the HVDC interconnection between Sangtuda in Tajikistan, Kabul in Afghanistan and Peshawar in Pakistan as well as the HVAC link between Datka in Kyrgyzstan and Khoujand in Tajikistan is also shown. The Salang Pass represents a challenge due to the space constraints inside the Salang Tunnel and in the surrounding areas.

The cost of the recommended project is US$ 873 million, excluding Interest During Construction (IDC). IDC amounts to an additional US$ 80 million. The project is economically viable based on a 10% discount rate with a Benefit/Cost ration of 1.3% and an EIRR of 15.6%.

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Figure E-2 Proposed Transmission Line Route for CASA Project

Approach and Methodology

The underlying driver for this project is that both Tajikistan and the Kyrgyz Republic have surplus energy from their hydro plants that could be used to offset severe shortages in Pakistan. The key criteria for determining the viability of the project should be based on the export of surplus power without new generation. The study was conducted for a scenario where no new generation will be added during the study period in Tajikistan and Kyrgyz Republic. Thus, if the project is economically viable for this most pessimistic condition, then it will be viable for all other scenarios as well.

The overall methodology used in the feasibility study first consisted in developing the load forecasts for the exporting countries. Their export potential was assessed taking into account the load forecasts, existing and committed power plants as well as import and export commitments. Hydro energy production capability was modeled based on historical hourly hydrological data. The import potential of Afghanistan and Pakistan was assessed using load forecasts, generation plans and other input data provided by the countries.

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The recommended project was then analysed in some detail: the exportable surplus and availability of firm power were determined, the line routing was reviewed, the costs were fine-tuned, an economic analysis was undertaken and the project risks were identified. Finally, the functional specifications, implementation schedule and operation and maintenance plan were updated.

2 EXPORT POTENTIAL OF TAJIKISTAN AND KYRGYZ REPUBLIC

The data for 2010 was incomplete at the time of preparing the studies for some of the countries, and thus data up until and including 2009 was used to ensure consistency between the load forecasts of all the countries.

The load forecast methodology used is similar to the one used by SNC-Lavalin in the original CASA study (Phase 1) that makes use of the following parameters: base year demand (GWh), demand elasticity, income elasticity, unserved energy, loss reduction program, and collection rate effort program.

The projected demand average growth rates over the next twenty years for the Kyrgyz Republic and Tajikistan are 2.6% and 1.6% respectively as summarized below for various periods.

Table E-1 Projected Demand Average Growth Rates

Period 2010-2015 2015-2025 2015-2030 2010-2030

Kyrgyz Republic 2.5% 2.1% 2.6% 2.6% Tajikistan 0.4% 1.4% 2.1% 1.6%

While the exporting countries may consider using existing thermal plants for exports, the thermal plants are rather old and their cost of generation is very high when considered as export sources. However, the use of plants with high generation costs to increase the level of firm power to be delivered could be considered but this is a contractual issue and should be considered in the development of contractual commitments.

In this study sedimentation and climate change is taken into account. Sedimentation in the Nurek reservoir is assumed to have reduced the live storage capacity by 25%, to 3,300 hm3. The effects of climate change in the region were also considered and recent inflow records were used as they provide a better approximation of the future inflows than older records.

The two countries have close to 6,000 GWh of surplus, almost entirely available in the summer months, which reduces to less than 900 GWh by 2035 as shown in Figure E-3.

With no generation expansion and an increasing demand, the Kyrgyz surplus is expected to drop from about 2,150 GWh of annual surplus in 2010 to less than 400 GWh by 2035.

Similarly, the Tajik surplus is expected to drop from 3,750 GWh at the beginning of the study horizon to about 500 GWh in 2035.

The historical water inflows show that over the years there were a number of months of severe water shortages. During these dry periods, the historical data shows that even with minimal inflows, most of the demand at peak hours can be supplied even if the full energy is

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not available on a 24 hour basis. During the initial years of the project, 1000 MW can be guaranteed with a 95% probability for the peak hours during the summer, even in a dry year.

Figure E-3 Combined Average Yearly Surplus (GWh)

3 IMPORT POTENTIAL OF PAKISTAN

The electricity sector of Pakistan is facing acute shortages in supply which have led to power outages on a large scale. The wide fluctuation of international oil prices, higher cost due to gradual phasing out of subsidy, and the circular debt problem have also exacerbated the situation of power supply in the country.

The Government of Pakistan is taking diverse measures to circumvent the problem of capacity shortage. These include expansion and refurbishment of existing plants, induction of new power plants - mainly in the private sector, encouragement of renewable energy, development of rental power plants, and acquisition of power from captive power plants.

At the end of financial year 2008-09, the total installed generation capacity in the country was 20,306 MW with 13,370 MW of thermal, 6,474 MW of hydro and 462 MW of nuclear. Current estimates indicate that over 90,000 MW of generation capacity will be required in 2030. Even with the current identified potential plants, there will be about a 10,000 MW deficit in 2030.

In view of the huge capital requirements and institutional issues, it might be difficult to build all the generation capacity as planned. In particular, for the large capacity coal-fired and hydro plants a significant investment will be required which will be difficult to obtain. For example, during the financial year 2015-16, the generation plan suggests the commissioning of 8,900 MW, which will entail a mammoth amount of investment. The substantial lead times for the construction of these power plants may also result in delays in acquiring additional capacity as planned. The likelihood of delays in commissioning of these projects cannot be ignored. Therefore, in such a scenario, the construction of CASA transmission line would contribute in alleviating the shortage of generation capacity in Pakistan.

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4 IMPORT AND EXPORT POTENTIAL OF AFGHANISTAN

The current projections for Afghanistan show that the country-wide demand in 2015 will be about 760 MW rising to about 1100 MW by 2020. It is estimated that by 2015, there will be about 1550 MW of capacity available to meet the demand. Hence a significant surplus could be exported to meet the shortages in Pakistan.

There is an element of uncertainty associated with the load forecast and the ability to develop the capacity additions within the planned timeframe. However, even with these uncertainties Afghanistan will likely have significant surplus capacity in 2015 and beyond, particularly during the summer months when Pakistan needs the power the most.

5 COST OF SUPPLY

The cost of supply for the four countries was based on information supplied and / or derived by each country and information available from international agencies.

• The cost of supply for Tajikistan is estimated at 1.5 US¢/kWh;

• For the Kyrgyz Republic, information on exports of electricity has been taken from data provided by the NEGK and JSC Power Plants, which was provided on a confidential basis;

• In Pakistan, the price that the state-owned utility (NTDC) is paying for the recent long-term PPAs with the IPPs was used as a proxy of LRMC to estimate the generation cost in Pakistan over the life time of the interconnection project. The rate for firm energy is 13.2 US cents/kWh and the rate for non-firm is 9.2 US¢/kWh; and

• The generation cost in Afghanistan is estimated to be at least 6 US¢/kWh for the study, based on the information provided by DABS. In the absence of any other credible data, this information was used for the generation cost in Afghanistan.

6 PROJECT SELECTION

Project Size

Transmission lines are manufactured in discrete step sizes and sizing the transmission lines for 1300 MW effectively restricts the capacity to about 1300 MW. It is possible to build the line with a conductor size that is capable of carrying the optimum power level (2300 MW) but limit the HVDC converter capacity initially to 1300 MW. An analysis of different transfer capabilities (1300 MW, 1800 MW, 2300 MW, 2800 MW and 3300 MW) showed that there was no major difference in the benefit / cost ratios of these options.

As the conceptual framework for the project is based on using existing low cost energy in the exporting countries to supply the importing countries, and that this energy decreased over the study period, it is preferable to build a line with a 1300 MW conductor. Should the existence of this line attract investors in the future and more energy become available than a 1300 MW CASA project can transit, another line can be built to transport this energy which could provide additional reliability to the interconnection.

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Project Configuration

A number of configurations options were investigated, including the use of a back-feed on a 220 MW line from Peshawar to Kabul. This option is not attractive for a number of reasons. In particular, it would increase the complexity of operation due to synchronization of systems without providing significant additional savings in capital cost.

The implications of eventually adding a fourth terminal to the overall scheme were also examined. The flexibility of giving four terminals would allow exports of surplus power from other countries down to Pakistan or Afghanistan. Worldwide, the implementation of four-terminal schemes does not have a positive track record and would constitute a milestone in the application of HVDC transmission. For the purpose of the CASA project, it is the Consultant’s technical recommendation that the number of terminals be limited to no more than three.

Given that Afghanistan may be in surplus during the summer and not need the original 300 MW allotment from CASA, then the 1300 MW of power from Tajikistan and Kyrgyz Republic could be delivered directly to Pakistan. Thus the recommended configuration would be at 1300 MW capacity line from the 1300 MW terminal at Sangtuda to the 1300 MW convertor terminal at Peshawar with 300 MW terminal at Kabul.

7 TRANSMISSION LINE ROUTE

A review of the route and terminal stations was carried out with particular attention to the Salang Pass and to the Kabul-Peshawar portion of the DC transmission line. Given security considerations such as demining, and operation and maintenance requirements around access to the line for repair and maintenance, the line routing recommended in the original study is deemed most suitable.

A possible alternate route that bypasses the congestion at the Salang Pass is a western detour via Shibar Pass. However, this increases the transmission line by 150 to 200 km and adds significant cost, around US$ 50 to 65 million, to the overall project.

Figure E-4 Alternate Route to Bypass Salang Pass

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8 TRANSMISSION NEEDS OF EXISTING NETWORKS

The costs of the project include an assessment of upgrades required to the existing systems to ensure reliable supply to the CASA-1000 line. In particular, a specific load swapping arrangement was studied, in the case of Tajikistan importing power from the Kyrgyz Republic for further export through the HVDC line. The load swapping arrangement allows power to flow from Kyrgyz Republic to CASA by passing through the Tajikistan system as shown in the accompanying figure. This arrangement avoids the construction of a long dedicated line from Khoujand to Sangtuda while also reducing system losses.

Figure E-5 Tajikistan Internal Power Flow with CASA

During the negotiation of commercial agreements, there are some contractual (metering and accounting) and operational (coordination and availability of line capacity) issues that will have to be addressed if the Barki Tajik internal network is used to transfer power from Khoujand to Sangtuda.

9 PROJECT COST

The project cost, excluding IDC, is estimated at US$ 873 million based on current market conditions which may change over time in response to market volatility. The basis of the costs is as follows:

• Costs of the 500 kV, 750 km HVDC interconnection link with conversion capacity of 1300 MW at Sangtuda, 300 MW at Kabul and 1300 at Peshawar;

• The costs of relocating the existing 220 kV line closer to the mountain on steel tubular poles with insulated arms and shorter spans to limit the conductor swing; and route the proposed HVDC line on steel tubular poles (option 1 of the three options proposed in section 7.2) are included in the HVDC interconnection link costs above;

• Costs of ground electrodes at Sangtuda, Kabul and Peshawar;

• Costs of the 500 kV, 477 km HVAC Interconnection between Kyrgyz republic (Datka substation) and Tajikistan (Khoujand substation);

• Costs of the country network reinforcements; and

• Costs of Environmental and Social mitigation measures.

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The cost estimates provided in this feasibility study have included provision for mitigation measures related to security, technical considerations, operational issues and routing issues.

Interest during construction (IDC) calculated at a 5% annual interest rate amounts to 80 million USD.

10 ECONOMIC ANALYSIS

The primary economic benefit of the project is the avoided costs in Afghanistan and Pakistan due to import of energy from Tajikistan and the Kyrgyz Republic. The benefits of the interconnection were assessed by comparing the system cost of generation in the exporting countries plus the cost of transmission interconnection with the cost of generation in the importing countries. The economic analysis shows that the levelized cost of transmission is calculated at 4.97 US¢/kWh.

The project is economically viable based on 10% discount rate and 30 year life of the asset, as shown below.

Table E-2 Economic Analysis Results

Benefits 1,724 MUSD

Costs 1,281 MUSD

B/C Ratio 1.34

NPV 440 MUSD

EIRR 15.6 %

Sensitivity studies showed that in the events that costs increase, energy exported decreases or discount rate increases, the project still produces favorable economic indicators with a positive NPV and a B/C ratio greater than one, in addition to achieving an EIRR greater than the discount rate.

Benefits to each country should be determined through commercial agreements that provide each country an appropriate allocation of the financial benefits to ensure adequate return to fund financial commitments.

11 PROJECT IMPLEMENTATION SCHEDULE

The project can be completed within minimum 58 months (five years) as shown in the schedule below. The critical path is driven by the supply of the converter stations (36 months).

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Figure E-6 Typical Sequence of Milestones

This completion period, however, could be delayed twelve (12) months depending on different factors such as:

• Availability and reliability of existing information and studies;

• Countries’ regulation specially for right-of way of transmission lines;

• Stakeholders and utilities intervention during works implementation; and

• Interface among Owner, contractors, utilities and countries.

While some activities could be done in parallel to save time, this would require strong leadership supported by each country through an effective project management unit.

12 CONCLUSION

The recommended project configuration provides flexibility without constraining future options and is economically viable under very conservative assumptions. Sensitivity studies show that even under adverse assumptions, the project remains viable. The biggest risk to the project viability is delays in the completion of the project, since most of the benefits are linked to the available surplus power.

Given that there are many active stakeholders, agreements need to be in place to facilitate the process of moving forward in an efficient manner.

In addition there will be challenges in coming to an agreement on operational and contractual issues. Some of the operational and contractual issues that need to be addressed in subsequent studies include risk of non payment, accounting of energy transfers and dispatch services, tariff and transit fees in addition to financing of the project.

8M

Award Consultancy

Contract

Studies

Complete

RFP

Issued

4M

12 months

Tenders Receipt

3M

Award Turnkey

Contracts

3M

HVAC Line

Ready

HVDC Line

Ready

30M 4M 2M

HVDC Converters

Ready

4M

Commissioning System

Complete

M8 M12 M15 M48 M52 M54 M58M0 M18

15 months

18 months

30 months

34 months

36 months

40 months

58 months

8 months

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1

INTRODUCTION

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1 INTRODUCTION

Afghanistan, the Kyrgyz Republic, Pakistan, and Tajikistan have been pursuing the development of electricity trading arrangements and the establishment of a Central Asia - South Asia Regional Electricity Market (CASAREM). The initial plan was to export power in the range of 1,000 to 1,300 MW from the Kyrgyz Republic and Tajikistan to Pakistan and Afghanistan. It was envisaged that the major share of the export will be used by Pakistan, while around 300 MW will be imported by Afghanistan. Pakistan has also expressed interest in increasing imports over the medium to long term beyond the initial power requirements of 1,000 MW.

SNC-Lavalin was commissioned to prepare a feasibility study, in two phases, for the regional interconnection. The final Phase 1 report was submitted in December 2007 and the Phase 2 report, in January 2009.

Since these initial reports were issued, there have been significant changes in market conditions that could have an impact on the cost of the project. Also, detailed work has been done by other consultants in the respective countries that now can provide additional information and allow a further assessment of the feasibility of the project.

The present study is an update of the initial feasibility study, with the addition of certain new elements. The overall objectives of the study are:

• Assessment of the availability and cost of power supply options in Tajikistan and Kyrgyz Republic;

• Assessment of the import potential of Pakistan and Afghanistan and the cost of alternatives of import;

• Assessment of the optimal size and configuration of the interconnection;

• Identification of the transmission needs of the existing networks in the countries;

• Update of line routing, control scheme, project cost, implementation plan, functional specifications, operations and maintenance plan and associated risks; and

• Update of the economic analysis.

The project is based on the expectation that sufficient power is available in the countries in the north to represent a substantial potential for trade with the countries in the south. Moreover, the cost of electricity in the sending countries is below the long-run marginal cost in the receiving countries, providing a justifiable rationale to invest in the transmission interconnection.

The study is conducted for a scenario where no new generation will be added during the study period in Tajikistan and Kyrgyz Republic. The objective of this conservative assumption is to assess the viability of the project for the most pessimistic generation scenario to facilitate decisions on the viability of the project. In case the project is economically viable for this scenario, then it will be viable for other scenarios as well. The requirements for the generation to be included in the base scenario were set out in the Terms of Reference (TOR) in Appendix J.

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This feasibility update report summarizes the findings based on updated information. It incorporates comments received during the course of the study, which are summarized in Appendix K. The report’s structure is based on the TOR and details of specific aspects of the report can be found in the appendices.

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2

EXPORT POTENTIAL OF TAJIKISTAN AND KYRGYZ REPUBLIC

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2 EXPORT POTENTIAL OF TAJIKISTAN AND KYRGYZ REPUBLIC

This section summarizes the assessment of the export potential from Tajikistan and the Kyrgyz Republic to Afghanistan and Pakistan via the CASA project. For this study, the export potential is defined as the power available from existing and committed supply in the exporting countries minus the internal demand of the exporting countries. Additional details, including sensitivity studies are presented in Appendix I, Note I.1.

The assessment of the export potential of Tajikistan and Kyrgyz Republic is based on the assumption that no new generation will be added in these countries during the study period. The objective of using this conservative scenario as a base case is to assess the viability of the project for the most pessimistic generation scenario. In case the project is economically viable for this scenario, then it will be viable for other scenarios as well. As such, and per the TOR, power plants that satisfy the following criteria will be taken into consideration in the export potential assessment: existing plants or new plants that are already under construction, have committed financing, and can be reasonably accepted to be commissioned in the next few years.

2.1 Demand Projections

The methodology used in this study is an analytical method similar to the one used by SNC-Lavalin in the original CASA study (Phase 1) that makes use of the following parameters:

• Base year demand (GWh),

• Demand elasticity,

• Income elasticity,

• Unserved energy,

• Loss reduction program, and

• Collection rate effort program.

2.1.1 The Kyrgyz Republic – Electricity Demand Projections

Input Data

The Kyrgyz Republic presented a list of major projects along with their demand requirements, dates of commissioning and implementation probabilities. With rather broad assumptions, the demand projections provided by the Kyrgyz Republic cover the period 2010-2025 with 5-year steps from 2015, with little details except that the annual demand growth rate is held constant at 2% from 2015 on.

Other historical electric data provided include: short historical sales (2004-2009), tariffs, unserved energy and losses, as well as energy saving measures (DSM).

It is important to note that at the time of issuance of this report, the data available for 2010 is partial. Therefore, to ensure reliability of load forecast results and consistency between the load forecasts of the Kyrgyz Republic and Tajikistan, data up until and including 2009 was used.

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Assumptions

The values used for the Kyrgyz Republic (Phase 1) in the previous study are presented in Table 2-1 below.

Table 2-1 Kyrgyz Republic Load Forecasting Input Values Original CASA1000 Feasibility Study (Phase I)

Parameter Value

Price Elasticity -0.15 Income Elasticity 0.8 GDP Growth 4% for 2007, 5% for 2008, 4% for 2009 and onwards Tariff path 2007-2014 2.31 – 3.12 US cents/kWh, hence ΔT = 4% Losses Reductions 23% in 2006 to 13% in 2011, hence ΔL(t) = -2.4% Collection rate 98% by 2015

In the present study, the parameter values in Table 2-1 are updated as shown in Table 2-2 below:

Table 2-2 Kyrgyz Republic Load Forecasting Input Values CASA1000 Feasibility Study Update

Parameter Value

Price Elasticity -0.15 Income Elasticity 0.8

GDP Growth

GDP Forecast Estimates by IMF Staff (2010-2015)1 : 2010: -3.5%; 2011: +7.1% (rounded off to 7.0%); 2012: +6.4% (rounded off to 6.5%); 2013: +6.1% (rounded off to 6.0%); 2014: +5.9% (rounded off to 6.0%); 2015: +4.7% (rounded off to 4.5%). From 2016 onwards: +4.5%.

Tariff path 2009-2014 ΔT = 4%

Losses Reductions

Reduced from 29% (T:8% D:21%) in 2009 to 26% (T:8% D:18%) in 2010 according to stated objective of the Utility; then, the same reduction rate for next 2 years; -2% for next 2 years; and, then -1% to 2015 and onwards up to 2025.

Collection rate 98% by 2015

The starting demand figures (in GWh) are updated to 2009 values that incorporate: sales + losses + unserved energy. The 2009 actual figures add up to 12.3 TWh, which includes an unserved energy of 2.3 TWh2.

1 Source: http://www.imf.org/external/pubs/ft/weo/2010/02/weodata/index.aspx 2 Source: Annexe 2‐f, a spreadsheet in Excel file [Annexes_data request.xls] sent by Kyrgyzstan.

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Results

The following results (base case) are then obtained:

Figure 2-1 Kyrgyz Republic Demand Forecast 2010-2030 – Base Case

The average growth rates of the projected demand are as follows:

Table 2-3 Kyrgyz Republic Projected Demand Average Growth Rates

Period 2010-2015 2015-2025 2015-2030 2010-2030

Average Growth 2.5% 2.1% 2.6% 2.6%

2.1.2 Tajikistan – Electricity Demand Projections

Input Data and Assumptions

The same methodology as in the Kyrgyz Republic is used for Tajikistan. Tajikistan has identified a number of detailed issues with respect to load forecast, availability of power and cost of supply. As this report addresses high level issues, given specific conditions as outlined in the Terms of Reference (see Appendix J), these issues have been considered in the analysis. However, only those items within the framework of the Terms of Reference were considered in depth.

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Demand 11.6 11.9 12.2 12.5 12.8 13.1 13.4 13.6 13.9 14.2 14.5 14.8 15.2 15.5 15.8 16.1 16.7 17.3 17.9 18.6 19.2

0.0

5.0

10.0

15.0

20.0

25.0

TWh

Kyrgyzstan Demand Forecast: 2010‐2030

Demand

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For Tajikistan, the parameter values used in the original CASA-1000 study were as follows:

Table 2-4 Tajikistan Load Forecasting Input Values Original CASA1000 Feasibility Report Phase I

Parameter Value

Price Elasticity -0.15 Income Elasticity 0.6 GDP Growth 7.5% for 2007, 7.1% for 2008, 4% for 2009 and onwards Tariff path 2007-2010 0.68 – 2.50 US cents/kWh Losses Reductions 13% in 2006 to 10% in 2010 Collection rate 98% by 2014

In the present study, while the price elasticity, GDP growth rate and collection rate figures are kept the same as in Phase I, the other parameters updated are: income elasticity, losses and the special status of TALCO with respect to the Tajikistan demand.

The income elasticity is considered the same as for the Kyrgyz Republic (KR). In 2008 the losses were estimated at 3.0 TWh out of a 17.0 TWh internal consumption3, which is about 17.6%. The assumption is made that these losses will shrink to 10% by the year 2020. This loss reduction goal corresponds to an annual 0.9% reduction from 2010 to 2020.

The demand share of TALCO is nearly half of the entire country, from 40 to 50% annually. In the present study, it is assumed to be 45% (at base year). Furthermore, it is also assumed that TALCO’s demand (in GWh or TWh) stays stationary throughout the entire forecast period.

Tariff hike figures used in the demand forecast (in view of price elasticity of demand) are from Barki Tojik (BT). These tariff hikes are given in Table 2-5.

Table 2-5 Average Tariff Hikes as Planned by Barki Tojik

Indicators Years

2010* 2011*

(planned) 2012*

(planned) 2013*

(planned)

Average tariff (in diram) 7.75 9.60 11.30 13.75

Source: Data from BT, December 2010.

In growth rates (percentages), these planned tariff hikes are translated as follows:

2010: 7.75 dirams (+25%) 2011: 8.45 dirams (+24%) 2012: 9.08 dirams (+18%) 2013: 9.67 dirams (+22%)

3 Source: State Statistical Committee of the Republic of Tajikistan with Assistance of UNDP Tajikistan (www.stat.tj).

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The unserved energy was evaluated at 2,650 GWh for 2006 while the Net Supply4 which can be considered as the sum of sales and losses was 17,750 GWh. In 2009, the net supply was 16,243 GWh. Considering that the unserved energy situation has not improved between 2006 and 2009, it is deemed that actually the drop in the net supplies between 2006 and 2009 can be considered as additional unserved energy. Conservatively, three fourths of the difference in the two net supplies are considered as additional unserved energy for 2009.

The starting demand figures (in GWh) for 2009 for Tajikistan (including TALCO) are then established as the sum of the Net Supply (that encompasses Sales and Losses) and the Unserved Energy. The following table summarizes these key assumptions.

Table 2-6 Summary of Key Assumptions – Tajikistan

Parameter Tajikistan

GDP 3.4% from 2009 to 2015 (as proposed by BT). Then 4% from 2016 onwards.

Income Elasticity of Demand 0.8 Unserved Energy: level of 2009 • Level of 2006 (2,650GWh), plus

• 75% of the difference between the Net Supply of 2006 (17,750 GWh) and Net Supply of 2009 (16,243 GWh).

= 3,780 GWh Price Elasticity of Demand -0.15 Tariff Hikes As planned by BT Losses in 2009 Loss Reduction

Included in Net Supply. -0.5% p.a. other 10 years from 17% in 2010 to 13% to 2020 (objectives of Tajikistan)*.

2009 Demand Net Supply + Unserved Energy = 20.0 TWh

* Loss reduction objectives as of December 2010.

4 Net Supply = Production + Import – Export.

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Results

Applying the same methodology as in the Kyrgyz Republic to establish the growth rate of the demand without TALCO, the following forecast results (base case) are obtained. The graph represents TALCO’s demand (flat) and the entire country demand (including TALCO).

Figure 2-2 Tajikistan Demand Forecast 2010-2030 – Base Case

The average growth rates of the projected demand are as follows:

Table 2-7 Tajikistan Projected Demand Average Growth Rates

Tajikistan 2010-2015 2015-2030 2010-2030 2010-2025

Country (incl. Talco) 0.3% 2.1% 1.6% 1.4%

Without Talco 0.5% 3.0% 2.4% 2.1%

2.2 Existing and Committed Supply

2.2.1 The Kyrgyz Republic – Existing and Committed Supply

Existing System

The Kyrgyz Republic’s existing system is mainly hydro (2,910 MW, 85%), with some thermal plants (530 MW, 15%) providing the extra energy in dry seasons and peak periods.

• Thermal Plants:

The thermal system consists mostly of the Bishkek plant, with a minor contribution from the Osh plant. These plants are old and with very high variable cost, mainly used during winter. The capacities shown reflect the projected rehabilitation and the maximum attainable energy production; however the plants are not being considered as a source for exports to CASA.

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

TALCO 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3

Country 20.0 19.9 19.8 19.8 19.7 20.0 20.3 20.6 21.0 21.4 21.8 22.1 22.6 23.1 23.6 24.1 24.7 25.2 25.8 26.4 27.0 27.6

0.0

5.0

10.0

15.0

20.0

25.0

30.0

TWh

Tajikistan Demand Forecast: 2010‐2030

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While the Kyrgyz Republic would like to use existing thermal plants for exports, the thermal plants are rather old and their cost of generation is very high to be considered as an export source. The use of old thermal generation plants to increase the level of firm power to be delivered is a contractual issue to be determined when contracts are negotiated. Since the value of firm energy is higher than non-firm energy, the use of older plants to guarantee a higher level of firm power could be considered in the development of contractual commitments. This analysis is outside the scope of this current study.

Table 2-8 Kyrgyz Republic Existing Thermal System

Plant Name Installed Capacity (MW) Annual Energy (GWh)

Bishkek 495 3,400 Osh 35 190

Total 530 3,590

• Hydro Plants:

The hydro system relies on the Toktogul reservoir and hydro power plant (1,200 MW, 5,110 GWh/year). Downstream plants benefit from Toktogul’s turbined outflow as a regulated inflow, and provide a considerable amount of annual energy (7,235 GWh).

Table 2-9 Kyrgyz Republic Existing Hydro System

Plant Name Type Installed Capacity (MW) Annual Energy (GWh)

Toktogul Reservoir 1,200 5,110

Kurpsai Run-of-River 800 3,315

TashKumyr Run-of-River 450 1,895

Shamaldysai Run-of-River 240 935

Ush-kurgan Run-of-River 180 950

At-Bashi Run-of-River 40 140

Total 2,910 12,345 Committed Plants In this present study, new additional generation expansion, apart from new committed plants, is not considered. However, plants that are committed for development and would be commissioned prior to 2016 (first year of this study) are taken into consideration as they would constitute a part of the existing system in 2016.

• Thermal Plants:

The Kyrgyz Republic has no thermal commitments or rehabilitations of plants prior to 2016.

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• Hydro Plants:

Work has already started on the Kambarata 2 HPP and the first unit of 120 MW is expected to be commissioned before January of 2016.

Table 2-10 Kyrgyz Republic Committed Hydro Plants

Plant Name Type Installed Capacity (MW) Annual Energy (GWh)

Kambarata 2 Run-of-River 120 800

With the addition of this plant, the total capacity of the Kyrgyz system in 2016 would be:

Table 2-11 Kyrgyz Republic 2016 System – Installed Capacity and Annual Energy

Type Installed Capacity (MW) Annual Energy (GWh)

Hydro Plants 3,030 13,145 Thermal Plants 530 3,590

Total 3,560 16,735

2.2.2 Tajikistan - Existing and Committed Supply

Existing System

Tajikistan’s existing system is mainly hydro (4,900 MW, 94%), with some thermal plants (318 MW, 6%) providing extra energy in dry seasons and peak periods.

• Thermal Plants:

Existing thermal plants consist of the rehabilitated Dushanbe plant and the Yavan plant. Dushanbe and Yavan are being converted from gas to coal plants. These plants are old and with very high variable cost, mainly used during winter. The capacities shown reflect the projected rehabilitation and the maximum attainable energy production; however the plants are not being considered as a source for exports to CASA.

Similar to the situation in the Kyrgyz Republic, the cost of thermal generation in older plants is too high to be considered as an export source. The use of old thermal generation plants to increase the level of firm power to be delivered is a contractual issue to be determined when contracts are negotiated. Since the value of firm energy is higher than non-firm energy, the use of older plants to guarantee a higher level of firm power could be considered in the development of contractual commitments. This analysis is outside the scope of this current study.

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Table 2-12 Tajikistan Existing Thermal System

Plant Name Installed Capacity (MW) Annual Energy (GWh)

Dushanbe 198 1,300 Yavan 120 790

Total 318 2,090

• Hydro Plants:

Most of Tajikistan’s hydro production comes from the Nurek reservoir and power plant (3,200 MW, 11,850 GWh/year). Nurek’s outflow regulates the inflow for downstream plants, which produce around 6,710 GWh annually. Kairakkum has its own reservoir and produces 755 GWh annually.

Sangtuda 1’s capacity has been increased by 167.5 MW in the Table 2-13 below, with the commissioning of the fourth unit which will occur prior to 2016.

Table 2-13 Tajikistan Existing Hydro System

Plant Name Type Installed Capacity (MW) Annual Energy (GWh)

Nurek (1) Reservoir 3,200 11,850

Baipaza Run-of-River 600 2,525

Sangtuda 1 Run-of-River 670 2,970

Golovnaya (2) Run-of-River 220 840

Perepa (2) Run-of-River 30 250

Central (2) Run-of-River 30 125

Kairakum Reservoir 126 755

Varzob Run-of-River 25 205

Total 4,901 19,520 (1) Includes the rehabilitation of Nurek from 3,000 MW to 3,200 MW. (2) Includes the rehabilitation of Golovnaya, Perepa and Central, from 255 MW to 280 MW.

Committed Plants

In this present study, generation expansion is not considered. However, plants that are committed for development and would be commissioned prior to 2016 (first year of this study) are taken into consideration as they would constitute a part of the existing system in 2016.

• Thermal Plants:

Tajikistan has no thermal commitments or rehabilitations of plants planned prior to 2016.

• Hydro Plants:

The second hydro development in Sangtuda is to be commissioned before 2016. It has 220 MW of capacity and would generate close to 1,000 GWh annually.

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Table 2-14 Tajikistan Committed Hydro Plants

Plant Name Type Installed Capacity (MW) Annual Energy (GWh)

Sangtuda 2 Run-of-River 220 955

Imports

Tajikistan used imports from Turkmenistan in the winter months (October to March) to meet its demand and clear its deficits. Historical data indicate close to 1.2 TWh of average annual imports. The future availability of this energy is in question due to the disconnection of the electrical link between Uzbekistan and Tajikistan. The reduction of these imports would increase the winter deficits. They have not been considered in the base case evaluation of the surplus.

Table 2-15 Tajikistan Imports

Country Months Import Annual Energy (GWh)

Turkmenistan Winter (Oct-Mar) 1200

With the addition of Sangtuda 2, the total capacity of the Tajik system in 2016 would be:

Table 2-16 Tajikistan 2016 System – Installed Capacity and Annual Energy

Type Installed Capacity (MW) Annual Energy (GWh)

Hydro Plants 5,121 20,475 Thermal Plants 318 2,090

Total 5,439 22,565

2.3 Surplus Analysis

2.3.1 Modeling Assumptions

Study Period

In this section, the total energy surplus of the Kyrgyz Republic and Tajikistan is assessed on a monthly basis. Using SDDP5, both systems were modeled, along with the load forecast and the simulation were run for the entire study period. The study period begins in 2016, year of commissioning of the CASA line. It extends for 20 years and the final month of simulation is December of 2035.

Load Forecast

Annual energy projections from Section 2.2 are used to forecast monthly load duration curves by scaling historical Load Duration Curves (LDCs) with a factor equal to the growth rate. Load duration curve forecasts are then modeled in SDDP using 3 load blocks for every month: a peak load, a medium load and a base load.

5 Stochastic Dual Dynamic Programming (SDDP) Power System Simulation Program

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Hydrological Data

To simulate a system with hydro power plants, using SDDP historical inflow records at considered hydro sites are required. The historical data is used to simulate the inflow during the years of the study period to have a more realistic scenario. For this purpose, in this study the historical data chosen is from 1987 to 2009. Using the most recent inflow records provides a better approximation of the future inflows. Several reports consulted, including Potential impacts of Climate Change on the hydrological regime of Tajikistan and the Kyrgyz Republic at the horizons 2050 and 2080 by Ouranos, dated May 2008, indicate that gradual changes in the shape of the annual hydrograph will take place in the upcoming years up to 2050 due to the effects of temperature increase and glacier melting. Increased spring and summer runoff due to glacier melt is expected in the region.

Obtaining Average Energy Surplus Values from SDDP Using Historical Hydrological Data

It is important to note that the analysis for exportable surplus does not use average values for hydrology scenarios. The exportable surplus is calculated using 23 historical hydrological years (for years 1987-2009). The first simulation assumes that the hydrology of 2016, the first year of the study period, will correspond to the hydrology of 1987 (2017 will correspond to 1988, etc.) and calculates the exportable surplus for each year of the study horizon, taking into account transmission capacity constraints. The simulation is repeated assuming that the hydrology of 2016 will correspond to the hydrology of 1988 (2017 will correspond to 1989, etc.), again taking into account the transmission constraint in obtaining the exportable surplus. This simulation is run 23 times, rotating the year that would correspond to the hydrology for 2016. For each year, the 23 simulated values are averaged to obtain the ‘average’ value for exportable surplus. This method differs from the approach using average hydrology values and addresses the difficulties of taking transmission constraints into account when using the latter approach.

Appendix A presents an overview of the SDDP model and more detailed explanation about the manner in which the historical hydrologies are used.

Reservoir Levels

Initial reservoir levels are assumed to be 100% at the start of the 2015-2016 winter for Nurek and Toktogul. Deficits in the winter months may be observed if not enough water is stored in the summer when inflows are historically high.

Toktogul HPP

Based on information provided by the Kyrgyz Republic regarding agreements with riparian states, the flow of the Toktogul HPP was limited to 600 m3/s in the winter months (October – March). In addition it was suggested to have the reservoir level above a minimum value of 10,000-12,000 Hm3 needed in the beginning of the summer (April 1st). The flow constraint was modeled in SDDP and the reservoir level at the beginning of April was checked in every simulation.

Nurek HPP

The modeling of the Nurek reservoir was based on the actual operating mode wherein the reservoir is fully filled in summer and reduced in winter so as to utilize all the available storage to reduce, which reduces the winter deficits to a minimum.

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Nurek Reservoir Sedimentation

It is understood that the Nurek reservoir has been experiencing sedimentation that is affecting its live storage. It was found that sedimentation reduces the storage for the winter hence increases winter deficits but it also increases summer generation and surplus since the plant will turbine the added inflow. In this study sedimentation is taken into account and the Nurek reservoir is assumed to have been reduced by 25%, with 3,300 hm3 live storage.

Existing Exports

By 2016, Tajikistan should be exporting to Afghanistan through a 220 KV line, rated at 300 MW. The annual exports would be close to 650 GWh. In the SDDP simulations, these exports are modeled only in the summer months (April-September), when the system has the most surplus.

Supplies to Afghanistan and Pakistan During Peak Periods

Given the regulation capabilities of the main hydro cascades in Tajikistan and Kyrgyzstan provided by the reservoirs of Nurek and Toktogul, whenever there is a limited energy condition (e.g. during periods where the exported energy is such that the capacity of the CASA line is not fully utilized), it has been assumed that the exports during summer can be scheduled at the peak hours of the receiving systems so as to maximize the value of this energy for the importer.

2.3.2 Kyrgyz Republic Surplus

Using the modeling assumptions from the previous subsection and the existing/committed system defined in Section 2.2.1, the Kyrgyz Republic’s average energy surplus is shown in Figure 2-3 below:

Figure 2-3 Kyrgyz Republic Average Yearly Surplus (GWh)

With no generation expansion and an increasing demand, the surplus is expected to drop as observed in Figure 2-3. At the beginning of the study horizon, a little above 2,150 GWh of annual surplus are available in the Kyrgyz system. However by 2035, less than 400 GWh can be exported from the Kyrgyz Republic annually.

0

500

1,000

1,500

2,000

2,500

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

GWh

Year

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Monthly balances for the years 2016; 2020; 2025; 2030 and 2035 are presented in Appendix B.

2.3.3 Tajikistan Surplus

Using the modeling assumptions from the previous subsection and the existing/committed system defined in Section 2.2.1. Tajikistan’s average yearly energy surplus is shown in Figure 2.4 below:

Figure 2-4 Tajikistan Average Yearly Surplus (GWh)

With no generation expansion, the surplus is expected to drop as observed in Figure 2-4. At the beginning of the study horizon, close to 3,750 GWh of annual surplus are available in the Tajik system. However by 2035, a little under 500 GWh can be exported from Tajikistan annually.

Monthly balances for the years 2016; 2020; 2025; 2030 and 2035 are presented in Appendix B.

2.3.4 Combined Surplus

The surpluses of both countries are added together to obtain the combined average yearly surplus for the CASA region:

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

GWh

Year

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Figure 2-5 Combined Average Yearly Surplus (GWh)

The region has close to 6,000 GWh of surplus, almost entirely available in the summer months. That surplus drops to less than a 900 GWh in 20 years with no generation expansion and an increasing demand.

2.4 Sensitivity Analysis

2.4.1 Dry Season Sensitivity Analysis

Since the values presented in the previous sub-section are averages over 23 possible hydrology scenarios, a sensitivity analysis was conducted to assess the potential surplus of the region during the driest years as well as during the wettest years. The scenarios giving the best and worst surplus were examined.

With 1989 being historically the worst year from an inflow point of view for Nurek, If that year repeats in 2016, there would be just a little over 1,000 GWh of surplus (1,094 GWh) compared to the 5,900 GWh average (close to 82% drop). But if a better year like 1988 repeats, the surplus can exceed the average by more than 4,000 GWh to reach 9,971 GWh.

The volatility of the surplus renders the energy available for export mostly non-firm with the yearly average close to 5,900 GWh.

The complete set of results for this sensitivity is available in Appendix I Note I.1 with tables and graphs showing the best and worst 5 years, also comparing the 23 years to the average.

2.4.2 Demand Sensitivity Analysis

The results of the demand study in both the Kyrgyz Republic and Tajikistan as provided in Section 2.1, which are considered as the Base Case results, were obtained by using assumptions that included three key parameters, which are:

• Tariff increase, which is closely related to price elasticity of demand;

• Income elasticity factor; and,

• Electricity loss reduction over the years.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

GWh

Year

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In this subsection the impacts on the results of the variations of these parameters are analyzed.

The Kyrgyz Republic

Several combinations of the variations of the three key parameters —tariff increase rate, income elasticity values and electricity loss reduction rate— were investigated. The following table (Table 2-17) summarizes a selected set of combinations of variations of these parameters, where the shaded cells reflect changes with respect to the Base Case figures as laid out in Table 2-2 of Section 2.1.1.

Table 2-17 Selected Variations of the Three Parameters (Kyrgyz Republic)

Case Tariff Increase

Income Elasticity Loss Reduction Rate

Base Case

4% p.a. up to 2015 Then 3% afterwards

0.8 As follows: -3% p.a. up to 2012

-2% p.a. to 2014

-1% p.a. to 2015

-1% 2016– 2025

Scenario1 No increase

same as Base Case

same as Base Case

Scenario 2 6% p.a. up to 2015

same as Base Case

same as Base Case

Scenario 3 same as Base Case

0.7 same as Base Case

Scenario 4 same as Base Case

0.9 same as Base Case

Scenario 5 same as Base Case

same as Base Case

50% lower than Base Case, i.e.

-1.5% p.a. up to 2012

-1% p.a. to 2014

-0.5% p.a. to 2015

0% after-wards

Scenario 6 same as Base Case

same as Base Case

50% faster than Base Case, i.e.

-4.5% p.a. up to 2012

-3% p.a. to 2014

-1.5% p.a. to 2015

0% after-wards

Scenario 7 No increase

same as Base Case

No Loss Reduction

Scenario 8 No increase

same as Base Case

50% slower than Base Case, i.e.

-1.5% p.a. up to 2012

-1% p.a. to 2014

-0.5% p.a. to 2015

0% after-wards

The simulations yielded that Scenario 7, representing the status quo, i.e. no tariff increase and no electricity loss reduction, resulted in the highest demand throughout the forecast period (2010-2030), as was to be expected. On the other hand, Scenario 6 — additional loss reduction — produced the lowest demand. These findings are illustrated in Figure 2-6.

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Figure 2-6 Kyrgyz Republic – Highest and Lowest Demand Scenarios

The average growth rates corresponding to the maximum and minimum demand scenarios are compared to the base case average growth rates in Table 2-18 below.

Table 2-18 Average Growth Rates (Kyrgyz Republic)

Base Case Scenario 6 Scenario 7

2010‐2015 2.5% 1.4% 5.1%

2015‐2025 2.1% 1.6% 3.6%

2010‐2030 2.6% 2.0% 3.9%

Tajikistan

For Tajikistan as well, several combinations of the variations of the three key parameters —tariff increase rate, income elasticity values and electricity loss reduction rate — were investigated. The following table (Table 2-19) summarizes a selected set of combinations of variations of these parameters, where the shaded cells reflect changes with respect to the Base Case figures as laid out in Table 2-6.

0.0

5.0

10.0

15.0

20.0

25.0

30.0(TWh)

Scenario 6 Base Case Scenario 7

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Table 2-19 Selected Variations of the Three Parameters (Tajikistan)

Case Tariff Increase

Year Income

Elasticity Loss Reduction

Rate 2009-2010

2010-2011

2011-2012

2012-2013

Base Case as planned by BT, i.e., 25% 24% 18% 22% 0.8 -0.5% p.a. to 2020

Scenario 1 No increase same as Base Case same as Base Case

Scenario 2 +1% higher increase except for 2010 same as Base Case same as Base Case

Scenario 3 same as Base Case 0.7 same as Base Case

Scenario 4 same as Base Case 0.9 same as Base Case

Scenario 5 same as Base Case same as Base Case

50% slower than in Base Case, i.e. -0.25% to yr 2020

Scenario 6 No increase same as Base Case

50% faster than in Base Case, i.e. -0.75% to yr 2020

Scenario 7 No increase same as Base Case No loss reduction

Scenario 8 No increase same as Base Case

50% slower than in Base Case, hence, -0.25% to yr 2020

As in The Kyrgyz Republic, the simulations virtually yielded the same situations in Tajikistan: Scenario 7, representing the status quo, i.e. no tariff increase and no electricity loss reduction, resulted in the highest demand throughout the forecast period (2010-2030). On the other hand, Scenario 6 — a faster loss reduction — produced the lowest demand, although it gives virtually the same results as Scenario 3 — Income elasticity of 0.7 —, with the latter scenario giving slightly lesser demand towards the end of the forecast period. These findings are illustrated in Figure 2-7.

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Figure 2-7 Tajikistan – Highest and Lowest Demand Scenarios

The slight drop in demand in the first years 2010–2013, for both the Base Case and Scenario 6, is due to the rather substantial tariff increase in that period — +25%, +24%, +18% and +22%, respectively. The average demand growth rates for the three displayed scenarios (Base, Highest and Lowest) are given in Table 2-20.

Table 2-20 Average Growth Rates (Tajikistan)

Base Case Scenario 6 Scenario 7

2010-2015 0.4% 0.2% 1.8% 2015-2030 2.1% 2.0% 2.3% 2010-2030 1.6% 1.6% 2.2%

2.4.3 Effect of Demand sensitivities on Surplus

All of the scenarios mentioned in the previous section provided new demand forecasts. These forecasts were taken and entered into the database of the model, replacing the base case demand, and a new surplus evaluation was made for each scenario.

The scenarios that made the most impact on the surplus were:

- Scenario 7 decreased the 2016 surplus in Tajikistan by 18%. It also decreased the Kyrgyz 2016 surplus by 47%.

- Scenario 3 increased the Tajik surplus by 4% ,

- Scenario 2 increased the Kyrgyz surplus by 23%.

The complete results of these scenarios are presented in Appendix I, Note I.2.

These results show how modifying the demand affects the surplus when no generation expansion is planned for the study period. The Kyrgyz surplus is more vulnerable to change due to the demand increase or decrease.

10.0

15.0

20.0

25.0

30.0

35.0

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

(TWh)

Scenario 6 Base Case Scenario 7

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3

IMPORT POTENTIAL OF PAKISTAN

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3 IMPORT POTENTIAL OF PAKISTAN

The electricity sector of Pakistan is facing acute shortages in supply which have led to power outages on a large scale. The wide fluctuation of international oil prices, higher cost due to gradual phasing out of subsidies, and the circular debt problem have also exacerbated the situation of power supply in the country.

The Government of Pakistan is taking diverse measures to circumvent the problem of capacity shortage. These include expansion and refurbishment of existing plants, induction of new power plants - mainly in the private sector, encouragement of renewable energy, development of rental power plants, and acquisition of power from captive power plants.

This section presents the demand-supply balance till the year 2030 taking into account the generation expansion plan and the load forecast developed by NTDC.

3.1 Generation Capacity

At the end of financial year 2008-09, the total installed generation capacity in the country was 20,306 MW. The share of thermal, hydro and nuclear capacities was 13,370 MW, 6,474 MW and 462 MW respectively. The details of the growth of generation capacity for the period 2003-04 to 2008-09 are provided in Table 3-1 below. For consistency among the countries, installed capacity numbers are used.

Table 3-1 Installed Generation Capacity by Type (MW)

Financial Year ending 30th June 2003-04 2004-05 2005-06 2006-07 2007-08 2008-09

THERMAL GENCOs 4,834 4,834 4,834 4,834 4,899 4,899IPPs connected with PEPCO system 5,715 5,743 5,743 5,893 6,129 6,299IPPs connected with KESCL system 262 262 262 262 262 262KESCL own GENCO 1,756 1,756 1,756 1,756 1,756 1,910Sub-total 12,567 12,595 12,595 12,745 13,046 13,370

HYDEL WAPDA 6,463 6,463 6,463 6,444 6,444 6,444IPPs 30 30 30 30 30 30Sub-total 6,493 6,493 6,493 6,474 6,474 6,474

NUCLEAR CHASNUPP (connected with PEPCO system) 325 325 325 325 325 325

KANUPP (connected with KESCL system) 137 137 137 137 137 137

Sub-Total 462 462 462 462 462 462

Total Installed Capacity of the Country 19,522 19,550 19,550 19,681 19,982 20,306

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From the information available the total installed capacity for the financial year 2009-10 is 20,731 MW.

In order to have comprehensive information on the generation expansion plan for the assessment of supply-demand balance and import potential, the Consultant had meetings with NTDC (National Transmission Despatch Company) and obtained the requisite data on their generation expansion plan till the financial year 2029-30. The plan envisages the expansion in the generation capacity by development of power plants by WAPDA (mainly hydro), IPPs, Gencos, and rental power.

In view of the current acute shortages of electric power in the country and to quickly circumvent the problem of these capacity shortages, the government has planned to induct rental power plants in the year 2010-2011. According to the generation development plan obtained from NTDC, it is envisaged that about 1100 MW of rental power plants will be commissioned during the current financial year. It is expected that these plants would help in mitigating the power shortages in the country in the short term.

The total yearly forecasted capacity of the generation system provided by NTDC for the period 2010-11 to 2029-30 is provided in Table 3-2 below.

Table 3-2 Generation Capacity Development

Year Generation Capacity (MW)

2010-11 22697 2011-12 23788 2012-13 26279 2013-14 29405 2014-15 33630 2015-16 42350 2016-17 45338 2017-18 50034 2018-19 53284 2019-20 58867 2020-21 63683 2021-22 68349 2022-23 70014 2023-24 70614 2024-25 76214 2025-26 79014 2026-27 83014 2027-28 84014 2028-29 88334 2029-30 N/A

In the above generation capacity expansion plan, a relatively significant capacity would be added during the period 2014 to 2016. This will mainly be from the commissioning of large capacity coal-fired power stations at Thar and Karachi. In addition, large hydro stations namely Bunji and Basha are planned to be commissioned during the period 2018-19 to 2021-22. The CASA transmission line in the expansion plan is projected to be

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commissioned in the year 2016. This implies a forecast of about 1000 MW of import from the CASA line from 2016 onwards.

3.2 Electricity Demand

The monthly energy generation, demand and shortfall in GWh for the years 2006-07, 2007-08 and 2008-09 are illustrated in Figure 3-1, 3-2 and 3-3 respectively. These figures indicate that the energy shortfall in the year 2006-07 was minimal, however for the following years the gap between demand and supply increased substantially resulting in high shortfall in the years 2007-08 and 2008-09. The pattern indicates that shortfall is more severe in the summer months when the demand for power increased significantly.

Figure 3-1 Energy Generation, Demand and Shortfall in 2006-07 (GWh)

Figure 3-2 Energy Generation, Demand and Shortfall in 2007-08 (GWh)

(1,000.00)

1,000.00

2,000.00

3,000.00

4,000.00

5,000.00

6,000.00

7,000.00

8,000.00

9,000.00

10,000.00

July

Aug.

Sept.

Octob

er

Novembe

r

Decembe

r

Janu

ary

February

March

April

May

June

Gen.

Demand

Shortfall

0

2000

4000

6000

8000

10000

12000

July

Aug.

Sept.

Octobe

r

Novemb

er

Decemb

er

January

February

March

April

May

June

Generation

Demand

Shortfall

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Figure 3-3 Energy Generation, Demand and Shortfall in 2008-09 (GWh)

The electricity demand in Pakistan is growing at a rapid pace due to an increase in the population and an increase in the demand for power in all sectors of the economy. The last demand forecast developed by NTDC was obtained during the recent meetings with NTDC. This demand forecast is presented in Table 3-3 below.

Table 3-3 Demand Forecast

Year Electricity Demand (MW)

2010-11 21755 2011-12 23491 2012-13 25356 2013-14 27488 2014-15 29513 2015-16 31722 2016-17 33204 2017-18 35618 2018-19 38607 2019-20 41832 2020-21 45257 2021-22 48885 2022-23 52777 2023-24 56863 2024-25 61158 2025-26 65700 2026-27 70396 2027-28 75177 2028-29 80203 2029-30 85532

2,000.00

4,000.00

6,000.00

8,000.00

10,000.00

12,000.00

14,000.00

July

Aug.

Sept.

Octob

er

Novemb…

Decembe

r

Janu

ary

February

March

April

May

June

Generation

Demand

Shortfall

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3.3 Evaluation of Supply-Demand Balance

In order to evaluate the supply-demand balance, it is necessary to determine the available capacity. Considering that some generation capacity will be on forced and planned outages in the system, and taking into account the derating of generating units, the available capacity will be less than the total installed capacity. Generally speaking, to cater for the forced and planned outages and the derating of the generating capacity, a reserve capacity margin of about 20% is normally maintained. In other words, if a capacity reserve margin of 20% is assumed, the available capacity would be less by 20% of the installed capacity. The following table (Table 3-4) presents the demand-supply assessment by taking into account the installed and available capacities and the demand forecast.

Table 3-4 Supply-Demand Assessment

Year Installed

Generation Capacity (MW)

Available Capacity (MW)

Demand Forecast (MW)

Surplus/Shortfall (MW)

2010-11 22697 18158 21755 -3597 2011-12 23788 19030 23491 -4461 2012-13 26279 21023 25356 -4333 2013-14 29405 23524 27488 -3964 2014-15 33630 26904 29513 -2609 2015-16 42350 33880 31722 2158 2016-17 45338 36270 33204 3066 2017-18 50034 40027 35618 4409 2018-19 53284 42627 38607 4020 2019-20 58867 47094 41832 5262 2020-21 63683 50946 45257 5689 2021-22 68349 54679 48885 5794 2022-23 70014 56011 52777 3234 2023-24 70614 56491 56863 -372 2024-25 76214 60971 61158 -187 2025-26 79014 63211 65700 -2489 2026-27 83014 66411 70396 -3985 2027-28 84014 67211 75177 -7966 2028-29 88334 70667 80203 -9536 2029-30 N/A N/A 85532 N/A

The above table indicates that in case all the planned capacity is realized, there would be a shortage in the generation capacity during the period 2010-11 to 2014-15 and then during the period 2023-24 to 2028-29.

Based on the peak load demand forecast, the energy requirements can be estimated by applying an appropriate load factor. If the system load factor is assumed to be 65%, the energy requirements for some of the selected years, say 2015-16, 2020-21 and 2025-26 will be 180,625 GWh, 257,693 GWh and 374,095 GWh respectively.

In view of the huge capital requirements and institutional issues, it might be difficult to build all the generation capacity as planned. In particular, for the large capacity coal-fired and hydro plants a significant investment will be required which will be difficult to obtain. For

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example, during the financial year 2015-16, the generation plan suggests the commissioning of 8,900 MW, which will entail a mammoth amount of investment. The substantial lead times for the construction of these power plants may also result in delays in acquiring additional capacity as planned. Therefore, the likelihood of delays in commissioning of these projects cannot be ignored. Therefore, in such a scenario, the construction of CASA transmission line would likely contribute in alleviating the shortage of generation capacity in Pakistan.

The recent floods in the country and its aftermath would likely have repercussions on the investment plans for the power sector, which may have an impact on the supply demand balance, particularly in the short to medium term.

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4

IMPORT AND EXPORT POTENTIAL OF AFGHANISTAN

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4 IMPORT AND EXPORT POTENTIAL OF AFGHANISTAN

4.1 Power Generation Assessment

In order to assess the power generation situation, endeavours were made to obtain information on the current power generation scenario and development plans in near future. Based on the information available, it can be inferred that significant efforts are being made to develop the generation capacity within the country and also to have imports from the neighbouring countries. The preliminary analysis of generation situation based on the current information available is provided in the following paragraphs.

The key hydro generating sources that are contributing to the supply of power to Kabul are three hydro power plants, namely Naghlu, Mahipur and Surobi. Nahglu power plant has four 25 MW units. One unit at the Naghlu power plant is under rehabilitation, while the rest are available for generation. Surobi power plant has been refurbished recently, with two 11 MW units. The Mahipur plant has three 22 MW units and was currently refurbished providing its full capacity.

In addition to the above-mentioned power plants providing power to Kabul, two new hydro plants were proposed in the vicinity of the Kabul region. One of the plants, namely Surobi II is on the Kabul River and has a proposed capacity of 180 MW. The other plant, namely Baghdara with a capacity of 280 MW is proposed to be constructed on Pansjir River. Surobi II is a run-of-river plant, while Baghdara is a seasonal reservoir storage power plant. These two plants according to previous studies by the Consultants appear to be technically feasible. The current status with regard the implementation of these power plants is not known. Some of the information available also suggests that two other Hydro plants, namely Kajakai of 52 MW and Salma of 44 MW are also planned to be commissioned soon. However, the status regarding the implementation of these plants is not clear.

As regards the thermal power plants, one notable thermal power plant namely Kabul North West Thermal Power Plant contributes to the supply of power to the Kabul region. Its installed capacity is about 58 MW. However, according to the current available information only units 3 and 4 are available thus significantly curtailing its generation capability. In addition, a 104 MW diesel power plant has been commissioned in Kabul recently.

As regards the development of new generation capacity, one of the key projects under consideration is the 400 MW Aynak thermal coal-fired power plant. Out of 400 MW, it is envisaged that 200 MW would be supplied to the power grid, while rest of the power would be utilized for the copper mine, starting in 2014-15.

Small quantities of gas reserves have been reported in the Sheberghan area sufficient for a 100 MW power plant. Therefore, a thermal plant of 100 MW is planned to be built near Sheberghan to cater for the power demand in the northern areas. Depending on the availability of gas and size of the plant, this power plant can also be considered to supplement the power plants meeting the load of the Kabul region.

In addition to the above power plants, substantial quantum of power import has been planned from the neighbouring countries. This includes up to 300 MW power from Tajikistan to be imported from the ADB financed interconnection from Sangtuda to Kunduz, Pol-e-Khumri and on to Kabul, which is currently under construction. It is envisaged that this interconnection will be commissioned by 2013 thus allowing the import from Tajikistan. In addition, 300 MW of power is planned to be imported from Turkmenistan. Currently,

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Afghanistan is importing about 150MW of power from Uzbekistan and it is envisaged that this level will be increased to 300 MW by 2012.

4.2 Power Demand Situation in Kabul Region and Country

Kabul with a fast growing population of 4 to 5 million is facing erratic power supply due to years of war and chaos in the country. The lack of development of power supply infrastructure over the previous years has also compounded the problem of electricity supply to the region.

It appears that the power distribution system in the Kabul region and other towns is in a very dilapidated condition and in order to absorb the available power in the future years it is imperative to rehabilitate and upgrade the distribution system within the Kabul and other regions. Its existing condition significantly limits the availability of power supply and is a serious constraint in delivering power to consumers. In this context, it may be added that a number of initiatives are being implemented to improve the distribution network in Kabul. The projects concerning the Kabul city MV system rehabilitation, LV system rehabilitation and installation of new sub-stations are in progress. Efforts are being made to expedite the implementation of the distribution projects so that the load shedding in the city can be minimized. Similar efforts will be required to rehabilitate and improve the distribution system in other parts of the country.

From the data available on the loading of substations, the maximum total load so far on the substations in the Kabul region for the year 2010 has been 197 MW. However, this figure does not represent the full power demand of Kabul as the substantial demand in the Kabul region may be suppressed.

As regards the electricity demand in the future years, a number of forecasts, which were available, were reviewed. The Ministry of Energy and Water had projected that the demand of electricity in the Kabul region will be about 500 MW by the year 20131. The demand forecast provided in the Power Sector Master Plan developed by Norconsult gives the Kabul forecast as 260 MW and 347 MW in the years 2015 and 2020 respectively2. The forecast of the whole country is 905 MW for the year 2020. In addition to these demand projections, the demand forecast is also available from Global Edison. This demand forecast was undertaken in 2007. It provides the demand forecast for the Kabul region as 384 MW and 591 MW for the years 2015 and 2020 respectively. For the whole country the demand projections are 761 MW and 1099 MW for the years 2015 and 2020 respectively.

Considering that the most recent forecast available is from Global Edison3, it should have used the most up-to-date information available and therefore can be considered as relatively credible as compared to other forecasts.

4.3 Supply-Demand Balance

In case all the existing power plants mentioned in the Section 4.1 are rehabilitated and the planned power plants are commissioned timely, the domestic installed power capacity in

1 Report on Power Sector Strategy for the Afghan Development Strategy, Ministry of Energy and Water, April 2007 2 Power Sector Master Plan, Demand Forecast, Norconsult, October 2004. 3 Power Demand in Afghanistan (2005 – 2025), Global Edison Corporation, Texas, USA,

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Afghanistan will increase to over 1400 MW by 2015. However, considering that 200 MW will be consumed by the Aynak copper mine, the power available for the grid will be about 1200 MW. Moreover, considering that lead time of hydro plants are long, the likelihood of the completion of Surobi II, Baghdara, Kajakai and Salma hydro plants appears to be difficult before 2015. Therefore, in case the generation capacity of these plants is excluded, the generation supply from domestic plants will be about 644 MW in 2015.

As regards the import of power from the neighbouring countries, if the planned transmission lines are commissioned, the import capacity would increase to about 900 MW by 2015. Combining the total planned capacity available to the grid including the planned hydro capacity and the planned import capacity, the total supply capacity in the country would be approximately 2100 MW by 2015. However, in case the hydro plants are excluded in view of lack of certainty about their commissioning dates, the available capacity reduces to 1544 MW in 2015.

Considering the power demand forecast of the country to be 761 MW in the year 2015 and taking into account the generation supply available in year 2015 of 1544 MW, it becomes obvious that if all the planned projects excluding the hydro projects mentioned above, and all the import plans are implemented on time, the Afghanistan will have a surplus of capacity to the tune of 783 MW. If required, this surplus energy can be exported to Pakistan as it is envisaged that it will continue to have power shortages in the foreseeable future.

It is important to note that the above analysis was carried out on the basis of installed capacities of the power plants. The available capacity of the hydro plants depends largely on the water flows and due to uncertainty in this regard will vary from the installed capacity of these plants. Broadly speaking, the water flows are relatively high in summer thus leading to higher generation capacity available during the summer period from these plants. Similarly, due to forced outages and inefficiencies associated with the thermal plants, the available capacity of thermal plants will also vary. Generally speaking, the available capacity will be somewhat less than the installed capacity and will vary periodically due to a variety of factors.

It is worthwhile to point out that in view of the current situation in Afghanistan and the constraints associated with the financing and implementation of the projects, the element of uncertainty associated with the load forecast and capacity development should not be ignored. However, even taking into consideration the uncertainties associated with the demand forecast and projected capacity development, Afghanistan will likely have surplus capacity in 2015 and beyond, at least for a few years, particularly during the summer months.

4.4 Review of Power Purchase Agreements (PPAs)

Afghanistan currently has Power Purchase Agreements (PPAs) with the following countries:

• Tajikistan;

• Iran; and

• Turkmenistan.

The following paragraphs present a brief review of these PPAs.

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Power Purchase Agreement with Tajikistan

The PPA with Tajikistan was signed in June 2008. This agreement was made between Da Afghanistan Breshna Moassasa (DABM) and Barki Tojik Open Joint Stock Holding Company controlled by the Government of Tajikistan.

The Agreement provides the annual minimum energy delivery schedule and specifies the minimum obligations for the sale and purchase of firm energy on a monthly basis for the period 2010-2014. The firm supply delivery schedule is for the months April to October. For the remaining months Tajikistan is required to supply energy if it is available as there is no obligation on their part to supply energy during these months. For the period 2010 to 2014, the minimum and maximum firm energy commitments according to PPA are 500.2 GWh and 650.8 GWh respectively. The PPA also provides the daily firm energy delivery schedule. For the years beyond 2014, the parties shall agree on the quantum of firm and non-firm energy to be delivered.

The PPA also provides a constant price of US Cents 3.5 per kWh for firm, non-firm, and unscheduled energy, and also for the energy needed for testing prior to commercial operation.

The nominal voltage for the supply of energy is 220 kV. The transmission line is a double circuit line and its terminal points are Sangtuda in Tajikistan and Kunduz and Pul-i-Khumri substations in Afghanistan.

Power Purchase Agreement with Iran

The PPA was signed in January 2003 between the Ministry of Energy of Iran and the Ministry of Energy and Water of Afghanistan. There was a prior PPA which ended in March 2007, however a clause in the current Agreement extends it to March 2016.

According to the PPA, Iran will deliver 200 GWh (+5 GWh) per year to Afghanistan with a maximum of 90 MW capacity on the transmission lines. The transmission lines include the following:

• 132 kV Torbat Jam (Iran) – Harat (Afghanistan)

• 20 kV Taybad (Iran) – Harat (Afghanistan).

In addition to the above transmission lines, a transmission line linking Zabel (Iran) to Zarnej (Afghanistan) can also deliver maximum of 10 MW of power.

As regards the price of electricity, for the period March 2007 to March 2010 the same price as agreed in the previous PPA was maintained. However, from March 2010 to end of contract (March 2016) the price of delivery is US Cents 4 per kWh. Afghanistan is required to pay US Cents 3 per kWh as Iran will charge US Cents 1 per kWh from the Iran Aid to Afghanistan.

Power Purchase Agreement with Turkmenistan

The PPA between Turkmenistan and Afghanistan was not made available to SNC-Lavalin. However, we had access to one of the Amendments to the PPA. The information provided below is based on that Amendment.

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The PPA was signed by the Ministry of Power Engineering and Industry of Turkmenistan and the Ministry of Water and Power of Afghanistan. According to the Amendment, the Seller (Turkmenistan) has to provide 759,738,176 kWh of energy during the period October 2003 to December 2010 at the price of US Cents 2 per kWh. The validity of the Agreement is January 2011.

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5 COST OF SUPPLY

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5 COST OF SUPPLY

Assessment of Cost of Supply Assumptions

Costs of supply for economic analysis are normally derived from the specific project costs or from a long-range country-wide or region-wide master plan analysis. The Long-Run Marginal Cost (LRMC) is approximated by the levelized cost of supply.

For both Tajikistan and the Kyrgyz Republic, there has not been any recent update of a master plan for the electricity sector.

However, several projects have been identified and are at different stages of implementation (e.g. Rogun HPP, Fon Yagnob coal TPP in Tajikistan and Kambarata 1 HPP and Kara Keche coal TPP in Kyrgyz Republic). Neither the cost of development of these projects nor the definition of their technical characteristics is available from recent or updated studies.

Given the scarcity of reliable information needed to compute the LRMC, the price of exports was used as an approximation for the cost of supply in Tajikistan and the Kyrgyz Republic.

Tajikistan - Cost of Supply

Information on exports of electricity has been taken from the Statistical Agency under the president of the Republic of Tajikistan (http://www.stat.tj/english/home.htm). In addition, the cost of purchasing power from the Sangtuda I & II projects as well as for the O&M fixed costs of Nurek and other existing hydro power plants have been considered. The cost of supply for Tajikistan is estimated at 1.5 cents/kWh.

The Kyrgyz Republic - Cost of Supply

Information on exports of electricity has been taken from data provided by the NEGK and JSC Power Plants, which was provided on a confidential basis.

Assessment of the Generation Costs in Pakistan

The price that the state-owned utility (NTDC) is paying for the recent long-term PPAs with the IPPs was used as a proxy of LRMC to estimate the generation cost in Pakistan over the life time of the interconnection project. The PPA’s cost includes the cost of capacity and this reflects the cost of building new generation projects. As the Power System Master Plan is currently under preparation, the average of PPA costs is a good approximation to the LRMC.

Only PPAs using residual fuel oil (RFO) and diesel have been considered. For the economic analysis, the economic viability of the project was examined by using firm energy valued at the levelized price of energy and capacity and non firm energy valued at the price of energy only. The rate for firm energy is 13.2 US cents/kWh and the rate for non-firm is 9.2 US cents/kWh. The prices are estimated based on the total levelized variable charges and the total levelized tariff of IPPS determined by NEPRA as on June 30th 2009. Sensitivities that use higher and lower opportunity costs for Pakistan are analysed in Section 10.

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Assessment of the Generation Costs in Afghanistan

The generation cost in Afghanistan is estimated to be, at least, US$ 0.06/kWh for the study based on the information provided by DABS. The information provided by DABS indicates that the cost of generation from Aynak power plant is expected to be US$0.06/kWh. In the absence of any other credible data, this information is used for the generation cost in Afghanistan.

In the Consultant’s view, it is plausible that generation costs in Afghanistan would be higher than the above mentioned figure. A sensitivity analysis, presented in Section 10, has been carried out to reflect this scenario (sensitivity #6 in Table 10-4).

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6 PROJECT SELECTION AND EXPORTABLE SURPLUS

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6 PROJECT SELECTION AND EXPORTABLE SURPLUS

Various project sizes and configurations were studied in the context of this feasibility update. This section discusses the size optimization analysis that was carried out as well as the configurations that were analysed. In addition, the exportable surplus for the recommended project size and configuration is showcased.

6.1 Assessment of Optimum Size of the Project

6.1.1 Methodology

To establish the optimal size of the interconnection from Tajikistan to Pakistan, with an intermediate connection in Afghanistan, the methodology used was the ratio of Benefit / Cost (B/C) for different transfer capabilities (1300 MW, 1800 MW, 2300 MW, 2800 MW and 3300 MW), considering the contribution of Tajikistan and the Kyrgyz Republic. The benefits and costs were brought to present value at the beginning of the year of commissioning of the project estimated for early 2016 using a discount rate of 10%.

6.1.2 Export Potential to Afghanistan and Pakistan

The potential export surplus for each case was obtained from the SDDP model by running the simulation over 20 years (2016-2035). Figure 6-1 shows the average energy results of the export potential for different capacities of the CASA HVDC line.

Figure 6-1 Average Energy Export Potential to AFG & PAK1

1 It can be noted that for a few years, for example for 2021, the average potential in 2300 MW appears to be greater than that of larger line capacities (though by a small margin, 0.5% in this case). This is related to the fact that the optimization of export potential is done for the entire study period (20 years). As the model is concerned about optimizing the simulation over the entire period, it is possible to see a marginally smaller export potential for a larger capacity if the results are analysed on a year by year basis. However the benefit optimization over the entire period shows an increase in export potential over the different capacities.

05001,0001,5002,0002,5003,0003,5004,0004,5005,0005,5006,000

2016

2018

2020

2022

2024

2026

2028

2030

2032

2034

GWh

Average Export to PAK/AFG Through CASA Line Different Options

1300 MW 1800 MW

2300 MW 2800 MW

3300 MW

1300 MW 1800 MW 2300 MW 2800 MW 3300 MW

2016 4,009 4,796 5,206 5,637 5,7792017 3,541 4,237 4,854 5,022 5,0602018 3,738 4,301 4,718 4,868 4,8872019 3,457 3,995 4,397 4,453 4,4332020 3,283 3,885 4,228 4,216 4,2142021 3,169 3,603 3,747 3,730 3,7202022 3,063 3,590 3,901 3,930 3,9342023 3,020 3,431 3,578 3,580 3,5732024 2,890 3,297 3,480 3,502 3,5212025 2,499 2,714 2,823 2,843 2,8432026 2,581 2,902 2,988 2,997 2,9972027 2,471 2,833 3,081 3,115 3,1132028 2,097 2,438 2,549 2,562 2,5632029 1,953 2,247 2,410 2,449 2,4492030 1,857 2,134 2,177 2,187 2,1872031 1,653 1,780 1,803 1,802 1,8022032 1,444 1,599 1,596 1,596 1,5962033 1,228 1,341 1,320 1,320 1,3202034 1,052 1,112 1,114 1,114 1,1142035 813 841 841 841 841

Average Export to PAK/AFG (GWh)Year

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6.1.3 Benefits

For the benefits, the potential energy surplus was valued as described in section 5. Considering that the peak load in Pakistan is coincident with the time of export potential from the Kyrgyz Republic and Tajikistan and as described in Section 5, the firm energy was valued at the levelized price of energy and capacity contracts and the non-firm energy was valued at the price of energy only.

6.1.4 Costs

The costs of supply considered in this analysis correspond to the exports in Tajikistan and the Kyrgyz Republic as developed in Section 5.

The summary of transmission investments for the HVDC interconnection between Sangtuda, Kabul and Peshawar, the HVAC interconnection between Datka and Khoudjand, the internal reinforcements in the countries and environmental and social costs are shown in Table 6-1. Details of these costs are provided in appendix I, note I.4. Note that based on the analysis presented in section 8.6, the Datka-Khoudjand line is taken as the most viable alternative for interconnection of the Kyrgyz Republic and Tajikistan. The environmental and social costs vary minimally as a function of the line capacity, hence the same environmental and social costs have been assumed for all options.

Estimates provided are inclusive of EPC costs, owner’s engineer fees and contingencies. The O&M cost was estimated as 3% of the investment cost following the experience of the consultant for this type of project. This takes into account additional cost due to rugged terrain and other local conditions.

Table 6-1 Total Project Costs for the Different Size Options (in million US$)

HVDC Size Option (MW)

HVDC Component

including electrodes

HVAC Component

Reinforcements in TAJ, PAK and

AFG

Environmental and Social

Costs Total

Project

1,300 626 197 34 16 873 1,800 716 197 60 16 989 2,300 758 197 98 16 1069 2,800 881 197 98 16 1192 3,300 909 197 98 16 1220

*: Total investment includes the EPC costs, owner’s engineering fees and contingencies

6.1.5 Results

The analysis shows that there is very little difference between the B/C ratios of the 1300 MW, 1800 MW and 2300 MW options as shown in Table 6-2.

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Table 6-2 Economic Evaluation for Size Optimization

HVDC Size Option (MW) B/C Ratio EIRR (%) NPV (MUSD)

1300 MW 1.34 16.2% 539

1800 MW 1.38 17.1% 701

2300 MW 1.40 17.5% 786

2800 MW 1.32 16.1% 689

3300 MW 1.31 16.0% 677

If there are financial constraints, the best configuration is a 1300 MW interconnection. Transmission lines are manufactured in discrete step sizes and sizing the transmission lines for 1300 MW effectively restricts the capacity to about 1300 MW. It is possible to build the line with a conductor size that is capable of carrying the optimum power level (2300 MW) but limit the HVDC converter capacity initially to 1300 MW. This option adds roughly 7% (41 million USD) to the minimum cost 1300 MW option (1300 MW converter capacity with 1300 MW line capacity). However, as the conceptual framework for the project is based on using existing low cost energy in the exporting countries to supply the importing countries, and that this energy decreased over the study period, it is preferable to build a line with a 1300 MW conductor. Should the existence of this line attract investors in the future and more energy become available than the CASA project can transmit, another line can be built to transport this energy.

6.2 Project Configurations

The main project configurations that were considered are presented in this subsection.

6.2.1 Converter Capacity at Peshawar

The assessment of the import and export potential for Afghanistan in section 4 shows that there is a possibility that Afghanistan will have sufficient power to meet its internal load, with potential surplus, especially during the initial years of the study period. In light of this conclusion, a converter capacity of 1,300 MW at Peshawar, equal to that at Sangtuda, would provide flexibility for Pakistan to absorb up to 1300 MW, should Afghanistan not need to import its entire share. Whenever Kabul is unable to take its allocation of 300 MW, this power can be transferred to Peshawar over the HVDC line and absorbed into the Pakistan system. If the Kabul system has a surplus of power and the Tajikistan/Kyrgyz system is unable to provide the full 1,300 MW of export power, then Kabul could export to Pakistan via its converter station. Therefore the base case configuration is taken as having 1,300 MW converters at Sangtuda and Peshawar and 300 MW at Kabul, and a 1,300 MW transmission line.

It is important to note that all converters will be able to both import and export power. Hence Afghanistan will also be able to export any surplus energy to Pakistan, provided the combined imports to Pakistan do not exceed 1,300 MW.

6.2.2 Back-feed Option between Peshawar and Kabul

As an alternative to a converter station in Kabul supplying power from the HVDC line, the multi-terminal arrangement could be replaced by a 2-terminal HVDC interconnection between Sangtuda and Peshawar. The power dedicated to Kabul could then be supplied

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via a 220 kV double circuit line from Peshawar back to Kabul. The following advantages and disadvantages can be enumerated at this time. The advantages are as follows:

• The back-feed option would allow electricity to be provided to communities along the Peshawar-Kabul route.

• The back-feed option would provide some flexibility for Afghanistan to export surplus energy to Pakistan irrespective of whether Pakistan is importing 1,300 MW from Tajikistan and the Kyrgyz Republic.

• Removing the converter station in Kabul would realize a cost reduction (including EPC costs and estimated owner’s engineer fees and contingencies) in converter costs and HVDC line costs of approximately MUS$ 75. It also entails a reduction of MUS$ 6 related to the electrode in Kabul. The cost of a 260 km, 220 kV double circuit line from Peshawar to Kabul, via Jalalabad would also be approximately MUS$ 73 plus the cost of extending the 220 kV switchyard in Peshawar (approximately MUS$ 5). The net cost reduction would therefore be MUS$3. This is summarized in Table 6-4 and additional cost details are provided in Appendix I, note I.4.

On the other hand, several disadvantages to this configuration have been identified. These are:

• The presence of an AC tie between Peshawar and Kabul would mean that; either the Pakistan/Afghanistan/Tajikistan/Kyrgyz Republic systems would be operated as a synchronously connected system; or, the supply to Kabul must be switched between the supply from Peshawar and the supply from Tajikistan on an either/or basis.

• Operating a low-capacity 220 kV AC link in parallel with a high-capacity DC link will give rise to operational problems. In the event of a fault on the HVDC line, the power transfer between Tajikistan and Pakistan will automatically transfer to the 220 kV parallel path until such time as the HVDC can be re-scheduled. Although this time may only be for a few tens of cycles, it would almost certainly result in the electrical collapse of the 220 kV link, which would then be tripped on overload. Also, because the AC link is of relatively low capacity, any generation outages in either the Pakistan system or the Tajikistan/Kyrgyz Republic system will result in significant power oscillations on the 220 kV link that could result in tripping of the 220 kV lines.

• Operating the 220 kV links to Kabul on a segregated basis will also result in operational difficulties. The northern 220 kV link to Tajikistan is rated at 300 MW, but could only deliver 200 MW to Kabul, the remainder being taken at Kunduz and Pol-e-Khumri. Supplying a total of 300 MW to Kabul would require 100 MW to be supplied from Peshawar. To achieve this without synchronously connecting all the systems together would require some splitting of the system in Kabul. This will involve complex switching arrangements to cater for all system configurations and will inevitably lead to a degradation in the reliability of supply to the Kabul area. It is understood that, at present, the Kabul system is operated in a split arrangement to allow other imports from Central Asia to be utilized there. While this may be acceptable at the present load levels in Kabul, it will inevitably lead to problems in the future as the load increases and will result in a degradation of the supply reliability and additional cost in the sub-transmission system.

• Supplying power that is essentially being carried on the HVDC interconnection back to Kabul on an AC link will result in higher system losses.

• To remove the operational difficulties that would arise from operating the Pakistan, Afghanistan, Tajikistan and Kyrgyz Republic systems as synchronously connected

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systems would require that the back-feed from Peshawar be taken into Kabul through a back-to-back HVDC converter. This would remove the synchronous connection between the Pakistan and Tajikistan/Kyrgyz systems and prevent the transfer of power from the HVDC interconnection to the AC interconnection. The cost of a 200 MW back-to-back converter would be in the range of MUS$ 25-30. Thus, the provision of a back-to-back converter would make the back-feed option more costly than the 3-terminal HVDC option. The location of the back-to-back converter station is immaterial from an electrical or contractual standpoint, but would most easily be accommodated in an existing substation.

In terms of providing electricity to communities along the Peshawar-Kabul route, it might be more economical to provide such a supply independently of the interconnection. If the total load requirement is not large enough to warrant a 220 kV supply, then cost savings can be achieved by using a lower voltage supply, such as 110 kV. This could be provided directly from Kabul to Jalalabad or onto the border with Pakistan, picking up loads at the smaller communities on the way, with low-cost tap-offs or even at lower voltages via distribution networks from Kabul and Jalalabad. This type of supply arrangement also internalizes the supply to these communities and does not result in the supply being provided by the Pakistan system. This may be an important consideration given that the Pakistan system is itself short of power and may not be in a position to maintain the supply into Afghanistan at the same time as it needs to shed load due to capacity shortages.

The backfeed option with a simple double circuit 220 kV line to Kabul could resolve a number of problems in the short term. However it brings about operational difficulties related to the synchronous operation of the Pakistan, Afghanistan, Tajikistan and Kyrgyz Republic systems. For the long term goal of having a unified and synchronized system in Afghanistan, the backfeed would only work effectively if there is an additional back-to-back HVDC converter in Kabul or Peshawar.

There are also commercial issues that need to be considered since power for Afghanistan will have to transit Pakistan territory to get back to Kabul. However, these issues can be resolved through appropriate contractual arrangements.

6.2.3 Potential Addition of a Fourth Terminal to the CASA Interconnection

The implications of eventually adding a fourth terminal to the overall scheme were also examined. This may be related to exporting any surplus power from other countries, such as Uzbekistan, down to Pakistan or Afghanistan. A technical note, included in Appendix I (note I.5), summarizes the impacts of a fourth terminal on the project. A summary of the conclusions is presented in this section.

The main two impacts of the addition of a fourth terminal are the following:

• Limitations on operations and power transfers: operational limitations will apply unless certain provisions are taken in the initial design stage:

• the DC line needs to be rated accordingly;

• the location of the fourth terminal relative to the other three needs to be known, and

• the “role” of each terminal needs to be fixed (importer vs. exporter).

• Cost: if the future implementation of a 4th terminal is confirmed then all provisions should be taken at the initial design stage. The most significant impact on cost consists in over-rating the DC line to accommodate the extra power to flow to/from the fourth terminal.

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The only planned multi-terminal system in operation (Quebec-New England) was finally restricted to three terminals because of performance concerns (and is being operated most of the time as a two terminal), and there has been no experience world-wide in planning and executing multi-terminal HVDC schemes since. The implementation of a four-terminal scheme for the CASA project would then constitute a milestone in the application of HVDC transmission.

For the purpose of the CASA project, it is the Consultant’s technical recommendation that the number of terminals be limited to either two or three.

6.3 Summary of Project Options

A diagram of the recommended option is provided in Figure 6-2.

Figure 6-2 Diagram of Recommended CASA Project

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Table 6.3 summarizes the different project sizes analysed for the Tajikistan-Afghanistan-Pakistan interconnection as part of the feasibility study update. The detailed costs are provided in Appendix I, note I.4.

Table 6-3 Options Analysed for Optimization of Project Size

# Option Total Cost (MUSD)

1 3 terminal 1,300-300-1,300 873 2 3 terminal 1,800-300-1,800 989 3 3 terminal 2,300-300-2,300 1069 4 3 terminal 2,800-300-2,800 1192 5 3 terminal 3,300-300-3,300 1220

In addition to the project sizes, different project configurations were investigated. These are highlighted in Table 6-4.

Table 6-4 Project Configurations Analysed for 1,300 MW Taj-Afg-Pak HVDC Interconnection

# Option Total Cost (MUSD) Analysis Summary

A

Recommended option:

3 terminal 1,300-300-1,300

873

Offers flexibility for Pakistan to absorb any of Afghanistan’s share that the latter does not need, up to 1,300 MW, which is desirable given the import potential assessments presented in sections 3 and 4.

B 3 terminal

1,300-300-1,000 858 Most cost effective option, though does not offer flexibility of option A.

C 3 terminal

1,300-300-1,300 with 2,300 MW line

913

Offers the flexibility to accommodate additional generation capacity though not recommended as the project is based on using existing low cost energy in the exporting countries to supply the importing countries, and that this energy decreased over the study period.

D 2 terminal

with back-feed 870

Offers the benefit of providing electrification to towns between Kabul and Jalalabad. However it would render permanent the segregation of Kabul North and South power systems, which is not recommended, or would require a back to back HVDC converter which would increase the costs.

E 4 terminal interconnection n/a

Implies limitations on operations and power transfers and significant costs as a 4 terminal HVDC scheme has never been implemented.

F Alternate routing in Salang Pass (see

section 7)

923 to 938

Bypasses congestion at Salang Pass but increases the HVDC route by 150 to 200 km.

Note: Project Costs include EPC, Owner’s Engineer and Contingency estimates, country reinforcements and environmental and social costs

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Table 6-5 summarizes the project scenarios that were investigated for the Kyrgyz-Tajik interconnection.

Table 6-5 Project Scenarios Analysed for Kyr-Taj HVAC Interconnection

# Option Total Cost Reference Section

i Datka-Khoudjand 197 8.6 ii Datka-Sangtuda 288 8.6

Project Costs include EPC, Owner’s Engineer and Contingency estimates.

6.4 Exportable Surplus

Figure 6-3 shows the monthly distribution of the exportable surplus through the CASA line with 1300 MW converters in Tajikistan, 300 MW in Afghanistan and 1300 MW in Pakistan, for the first 4 years (2016-2019).

The exportable surplus was obtained using relaxed reservoir coordination constraints during the summer months, which increase flexibility in taking advantage of Toktogul’s larger size without significantly changing Nurek’s operation. These constraints are introduced without violating riparian issues. This firms up the power available particularly during shoulder months, and increases the benefits overall. Additional details on the summer reservoir coordination are provided in Appendix I, Note I.3.

Figure 6-3 Monthly Distribution of Exportable Surplus (1300 MW)

0

100

200

300

400

500

600

700

800

900

1,000

1,100

Jan‐16

Mar‐16

May‐16

Jul‐1

6

Sep‐16

Nov‐16

Jan‐17

Mar‐17

May‐17

Jul‐1

7

Sep‐17

Nov‐17

Jan‐18

Mar‐18

May‐18

Jul‐1

8

Sep‐18

Nov‐18

Jan‐19

Mar‐19

May‐19

Jul‐1

9

Sep‐19

Nov‐19

GWh

Month

Tajikistan Kyrgyz Republic

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The export is concentrated in the 5 months of the summer, from May to September. (April’s contribution is minimal). The peak is in July, when Nurek has the highest inflows on average. The Kyrgyz Republic’s contribution is mostly in the months of May and September. With the collaboration of the systems and the coordinated optimization of Nurek and Toktogul, the available surplus can be distributed over 5 months instead of three. Toktogul shifts production to the beginning and end of summer and Nurek handles the production in July and August. Spilling in July and August is thus avoided by not having Toktogul also optimize its production for these months, where it historically also has its highest inflows.

Analysis of Availability of Firm Energy during Peak Summer Hours

A study was conducted to evaluate the amount of firm energy available for export during the peak summer hours through the 1,300 MW CASA Line. Two alternatives were considered for the duration of the peak hours: 4 hours and 2.4 hours.

It was observed that the firm export to Pakistan through the CASA Line is above the 80% rating (1,040 MW) of the line for 4 months of the summer during the first 3 years for the 4 peak hours case, and during the first 5 years for the 2.4 peak hours case. During subsequent years, with the load increasing and without any generation expansion plan, the duration for which this level of firm export is available reduces progressively.

It can be then guaranteed to a 95% probability that there will be available export of at least 1,000 MW for the peak hours during the summer for the initial years of the project. With the likely generation expansion, this period of guaranteed peak summer export will extend further.

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7 TRANSMISSION LINE ROUTES

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7 TRANSMISSION LINE ROUTE

In light of recent developments in the region, the route recommended in the original study was reviewed. The findings are summarized in this section, with an emphasis on the space constraints around the Salang pass and the availability of space for the proposed converter stations at Sangtuda-II and Peshawar. Figure 7-1 is a high level map of the line route for the HVDC and HVAC components of the project.

Figure 7-1 Proposed Transmission Line Route for CASA Project

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7.1 HVDC Transmission Line Route

A desk top review of the route and terminal stations was carried out, with particular attention to the Kabul-Peshawar portion of the DC transmission line. Given security considerations such as demining, and operation and maintenance requirements around access to the line for repair and maintenance, the line routing recommended in the original study is deemed most suitable. The HVDC line route details are presented in Appendix C.

7.1.1 Salang Pass Space Constraints

The options of routing the HVDC line in the vicinity of Salang Pass are limited. Much of the existing Right of Way has been utilized for the existing 220 kV Line. The more precise planning of the existing space will only be possible after the detailed survey of the area. This detailed survey is usually specified as part of the turn key line construction contract and is performed by a qualified overhead line surveying company.

However, at this stage according to the information available from site investigations performed at the time of phase 2 works of the original study, about 7 km of 220 kV double circuit existing line constrains the routing of the proposed HVDC line in Salang Pass area.

A few options to locate the proposed HVDC line are envisaged as mentioned below:

• Relocate the existing 220 kV line closer to the mountain on steel tubular poles with insulated arms and shorter spans to limit the conductor swing; and route the proposed HVDC line on steel tubular poles as well but closer to the tunnel.

The estimated cost for converting 7 km of 220 kV double circuit line as tubular pole line having reduced average span of 275 m can be assessed as US$ 600,000 per km. A total estimated investment of US$ 4.2 million is envisaged. It is to be noted that a major outage of both the 220 kV circuits will be required during pole erection and re-stringing. The existing conductors and some other material can be re-used and the salvaged lattice steel towers can be bundled and transported to a store yard for future use as spare towers.

• If relocating the 220 kV line does not provide adequate corridor to place towers for the HVDC line, the spans can be shortened to limit the conductor swing and hence narrow the required minimum Right of Way for the proposed line. In this option, lattice steel towers with narrow foot print can also be utilized for the HVDC line.

• In case the existing corridor is too narrow at some places and the above two options cannot be employed, then converting a portion of the existing 220 kV line to underground cables can be considered .This will allow the existing 220 kV ROW to be used for the proposed HVDC line. In this case surge arresters and terminal structures will be required on both ends of the underground cable section. The required length of the existing OHL which would be needed to be converted to underground cable can only be determined after a detailed survey by a qualified overhead line surveying company.

Approximately 7 km of the existing 220 kV double circuit line is envisaged to be undergrounded in order to use the existing 220 kV line ROW for the proposed HVDC line. The budget estimate for the required cable 220 kV XLPE cable is US$ 2 million per kilometre including the terminal equipment. An estimated total additional investment of US$ 28 million is envisaged for the option mentioned above.

The implementation of this option will also require an outage on the 220 kV circuits.

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All existing line materials and latticed steel towers can be salvaged, suitably packed and can be used as spare material/towers.

7.1.2 Alternate Route to Bypass Salang Pass

Figure 7-2 highlights in red a possible alternate route that bypasses the congestion at the Salang Pass. The alternate route is a western detour via Shibar Pass. However, this increases the transmission line by 150 to 200 km and adds significant cost, around 50 to 65 US$ million, to the overall project.

Figure 7-2 Alternate Route to Bypass Salang Pass Source: Transoxiana

7.1.3 Space Availability for the Proposed Converter Stations at Sangtuda-II and Peshawar

As indicated by NTDC, the existing 500 kV substation at Sheikh Muhammadi has constraints on further extension related to right of way for additional lines. This is shown in Figure 7-3. NTDC has proposed a new substation (Peshawar New), at a suitable nearby location, near the 500 kV and 220 kV network feeding PESCO. The cost estimates have been revised to include a 500 kV, 10 km in and out connection to the location of Peshawar New from the existing 500 kV line.

The Sangtuda II proposed converter location is shown in Figure 7-4. In view of encroaching private lands, it is recommended to reserve the area for the future construction of the converter station.

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7.2 HVAC Transmission Line (Kyr-Taj) Route

The transmission line route details for the HVAC 500 kV line between Datka and Khoudjand were developed as part of the original CASA-1000 feasibility study and are shown in Appendix D.

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Figure 7-3 Right of Way Constrained Existing Peshawar Substation

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Figure 7-4 Proposed Converter Location for Sangtuda-II Substation

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8 TRANSMISSION NEEDS OF EXISTING NETWORKS

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8 TRANSMISSION NEEDS OF EXISTING NETWORKS

Data was collected on the transmission needs of each of the Tajikistan, Afghanistan and Pakistan networks. The results of the assessment include (i) a review of the existing load flow studies, where applicable, (ii) an assessment of the transmission reinforcements in each network, and (iii) a specific load swapping study in the case of Tajikistan importing power from the Kyrgyz Republic for further export through the HVDC line.

8.1 Transmission Needs of the Existing Network in Tajikistan

Methodology

Based on the data provided in the Jacobs report and the internal Tajikistan network report by the Asian Development Bank (ADB report), a high level analysis of the capacity of the Tajikistan 500/220 kV power network to deliver the CASA project at Sangtuda is carried out in the following steps:

• Determination of the location and levels of the main load centers;

• Identification of the main generators and their typical power outputs;

• A high level schematic of the Tajikistan network is developed by identifying the main 500/220 kV transmission corridors;

• Identification of the predominant direction of the power flows;

• Analysis of the approximate magnitudes of the flow of power within the Tajikistan network for the different CASA options; and,

• Recommendation of the corresponding conservative upgrades for the Tajikistan 220/500 kV power grid for each CASA option.

Based on the review of the data, the following main assumptions were used for the assessment of the transmission needs of the existing network:

• The Uzbekistan and Tajikistan networks are not connected and do not exchange power at the time.

Results

The general assessment after a review of the input data follows:

• The predominant flows in Tajikistan prior to the commissioning of the CASA project are south to north;

• The bulk of the generation is located at Nurek (3000MW) and Sangtuda I and II (890 MW) power plants;

• The demand for Tajikistan is concentrated in the capital Dushanbe;

• The power generated at Sangtuda I and II power plants is evacuated via the 220 kV corridor to the load center at Dushanbe;

• The power generated at Nurek power plant is evacuated through the 500 kV corridor to Regar substation and finally to Dushanbe;

• By the time that the HVDC interconnection will be in place, there will also be a power export from Tajikistan to Afghanistan through the Sangtuda – Kunduz and Pol-e-

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Khumi 220 kV, double circuit interconnection which will also be extended from Pol-e-Khumri to Kabul. This interconnection is rated at 300 MW, however this applies to the capability of the line at the Sangtuda end. The section of the line from Pol-e Khumri to Kabul is 200 km in length. For such a length, the maximum safe loading would be 2 x the surge impedance loading of 125 MW or 250 MW. Taking into account the section from Sangtuda to Pol-e-Khumri (265 km route length), the maximum delivery capability at Kabul would be closer to 200 MW; and,

• Figure 8-1 depicts a high-level flow diagram for the power transfer between Sangtuda, Nurek and Dushanbe if the CASA project is not in service. Note that most of the power supplying the load center at Dushanbe needs to flow from Nurek and Sangtuda.

Figure 8-1 Diagram of the power flow between Nurek and Sangtuda power stations and the load center at Dushanbe without the CASA project

• Once the CASA project is operational, the net power injection at the Sangtuda substation will be equal to the generated power at the Sangtuda I and II power plants minus the 220 kV/200MW export to Afghanistan and the power drawn by the CASA DC interconnection.

• Figure 8-2 depicts a high-level flow diagram for the power transfer between Sangtuda, Nurek and Dushanbe with the CASA project in service. This “power swapping” option feeds a fraction of the load in Dushanbe through the HVAC 500kV interconnection between Tajikistan and Kyrgyztan, while using equivalent power generated in Sangtuda and Nurek power stations to be exported through the HVDC connection between Tajikistan, Afghanistan and Pakistan. Note that the power transfer requirement between Nurek/Sangtuda and Dushanbe is decreased when compared to the case without the CASA project.

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Figure 8-2 Diagram of the power flow between Nurek and Sangtuda power stations and the load center at Dushanbe with the CASA project

• After close examination of the PSS/E print out data in the ADB report “Tajikistan: Power Rehabilitation Phase II”, the power transfer between Nurek and Sangtuda consists mainly of the equivalent of two 220 kV transmission paths with a combined capacity of 2x276 MW = 552MW1. Other parallel paths between Nurek and Sangtuda are assumed to contribute marginally to the power transfer capacity between both substations.

• According to the “Techno-Economic Pre-feasibility Study for the Central Asia-South Asia Transmission Interconnection (CASA –1000)” dated December 2007, the length of a line between Nurek and Sangtuda substations is 80 km.

The table below shows the power to be transferred to Sangtuda and the recommended reinforcement between Nurek and Sangtuda substations for the different CASA options.

Table 8-1 Tajikistan Proposed High Level Transmission Reinforcements for the Different CASA Options

HVDC capacity

Nurek-Sangtuda Transfer

Transfer Deficit Proposed Reinforcement

1300 610 58 220kV single circuit 1800 1110 558 500kV single circuit 2300 1610 1058 500kV double circuit 2800 2110 1558 500kV double circuit 3300 2610 2058 500kV double circuit

1 In this analysis no reliability criterion such as N‐1 has been considered.

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Tajikistan proposed a number of transmission options. The consultant considered these options and included indicative costs for reinforcing the networks to ensure that CASA power can be evacuated reliably based on the original configurations proposed in the first CASA-1000 study.

8.2 Transmission Needs of the Existing Network in the Kyrgyz Republic

The power system in the Kyrgyz Republic can deliver up to 1000 MW at the Datka substation without incurring significant costs in the upgrade of its internal AC power system. From Datka, this level of power can be delivered to Tajikistan either through a 500 kV line to Khoujand or a direct 500kV line to Sangtuda.

8.3 Transmission Needs of the Existing Network in Afghanistan

The Afghanistan 220kV network at Kabul is in the early stages of development and is mainly a distribution system at this time. The capability of the distribution system is limited since much of this network is in need of repair and rehabilitation. The upgrades necessary to allow the Kabul system to absorb the import from Tajikistan are required whether or not the interconnection is built since the power must come from either the interconnection or from local generation. Thus any costs associated with such an upgrade are external to the economic viability of the interconnection.

In order to integrate the converter station into the existing transmission/distribution network in Kabul, an allowance for 10 km of 220 kV double circuit line has been made in the cost estimate.

8.4 Transmission Needs of the Existing Network in Pakistan

Based on load flow studies carried out during the initial assessment of the HVDC interconnection, the Pakistan network at Peshawar can absorb all the power to be delivered by the CASA DC interconnection project without incurring significant costs in the upgrade of their AC power systems up to an import level of 1,000 MW. If the import level into Pakistan were increased to 1,300 MW or 2,000 MW, then some additional 500 kV transmission out of the Peshawar area would probably be required. This could take the form of a 500 kV line from Peshawar to Ghazi Barotha, as examined in the Phase-I report. However, if the import were kept at the 1,000 MW level, the additional 300 to 1,000 MW would have to be provided from generation in the south of the country. This would certainly require additional transmission capacity from south to north and would be more expensive than the reinforcement out of Peshawar. Thus any reinforcement of the 500 kV system out of Peshawar is considered as part of general system reinforcement and is not directly tied to the interconnection project.

Access restrictions to the Peshawar substation site due to existing 500 kV and 220 kV lines would mean that the HVDC converter station would need to be located at a site remote from Peshawar and tied into the Peshawar substation via some short 500 kV circuits. This has been included in the cost estimate by allowing for two 10 km 500 kV circuit to integrate the converter station into the existing network.

8.5 Interconnection between the Kyrgyz Republic and Tajikistan

Two options of delivering power from the Kyrgyz Republic to Sangtuda are examined. The first option is to deliver the power over a dedicated line directly from Datka to Sangtuda. The second option is to deliver power from Datka to Khoudjand on a dedicated line and using the

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internal Barki Tojik network to transmit power onward to Sangtuda. The latter option is effectively a swap of power with power from Sangtuda that normally serves the load in North East Tajikistan being supplied by power from the Kyrgyz Republic at Khoujand.

Analysis of Datka – Khoudjand Interconnection - 500 kV / 1000 MW

After reviewing the input data, the demand at Dushanbe is generally greater than the power imported by Tajikistan from the Kyrgyz republic via the Datka-Khoudjand interconnection. As most of the generation in Tajikistan is located in Sangtuda and Nurek power plants located south of Dushanbe, the effect of this interconnection is to decrease the power flow from the south to the north. This power flow reduction causes a greater proportion of the power generated in Nurek and Sangtuda power plants to be exported though the CASA interconnection. This option has been referred to as the power swapping option where a power import in the demand-rich north is swapped by a power export in the generation-rich south. Under this Option, Table 8-1 which enumerates the transmission reinforcements, is still valid.

Analysis of Datka – Sangtuda Interconnection - 500 kV / 1000 MW

A high-level preliminary assessment of the Datka Sangtuda power line shows that:

• The length of the line is roughly 40% to 50% longer that of the Datka - Khoudjand line.

• Line compensation (series and shunt) and one intermediate substation are likely to be necessary in order to transport 1000 MW over a 500 kV / 670 km line.

From the point of view of the Tajikistan internal power system, connecting Datka directly to Sangtuda possibly requires more extensive AC system reinforcements in Tajikistan when compared to the Datka-Khoudjand interconnection. The injection of power at Sangtuda substation from Kyrgyzstan only adds to the predominant south-north power flow in Tajikistan and aggravates any pre-existing transmission deficiency. Connecting Datka directly to Sangtuda does not take advantage of serving a fraction of the load at Dushanbe from Kyrgyzstan and the subsequent reduction of the transmission requirements from Nurek/Sangtuda to Dushanbe (the so-called “swapping” of power). The estimated costs and transmission losses related to both options are summarized in Table 8.2 under the following assumptions:

• The Datka – Sangtuda line is 40 percent longer that the Datka –Khoudjand line.

• One intermediate substation is required for the Datka – Sangtuda line.

• Losses are calculated for a line loading of 1000 MW at a power factor of 0.95.

Table 8-2 Interconnection Options between the Kyrgyz Republic and Tajikistan – High Level Cost Estimation and Transmission Losses

Kyr-Taj Interconnection Option Costs Transmission Losses

US $ million MW

Datka - Khoudjand 197 13 Datka - Sangtuda 288 18

Project Costs include EPC, Owner’s Engineer and Contingency estimates.

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Given the obvious advantages of the Datka – Khoudjand interconnection, this option will be taken as the basis for the economic analysis and the project costing. Please refer to section 9 for the detailed costing analysis of the Datka – Khoudjand transmission line.

There are some contractual and operational issues that need to be addressed if the Barki Tajik internal network is used to transfer the power from Khoudjand to Sangtuda. The contractual issues related primarily to accounting of energy delivered to Barki Tajik network from the Kyrgyz Republic and the equivalent energy being delivered to the CASA line. There will have to be additional coordination required to ensure proper flows of power during the time that power is transferred on the Datka – Khoudjand line.

As noted above, there are significant costs associated with the construction of a dedicated additional line. Not only will the power swapping option avoid additional transmission losses through a dedicated line, but it will also result in reduced losses in the Barki Tajik system.

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9 PROJECT COST AND COUNTRY WIDE ALLOCATION

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9 PROJECT COST AND COUNTRY WIDE ALLOCATION

Various project sizes and configurations were analysed as part of this study. This section provides cost details for the recommended project only. However other project alternatives that were analysed in the process of selecting the recommended project are discussed in section 6 and cost details for these are provided in appendix I, note I.4.

In this report updated costs are provided for the HVDC transmission interconnection between Tajikistan, Pakistan and Afghanistan as well as for the HVAC interconnection between the Kyrgyz Republic and Tajikistan. The costs are presented as follows:

• HVDC transmission interconnection (Tajikistan – Afghanistan – Pakistan);

• HVAC transmission interconnection (the Kyrgyz Republic – Tajikistan); and

• Total project (HVDC interconnection + HVAC Interconnection) including contingency and Owner’s engineer fees as well as the costs for the country network reinforcement and environmental and social mitigations

The project costs presented in this section are “best estimates” based on current market conditions. These may change over time in response to market volatility.

The project cost estimates are based on the following:

• Costs of the 500 kV, 750 km HVDC interconnection link with conversion capacity of 1300 MW at Sangtuda, 300 MW at Kabul and 1300 at Peshawar.

• The costs of relocating the existing 220 kV line closer to the mountain on steel tubular poles with insulated arms and shorter spans to limit the conductor swing; and route the proposed HVDC line on steel tubular poles (option 1 of the three options proposed in section 7.2) are included in the HVDC interconnection link costs above.

• Costs of ground electrodes at Sangtuda, Kabul and Peshawar.

• Costs of the 500 kV, 477 km HVAC Interconnection between Kyrgyz republic (Datka substation) and Tajikistan (Khoudjand substation)

• Costs of the country network reinforcements

• Costs of Environmental and Social mitigation measures

9.1 Cost Estimates of the Proposed HVDC Transmission Interconnection (Tajikistan – Afghanistan - Pakistan)

Table 9-1 provides the engineering, procurement and construction (EPC) cost estimates for the converter stations and substations, as well as the transmission line, for the Tajikistan - Afghanistan - Pakistan HVDC interconnection.

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Table 9-1 EPC Cost Estimate for the HVDC Tajikistan - Afghanistan - Pakistan Interconnection (US $ Million)

Countries Converter Stations +

Substations Transmission Line Electrodes Total

Tajikistan 128 33 5 166 Afghanistan 71 162 5 239 Pakistan 128 20 5 153 The Kyrgyz Republic - - - -

Total EPC 326 216 16 558 *Estimates include EPC costs only.

Cost Estimates for the HVDC Converter Stations and Substations

SNC-Lavalin contacted the main suppliers of HVDC converters worldwide to provide an updated cost estimate of the converter stations. These costs are based on the following scope of work:

• A complete turnkey contract for the converter stations including supply, delivery and installation as well as site leveling and preparation;

• The converters are comprised of a bipolar system with ground electrodes, +/- 500 kV DC voltage, unity power factor at the AC buses, complete with valves, converter transformers, AC and DC filters, reactive power compensation equipment, and a 50Hz filter on the DC line side, and complete with all switching, controls, buildings and auxiliaries, but excluding AC line termination circuit breaker entries to the AC switchyards. The AC bus voltage at either end is assumed to be 500 kV.

Cost Estimates for the HVDC Transmission Line

The HVDC line estimates are based on the costs presented in the original CASA Feasibility Study Phase 2 report, updated to reflect appropriate changes. Cost references from relevant projects were used for verification.

9.2 Cost Estimates of the Proposed HVAC Transmission Interconnection (the Kyrgyz Republic - Tajikistan)

Table 9-2 below presents the cost estimates for the line and substations for the Kyrgyz Republic - Tajikistan interconnection between Datka and Khoudjand.

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Table 9-2 EPC Cost Estimate for the HVAC Kyrgyz Republic - Tajikistan Interconnection (US $ Million)

Countries Substations Transmission Line Total

The Kyrgyz Republic 9 151 160

Tajikistan 9 7 16

Total EPC 18 158 176 *Estimates include EPC costs only.

Cost Estimates for the HVAC Line

The 500 kV line connecting the Kyrgyz republic (Datka substation) and Tajikistan (Khoudjand substation) was assumed to follow the route described in the previous CASA Feasibility Study – Phase 2 Report, Section 4. The cost estimate was updated to reflect changes in market conditions since the previous pre-feasibility study.

Cost Estimates for the HVAC Substations

The substation costs associated to the 500 kV Datka – Khoudjand transmission line include the line termination with associated switchgear and bus-work. The above estimation does not include any step-up transformer cost.

9.3 Network Reinforcement Costs

In addition, the network reinforcements discussed in section 8 are included in the analysis and are presented in Table 9-3.

Table 9-3 Network Reinforcement Costs in MUSD

HVDC Size Option (MW) Tajikistan Afghanistan Pakistan

1,300 24.1 4.3 5.9

Notes: Project Costs include EPC, Owner’s Engineer and Contingency estimates

9.4 Environmental and Social Costs

The environment and social costs including land acquisition costs for Pakistan, Afghanistan and Tajikistan estimated at 2007 prices in the Environmental Social Impact Assessment reports for CASA Phase II Study were used. A 15% increase of the costs has been assumed for inflation for the past 3 years.

The environment and social costs for Pakistan, Afghanistan and Tajikistan as well as for the Tajikistan and the Kyrgyz Republic interconnection line estimated in the Environmental Social Impact Assessment reports for CASA Phase II Study are provided in Table 9-4 below.

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Table 9-4 Environment and Social Costs for Pakistan, Afghanistan and Tajikistan (US $ Million)

Pak Afg Taj Taj-Kyr line Total

Environmental and social cost estimate for the original CASA Phase II Study 2.3 9.5 1.9 0.3 14.0

Environmental and social cost estimate for the feasibility update* 2.6 10.9 2.2 0.4 16.1

* A 15% increase of the environment and social costs for CASA Phase II Study has been assumed for inflation for the past 3 years.

9.5 Estimation of Total Project Costs

Table 9-5 below summarizes the total project costs, which includes the HVAC interconnection between the Kyrgyz Republic and Tajikistan and the HVDC interconnection between Tajikistan, Afghanistan and Pakistan. All costs are based on the premise that this project will be bid internationally and will adhere to international standards.

Table 9-5 EPC Cost Estimate for HVDC Tajikistan-Afghanistan-Pakistan and HVAC Kyrgyz Republic-Tajikistan Interconnections (US $ Million)

Countries

HVDC Component HVAC Component HVDC + HVAC Cost

Converter Stations + Substations

Electrodes Transmission Line Substation Overhead

Line

Tajikistan 128 5 33 9 7 182 Afghanistan 71 5 162 - - 238 Pakistan 128 5 20 - - 153 The Kyrgyz Republic - - - 9 151 160

Total EPC Costs 558 176 734

*Estimates include EPC costs only.

In order to estimate the total project costs other costs such as Owner’s Engineer, Contingency, country network reinforcements, environmental and social mitigation measures were added to the EPC costs shown in Table 9-5 above. These costs were calculated as follows:

• Owner’s Engineer – 2% of EPC Costs

• Contingency – 10% of EPC plus Owner’s Engineer Costs

Table 9-6 shows the total project costs based on the parameters defined above.

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Table 9-6 Total Project Cost (US $ Million)

Component Project Costs

EPC (HVDC+HVAC) 734 Owner’s Engineer 15 Contingency 74 Internal Reinforcements in Countries (Including engineering costs and contingencies) 34

TOTAL 873

In addition, interest during construction (IDC) calculated at a 5% annual interest rate amounts to 80 million USD.

9.6 Currency Split

A portion of the total cost would be expended in Euros, and the remainder in US dollars. Table 9-7 below shows the split between currencies for the EPC project costs. An exchange rate of 1.4 was used to convert the Euros to US dollars as at 5 November 2010.

Table 9-7 Total Project Costs Currency Split

Component

Project Costs

Project Costs to be Expended as Euros

(Costs Expressed in US $ Million)

Project Costs to be Expended as US $

(Costs Expressed in US $ Million)

Total Project Costs (Costs Expressed in

US $ Million)

EPC 240 633 873

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10 ECONOMIC ANALYSIS

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10 ECONOMIC ANALYSIS

This section presents the analysis of two aspects of the interconnection project:

• The economic evaluation including sensitivity analysis for the interconnection alternative considered as a suitable option to have a transmission line of 1,300 MW and converter stations of 1,300 MW capacity in Tajikistan, 1,300 MW in Pakistan and 300 MW in Afghanistan in view of the economic performance and funding constraints to finance and execute the project; and

• The benefit allocation to each of the countries and country-wise B/C ratios

10.1 Methodology

A number of approaches can be used for the economic analysis of the cross-border transmission interconnection projects. The choice of appropriate approach depends on a number of factors including the purpose of the interconnection project, data availability, and so on. The following paragraphs present the proposed approach.

Broadly speaking, for the economic evaluation, the cost of generation in Tajikistan and the Kyrgyz Republic plus the cost of interconnection are compared with the cost of generation in Pakistan and Afghanistan. The avoided costs in Afghanistan and Pakistan due to import of energy from Tajikistan and the Kyrgyz Republic represent the benefits of the interconnection.

The economic evaluation of the project involves the following principle tasks:

• Assessment of the cost for export of power from Tajikistan and the Kyrgyz Republic;

• Assessment of the generation costs in Pakistan and Afghanistan;

• Assessment of the transmission interconnection costs; and

• Benefit-cost analysis and estimation of EIRR.

Cost of Supply of Exporters and Avoided Cost of Importers

The assessment of the costs of supply in Tajikistan and the Kyrgyz Republic and the generation costs in Pakistan and Afghanistan are detailed in section 5 and summarized below.

The cost of supply for Kyrgyz Republic exports has been estimated based on recent export contracts with volumes similar to the CASA exports. The levelized cost of export and present value (PV) of the cost of export over the life of the interconnection project are assessed by using an appropriate discount rate.

The cost of supply for Tajikistan exports has been estimated based on official figures for 2009 and the cost of purchasing power from the Sangtuda I & II projects as well as for the O&M fixed costs of Nurek and other existing hydro power plants.

In Pakistan the figures for avoided cost of power have been estimated using the average price of PPAs using residual fuel oil (RFO) and diesel. The levelized cost of generation and PV of generation costs for Pakistan will also be assessed.

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A conservative estimate has been used for the avoided cost of power in Afghanistan based on recent project costs, existing import contracts and alternative sources.

Assessment of Transmission Interconnection Costs

One important aspect of the economic analysis is the estimation of the transmission interconnection costs. After determining the principal technical parameters of the transmission line, the transmission line costs for both the Tajikistan-Kyrgyz Republic HVAC line and the Tajikistan-Afghanistan-Pakistan HVDC line are estimated. The detailed costs are provided in section 9. The total cost of transmission interconnection and PV of the transmission interconnection costs are estimated. This includes the investment and O&M costs of the interconnection over the economic life of the interconnection.

The reinforcement costs in Tajikistan, Pakistan and Afghanistan required for delivering the power from the exporting countries to the importing countries were also estimated and included in the project costs for the economic analysis. In addition, provision was made for environmental and social costs.

The costs associated with the project are:

• HVDC Interconnection Cost between Tajikistan, Afghanistan and Pakistan (Investment and O&M);

• Ground electrodes in Tajikistan, Afghanistan and Pakistan;

• HVAC Interconnection Cost between Tajikistan and the Kyrgyz Republic (Investment and O&M);

• Reinforcement costs in Tajikistan, Pakistan and Afghanistan (Investment and O&M); and

• Project environmental and social costs.

Assessment of Benefits

As regards the project economic benefits, it is to be noted that the primary economic benefits will result from the export of lower-cost energy from Tajikistan and the Kyrgyz Republic which will displace the higher-cost energy in Pakistan and Afghanistan. Once the system costs of generation are estimated in both the exporting countries (the Kyrgyz Republic and Tajikistan) and the importing countries (Pakistan and Afghanistan), the benefits of the interconnection are assessed by comparing the system cost of generation in the exporting countries plus the cost of transmission interconnection with the cost of generation in the importing countries.

The interconnection can also provide secondary environmental, social and economic benefits. Though these benefits are discussed in section 10.3.2, for this study only the primary economic benefits were quantified and included in the economic analysis.

Benefit-Cost Analysis and Estimation of EIRR

The benefit-cost ratio of the project is determined by calculating the ratio of the benefits of the project and the transmission interconnection costs. The EIRR is estimated based on the benefit and cost flow streams over the study period. Other benefits such as environmental benefits and indirect benefits shall be assessed and included for the analysis in the next stage.

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10.2 Interconnection Option for Economic Analysis As presented in section 6.1, the size optimization analysis shows that there is very little difference between the B/C ratios of the 1,300 MW, 1,800 MW and 2,300 MW options. However, in the event of funding constraints to finance and execute a project of 1,800 MW or 2,300 MW, the recommended option is to have a transmission line of 1,300 MW and converter stations of 1,300 MW in Tajikistan, 1,300 MW in Pakistan and 300 MW in Afghanistan. The 1,300 MW converter capacity in Peshawar provides flexibility that would enable Pakistan to import, in addition to its 1,000 MW share, any of Afghanistan’s 300 MW that it may not need. This option has been used as the base case for the economic analysis keeping the export energy surplus to the level of 1,300 MW.

10.3 Major Assumptions and Input Data

Major assumptions and input economic parameters that were used for the economic evaluation are provided in the following paragraphs.

It is important to note that the feasibility study is based on a number of conservative assumptions, listed below:

• The energy surplus potential was assessed based on the assumption that no additional generation capacity will be added during the study horizon in the exporting countries. A sensitivity assuming that generation is built to compensate for the increase in load, hence providing constant energy export to Pakistan and Afghanistan, is shown in section 10.6 (see sensitivity #7).

• A conservative rate was used for energy opportunity cost in Pakistan. A sensitivity analysis with a higher rate is presented in section 10.6 (see sensitivity #4).

• A conservative rate of 0.06 $/kWh was used for energy opportunity cost in Afghanistan. A sensitivity analysis with a higher rate is presented in section 10.6 (see sensitivity #6).

• Only primary economic benefits were quantified. Other secondary benefits (environmental, social) were not quantified.

10.3.1 Costs

The costs required to be assessed for the study include:

• The cost for export of power from Tajikistan and the Kyrgyz Republic;

• Investment and O&M costs of CASA project including the HVDC interconnection between Tajikistan, Afghanistan, Pakistan, the interconnection between the Kyrgyz Republic and Tajikistan, the reinforcement costs in Tajikistan, Pakistan and Afghanistan, and the project environmental and social costs; and

• Generation cost (LRMC) in Afghanistan and Pakistan.

Assessment of the Cost for Export of power from Tajikistan and the Kyrgyz Republic

As detailed in section 5, the cost of supply for Kyrgyz Republic exports has been estimated based on recent export contracts with volumes similar to the CASA exports, provided on a confidential basis.

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The cost of supply for Tajikistan exports has been estimated based on official figures for 2009 (from the Statistical Agency under the President of the Republic of Tajikistan http://www.stat.tj/english/home.htm) and the cost of purchasing power from the Sangtuda I & II projects as well as for the O&M fixed costs of Nurek and other existing hydro power plants. The cost of supply for Tajikistan is estimated at 1.5 cents/kWh.

Assessment of the Transmission Interconnection Costs

As outlined in section 9, the interconnection project for economic analysis is proposed to comprise 1,300 MW converters in Sangtuda and Peshawar, a 300 MW converter in Kabul, and 1,300 MW transmission line. The project cost including EPC costs, owner’s engineer fees, contingencies, internal reinforcements and environmental and social costs for this option is provided in the table below.

Table 10-1 Total Project Cost of the Selected Alternative for Economic Analysis Unit: million US$

HVDC

Component including

electrodes

HVAC Component

Reinforcements in TAJ, PAK and

AFG

Environmental and Social

Costs Total

Project

Total Investment* 626 197 34 16 873

* Total investment includes the EPC costs, owner’s engineering fees and contingencies

The above table illustrates that the investment of HVDC components, HVAC components and reinforcements in Tajikistan, Pakistan and Afghanistan are estimated to be US $ 626 million, US $ 197 million and US$ 34 million, respectively, giving the total Project investment costs of US $ 873 million.

The O&M cost was estimated as 3% of the investment cost.

A placeholder has been used for environmental and social costs. Firm numbers for the environmental and social costs will be available following detailed studies to be undertaken shortly. The environmental and social costs estimates in this analysis will be updated at that time. However a sensitivity analysis is presented using environmental and social cost figures provided in the original CASA study. The environmental and social costs for Pakistan, Afghanistan and Tajikistan estimated at 2007 year’s price in the Environmental Social Impact Assessment reports for CASA Phase II Study were used for the sensitivity analysis in Section 10.5 of this report. A 15% increase of the costs has been assumed for inflation for the past 3 years.

Assessment of the Generation Costs in Pakistan and Afghanistan

In Pakistan the figures for avoided cost of power have been estimated using the average price of PPAs using residual fuel oil (RFO) and diesel. According to figures from the NEPRA website the all-in price of the contracts including capacity charges is 13.2 US cents/kWh and the energy price is 9.2 US cents/kWh.

A conservative estimate has been used for the avoided cost of power in Afghanistan based on recent project costs, existing import contracts and alternative sources. The price used in Afghanistan is 6 US cents/kWh.

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Section 5 provides additional information on the assessment of generation costs in Pakistan and Afghanistan.

10.3.2 Benefits

The primary economic benefit of the project is the avoided costs in Afghanistan and Pakistan due to import of energy from Tajikistan and the Kyrgyz Republic. The benefits of the interconnection were assessed by comparing the system cost of generation in the exporting countries plus the cost of transmission interconnection with the cost of generation in the importing countries.

The potential energy surplus is obtained from the SDDP simulation model for 20 years (2016-2035) for the CASA 1,300 MW interconnection option, which is a conservative estimate for the benefits. For the following 10 years from 2036 to 2045, energy surplus is assumed to decrease by the average decreasing rate of the last 5 years’ energy surplus from 2031-2035 for each of the following years.

The interconnection can also provide environmental benefits related to a shift towards environmentally preferred generation sources and to a reduction of green house gas emissions when hydro energy replaces thermal energy in the importing countries.

Cross-border transmission and energy transactions stand to strengthen regional cooperation. The interconnection between Tajikistan and Kyrgyz Republic can improve the system coordination and system operating flexibility and provide benefits to the countries.

Finally, the development of the interconnection project can promote the economic growth and encourage the economic cooperation among the exporting and importing counties. The construction of the project results in short-term employment for the construction companies and suppliers. The revenue of the companies and suppliers in turn generate additional income in other sectors, i.e. indirect benefits. In long term, the ongoing operation and maintenance of the transmission lines will provide employment for the operating and maintenance staff in the countries.

10.3.3 Discount rate

The rate used for discounting the costs and benefits is ten (10) percent.

10.3.4 Useful lifetime

Useful lifetime of the transmission interconnection for the economic evaluation was assumed to be 30 years.

10.3.5 Escalation

Escalation was not considered in the economic analysis.

10.4 Result Summary of Economic Analysis To assess the economic viability of the interconnection project, a spreadsheet model was built to cover the period of economic evaluation from 2016 through 2045 to model the benefit and cost flows, calculate the economic parameters (B/C Ratio, NPV, and EIRR) and conduct the sensitivity analysis.

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The present value of benefits (year 2016) for each of the countries was calculated based on the discount rate of 10% for the study period of 30 years. The present worth of the benefits and the total costs including O&M costs for the overall project are estimated to be US$ 1,721 million and US$ 1,281 million, respectively, discounted to the beginning to 2016 at 10%. The B/C ratio and the EIRR are estimated to be 1.34 and 15.6%, respectively, for the overall project. The NPV is estimated to be US$ 440 million at the discount rate of 10% to the beginning of 2016. The results are summarized in Table 10-2.

Table 10-2 Economic Analysis Results

Benefits 1,724 MUSD

Costs 1,281 MUSD

B/C Ratio 1.34

NPV 440 MUSD

EIRR 15.6 %

Having a B/C Ratio above 1 and an EIRR greater than the discount rate (10%), the project is economically sound. Sensitivity analyses in the following subsection will serve as additional tests to check the project’s economic viability under different scenarios. If the project still holds B/C Ratios greater than 1 and EIRRs greater than 10% for the multiple scenarios then it would be suggested to proceed with the project from an economic standpoint once the financial constraints are met.

10.5 Levelized Cost of Transmission To obtain the annual transmission cost of energy, the annualized investment cost is calculated over the 30-year lifetime of the project. Hence the 873 MUSD project’s annualized investment cost is 110 MUSD/year, with a 10% discount rate. Adding the O&M cost and dividing the total by the total energy exported yearly, the annual transmission cost of energy is calculated in ¢/kWh:

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Table 10-3 Annual Transmission Costs

Year Annual Cost of Transmission

(¢/kWh) Year

Annual Cost of Transmission

(¢/kWh)

2016 3.37 2031 8.15 2017 3.82 2032 9.34 2018 3.61 2033 10.99 2019 3.91 2034 12.83 2020 4.12 2035 16.52 2021 4.27 2036 19.04 2022 4.42 2037 21.95 2023 4.47 2038 25.30 2024 4.67 2039 29.16 2025 5.42 2040 33.61 2026 5.23 2041 38.73 2027 5.46 2042 44.64 2028 6.44 2043 51.45 2029 6.91 2044 59.30 2030 7.26 2045 68.35

As observed in the table above, in the initial years of the project, the cost of transmission is around 4 ¢/kWh. However, with increasing load and no generation expansion plans, the surplus decreases and this drives the annual transmission cost of energy to rise to around 70 ¢/kWh by 2038. Hence, with an adequate generation expansion plan, if the level of surplus can be maintained around that of the initial years, a transmission charge of 4 ¢/kWh would be appropriate to recover the investment.

Dividing the NPV of the investment and O&M by the NPV of the exportable energy, the levelized cost of transmission is calculated at 4.97 ¢/kWh which is close to the annualized cost in the initial years.

10.6 Sensitivity Analysis The sensitivity analysis was undertaken to examine the impacts on the economic performance of the project by changing the following factors:

• Discount rate (8% and 12%)

• Capital costs of the interconnection project (+10% and -10%)

• Energy surplus (+10% and -10%). Please note that for the +10% sensitivity, the transmission constraint was taken into consideration when assessing the exportable energy surplus.

• Higher opportunity cost in Pakistan (cost of rental plants, i.e. US$ 0.20.kWh)

• Lower opportunity cost in Pakistan: average price of residual fuel oil (RFO) and diesel PPAs (base case) in addition to gaz IPP’s

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• Higher generation costs in Afghanistan (same as the generation costs in Pakistan, US$ 0.132/kWh for firm energy, US$ 0.092/kWh for non firm energy)

• Assuming generation capacity is built to match load increase in Tajikistan and the Kyrgyz Republic as to maintain constant export to Pakistan and Afghanistan

• Afghanistan can use only 100 MW. Pakistan will import the remaining 1,200 MW.

• One year project delay

• Uncoordinated operation of Nurek and Toktogul reservoirs

The following table summarizes the B/C ratio, EIRR, and NPV of the overall project due to the variation of the above-mentioned factors.

Table 10-4 Results of Sensitivity Analysis

Sensitivity Economic Parameters

Factors B/C Ratio EIRR NPV (M US$)

1 Discount rate 8%

Base Case (10%)12%

1.50 1.34 1.21

15.6% 15.6% 15.6%

642 440 264

2

Capital costs -10%

Base Case+10%

1.49 1.34 1.22

17.6% 15.6% 13.8%

566 440 313

3

Energy Surplus -10%

Base Case+10%

1.17 1.34 1.51

13.0% 15.6% 17.9%

222 440 657

4 Higher opportunity cost in Pakistan

US$ 0.20/kWh

2.89

31.9%

2,422

5 Lower opportunity cost in Pakistan

Average price of residual fuel oil (RFO), diesel and gas PPA’s

1.15 12.5% 187

6

Higher generation costs in Afghanistan

US$ 0.132/kWh for firm energy, US$ 0.092/kWh for non firm energy

1.44 17.0% 570

7 Assuming constant energy export to Pakistan and Afghanistan 2.11 20.8% 1,418

8 Afghanistan use only 100 MW; Pakistan uses the balance of 1,200 MW

1.45 17.1% 577

9 One year project delay 1.14 13.9% 273

10 Energy surplus with uncoordinated operation of Nurek and Toktogul reservoirs

1.16 12.6% 202

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The above table shows that the project has a positive NPV and a B/C ratio greater than one for all sensitivities, in addition to achieving an EIRR greater than the discount rate. These results confirm the economic viability of the project, further strengthening the conclusion drawn from the results of the economic analysis in the previous subsection. If costs increase, energy exported decreases or discount rate increases, the project still produces favorable economic indicators.

10.7 Country-Wise Benefit Allocation

Though benefit allocation is usually done as part of a financial rather than an economic analysis, the benefit allocation for each country was requested during the initial study to provide some indication of how benefits can be allocated to each country. The updated country-wise allocation is provided in appendix I, note I.6.

However, for deciding the viability of the project, the overall economic benefit / cost ratio should be the determining economic criteria. Commercial agreements should ensure that each country receives appropriate allocation of the financial benefits to ensure adequate return to fund financial commitments.

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11 MAJOR RISKS WITH IMPLEMENTATION AND OPERATION

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11 MAJOR RISKS WITH IMPLEMENTATION AND OPERATION

11.1 Security

Security is a key issue for the project, both during construction and operations. The primary security issues are related to landmines, sabotage and theft of equipment. These issues can be addressed with proper planning but never eliminated. Contingency plans will have to be in place to mitigate the impact of security-related issues.

Construction of the line will have to take place on land cleared of landmines which will entail additional cost and delays. However, during the construction of the 220 kV line, it was found that not all landmines were properly cleared, even though they were officially certified as clear. Additional precautions will need to be taken by the contractors and the operators. A 10 million US$ cost provision has been included to this effect.

For operational reasons related to quick restoration of power, the line should be built in areas that are relatively accessible by road. The incidence of sabotage and theft will have to be ascertained but any increase in outages due to these threats can be mitigated somewhat with restoration procedures that enable the operators to respond quickly. This would require good access to the line to reduce outage times. Restoration procedures would require a larger inventory of spare parts (including temporary towers) and work crews. These costs have been included in the initial project costs as well as in operation and maintenance allocations. For example, operation and maintenance costs are normally 2% of capital costs, but for the CASA line 3% was used.

Unauthorized power take-off along the line is not an issue in the case of HVDC as power has to be converted into AC through a converter station before feeding any type of load. Moreover, the amount of power sent and received at each converter station is strictly controlled by the valves and the control system.

11.2 IGC Management

The IGC structure will have ensure that the decision-making process is streamlined to deal with major issues that may arise during the construction and operation of the line. It is anticipated that protocols will be developed early on in the process to deal with day-to-day decisions.

However, as day-to-day management during the construction will be the responsibility of the contractor and operations will be in the hands of the company managing the transmission once construction is completed, the IGC will only need to deal with extra-ordinary events

11.3 Technical

11.3.1 Lightning

The major technical risk associated with any transmission line involves the impact of external factors on the security and availability of the line. The major cause of line outages due to external factors is the incidence of lightning strokes to the line. Careful design of the overhead shielding of the line will reduce the number of direct strokes to a phase conductor to virtually zero. However, lightning strokes to the overhead shield wires can still result in line tripping due to back-flashovers from the tower to the phase conductor. This can be reduced by attempting to lower the tower footing resistance of each tower, but cannot be entirely eliminated.

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Statistical data on transmission line forced outages is available from a number of sources, but these tend to provide conflicting information due to very different service conditions in different parts of the world. The major factor influencing the lightning performance of a particular transmission line is the level of thunderstorm activity in the area of the line. This is normally quantified as the number of thunderstorm-days per year and the trip-out rate due to lightning is considered to be proportional to this variable. The project area for this study is generally low in terms of the number of thunderstorm-days per year. The reduction in energy transported across the line over the course of a year due to such trip-outs is not significant, although the interconnected system has to be able to survive the outage of the circuit.

Permanent line outages normally have relatively short repair times (< 1 day on average) but for this project, because of the difficulties of transport throughout Afghanistan, repair times are likely to be of the order of 3-4 days. Fortunately, such events should be limited to 1 or 2 occurrences per year. A significant difference should be noted between an AC transmission scheme and a DC transmission scheme in this regard. A double circuit (or two single circuit) 500 kV AC interconnection inherently has the capacity to carry a 1 100 MW transfer with one circuit out of service. For an HVDC interconnection, the permanent outage of one pole due to a line fault would result in a reduction in the transfer capacity to approximately 550 MW. However, measures are available at additional cost that would allow the full capacity to be restored quickly, such as pole switching and the use of earth return. There are fault conditions, such as the loss of a converter transformer or DC smoothing reactor that can result in the long-term unavailability of one pole. Such conditions are extremely rare and are not normally considered significant.

11.3.2 Ground Electrodes

The other major technical risk associated with HVDC interconnections is the cost of obtaining a ground electrode at each converter station with a reasonable ground resistance (<1Ω). No information has been gathered at this stage on the soil conditions or geology at any of the potential converter locations to be able to determine the grounding electrode locations and requirements. The normal cost for a ground electrode is of the order of US$ 1 million in good soil conditions. In very adverse soil conditions, this cost will increase and could go up to US$ 9 million per electrode.

11.3.3 Operational – Coordination between System Operators

From an operational perspective, there are also significant differences between AC and DC interconnections. A DC interconnection can be easily controlled as an independent facility. Power and current orders can be selected ahead of time and programmed into the DC control schemes of both rectifiers and inverters to set the level of transfer independently of the AC systems connected at either end. An AC interconnection maintains its desired transfer level by continuously adjusting the generation levels in the connected AC systems to cater to changes in the demand in each system. With such an interconnection, one system (usually the largest) takes the responsibility for controlling the frequency of the interconnected system and the smaller systems take responsibility for controlling the power transferred across the interconnection. With either interconnection scheme, it is required that close cooperation is maintained between the system operators of the connected systems so that the correct generation/load balance can be maintained in each system to ensure that frequency deviations are minimized. A major difference between AC and DC interconnections is that the failure of one system to maintain a correct generation/load balance impacts all the participants in the AC interconnected system, whereas with a DC interconnection, the impact is seen only in the system that fails to maintain its correct balance. A DC interconnection also provides immunity in each connected system from the

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impact of faults in the other system, insofar as these faults do not affect the operation of the DC interconnection itself.

There are numerous risks inherent in a project of this nature in addition to the normal implementation and operational risks of a ‘normal’ transmission line. Some of the risks have been discussed in the Phase I report. These and additional risks are summarized in this section.

11.3.4 Salang Pass

There are numerous technical challenges for this line, especially with respect to construction and maintenance at high altitudes and through rugged terrain. The passage of the line through the Salang pass will be a challenge but it is not insurmountable, as discussed elsewhere in this report. The construction and subsequent Operations and Maintenance costs are higher than ‘normal’ as a result. Options for dealing with Salang Pass Constraints are addressed in Seciton 7.2

11.4 Schedule

Risks related to schedule are discussed in Section 13 which presents typical implementation schedules. These schedules will have to be reviewed prior to implementation and address issues such as:

• Acquisition of land for substations

• Technical agreements

• Logistics (transportation)

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12 FUNCTIONAL SPECIFICATIONS

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12 FUNCTIONAL SPECIFICATIONS

Functional Specifications were developed as part of the original report to cover (i) the HVDC transmission line, (ii) the three converter stations, (iii) the overall control system concept for this regional interconnection and (iv) the HVAC transmission line required to reinforce the Tajikistan system.

For each one of these components, the issues which have risen as part of this update are explained below along with their impact, if any, on the original functional specifications.

12.1 HVDC Transmission Line

The critical parameters that shape the functional specification of the line are the following:

• HVDC line voltage

• Changes in the line voltage will impact the design of the tower, the levels of insulation, clearance, etc. This voltage has not changed from its original value: +/- 500kV;

• HVDC line current

• Changes in the line current will impact the number and size of conductors used on each pole to carry the DC current. This is a direct result of the power rating of the converter stations. A Cardinal conductor has been specified in order to carry 1300 MW.

• HVDC line route

• The route is important for the functional specification as special conditions such as high altitude and terrain have to be taken into account. With the exception of the highlighted need to determine a new suitable location for the substation in Peshawar, the line has not changed since the original study.

The functional specification of the HVDC transmission line developed as part of the original study remains valid. An update of the route around the Peshawar substation will be required as part of a subsequent study once the location of the new substation is known. The original DC transmission line functional specification is included in Appendix E.

12.2 Converter Stations

The various aspects of the size optimization exercise carried out as part of this update will affect the following parameters as far as the converter stations are concerned:

• Converter station arrangement and staging

• The arrangement is still planned to be bipolar and constructed in a single stage.

• Base power rating

• The power rating for the bipole is still recommended as 1300 MW. The higher rating used for the line is only to preserve flexibility for possible future upgrades. The specification in Appendix G is written on the basis of a 1300 MW project.

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• Number of terminals

• The backfeed option was analyzed in more detail as part of this update and it was found that the three terminal option remained the better choice for this interconnection. The number of terminals then remains three.

• Grounding and electrodes

• The actual feasibility of installing electrodes can only be decided at the detailed study stage when earth resistivity measurements can be carried out in the vicinity of each converter station site. In case no suitable site is found, the alternative in case of loss of a pole is to use that pole’s conductor as a metallic return. Electrodes are currently included in the functional specifications and their price is taken into account in the project cost.

The original functional specification for the converter stations is then not impacted. It is included in Appendix G.

12.3 Control System Concept

The aspects of this update which can potentially affect the detailed control scheme developed as part of the original functional specifications are the following:

• Number of converters

• The control system concept is highly dependent on the number of terminals in the interconnection. The original concept was developed for three terminals, and remains valid.

• Converter station arrangement and staging

• The arrangement is still planned to be bipolar and constructed in a single stage.

• Central Control Unit:

• The interconnection control centre could be located in any one dispatch centre of any of the countries involved, or could be a separate control centre. This depends on the agreements reached between the countries. The scheme could also be set up so that all countries have the possibility of taking control of the scheme, however only one country could have control at any given time. The cost implications of the various options are not significant.

It is important to note that the nature of the AC system reinforcements do not have any impact on the control system concept. This is due to the fact that DC technology operates on the basis of a “power order”. The power transfer order received at each converter station from the master control will be executed regardless of the strength of the AC networks.

Based on the above, there is no impact on the functional specification for the control system included in Appendix G.

12.4 HVAC Transmission Line

The functional specification of the HVAC transmission line linking Tajikistan to the Kyrgyz Republic is shown in Appendix F, and depends mainly on the size of the CASA interconnection and the load swapping arrangement between the two countries. Given that the size has remained at 1000 MW, the load swapping conditions remained unchanged as well. As such the functional specification of this line then remains unchanged from the original report.

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13 PROJECT IMPLEMENTATION SCHEDULE

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13 PROJECT IMPLEMENTATION SCHEDULE

This section presents the typical implementation schedule for the project on a monthly basis. Detailed and specific schedules should be developed in further phases of the project.

13.1 Typical Sequence of Milestones

Figure 13-1 below illustrates the typical sequence of key milestones up to completion of commissioning works and without including warranty period neither performance guarantee period which may vary from one to three years for such project.

Figure 13-1 Typical Sequence of Milestones

13.2 Typical Implementation Schedules

Figures 13-2, 13-3, 13-4 and 13-5 below illustrate the following typical implementation schedules in the form of a Gantt Chart and on a monthly basis:

- Figure 13-2 Typical Implementation Schedule for Award of Turnkey Contracts, applicable to all components of the project

- Figure 13-3 Typical Implementation Schedule for 500kV HVDC Converter Stations at Sangtuda, Kabul and Peshawar and for Control Centre

- Figure 13-4 Typical Implementation Schedule for 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan (750km).

- Figure 13-5 Typical Implementation Schedule for 500kV HVAC Transmission Line Kyrgyz-Tajikistan (450km).

SNC-Lavalin estimates that the project can be completed within a minimum of 58 months (five years). However, this completion period may be extended twelve (12) months depending on different factors such as:

- Availability and reliability of existing information and studies

- Countries’ regulation especially for right-of way of transmission lines

- Stakeholders and utilities intervention during works implementation

- Interface among Owner, contractors, utilities and countries.

8M

Award Consultancy

Contract

Studies

Complete

RFP

Issued

4M

12 months

Tenders Receipt

3M

Award Turnkey

Contracts

3M

HVAC Line

Ready

HVDC Line

Ready

30M 4M 2M

HVDC Converters

Ready

4M

Commissioning System

Complete

M8 M12 M15 M48 M52 M54 M58M0 M18

15 months

18 months

30 months

34 months

36 months

40 months

58 months

8 months

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The first eighteen (18) months are common to all the components of the project: Twelve (12) months to produce studies, specifications and tender documents; and six (6) months to evaluate tenders and to award EPC-turnkey Contracts.

Assuming that all EPC-Turnkey Contracts commence on the same date, SNC-Lavalin estimates that each component of the project can be completed as follows:

- 500kV HVDC Converter Stations and Control Centre 36 months

- 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan 34 months

- 500kV HVAC Transmission Line Kyrgyz-Tajikistan 32 months

The critical path is usually driven by the converter stations and in particular by the manufacturing and delivering of major equipment such as converter transformers and converter valves. However, different regulations in each country may divert the critical path to the transmission lines.

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Figure 13-2 CASA-1000 Project - Typical Implementation Schedule for Award of Turnkey Contracts

Procurement of Turnkey Contracts Month500kV HVDC & HVAC System 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Award of Consultancy Contract1 Inception and Estimating

1.1 Inception and Data Collection1.3 Project Estimates

2 System and Design Studies2.1 Critical System Studies2.2 Non-Critical System Studies

3 System and Design Studies3.1 Critical Design Studies3.2 Non-Critical Design Studies

4 Technical Specifications4.1 Functional HVDC Specifications4.2 Standard HVAC Specifications4.3 Technical Datasheets

5 Preparation of Tender Documents5.1 Instructions to Tenderers and Tender Forms5.2 Conditions of Contract5.3 Schedule of Prices

6 Prequalification of Tenderers (RFQ)6.1 Preparation of Application Documents6.2 Preparation and Receipt of Applications6.3 Evaluation and Selection of Prequalified Tenderers

7 Tendering and Award (RFP)7.1 Preparation and Receipt of Tenders7.2 Evaluation of Un-priced Tenders7.3 Evaluation of Priced Tenders7.4 Preaward and Award of Turnkey Contracts

Notes:Schedule common to all components of the ProjectIt is assumed availability and realiability of existing informationIt is assumed minimum intervention of Stakeholders and UtilitiesNo time extension for preparation of tenders is assumed

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Figure 13-3 CASA-1000 Project - Typical Implementation Schedule for 500kV HVDC Converter Stations at Sangtuda, Kabul and Peshawar and for Control Centre

500kV HVDC Converter Stations and Control Centre MonthSangtuda (Tajikistan) + Kabul in (Afghanistan) + Peshaw ar (Pakistan) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

Award of Turnkey Contract and Notice to Proceed1 HVDC Converter Station Design and Engineering

1.1 Mobilization

1.2 Survey of the Converter Station Areas at Taj.,Kabul and Peshawar

1.3 Preparation of Design and Drawings1.4 Design Review and Approval1.5 Electrodes-Field Investigation1.6 Design -CASA Transm. Control centre1.7 Electrodes-Design

2 Manufacturing of HVDC Converter Station 2.1 Converter Transformers2.2 Capacitors2.3 Reactors2.4 Valves2.5 Switchyard Equipment2.6 Manufacture -CASA Transm. Control centre

3 Supply and Delivery 3.1 Converter Transformers3.2 Capacitors3.3 Reactors3.4 Valves3.5 Switchyard Equipment3.6 Supply -CASA Transm. Control centre

4 Installation and Const. of HVDC Converter Station 4.1 Earth Work4.2 Foundations /structures4.3 Electrodes Installation (optional)4.4 Switchyard and Control Building4.5 Equipemnt Erection and Installation 4.6 Installation -CASA Transm. Control centre

5 Testing, Programming and Commissioning 5.1 Testing HVDC Converter Stations5.2 Programming/testing CASA Transm. Control Centre5.3 HVDC System Ready for Commissioning

Notes:Schedule applicable to three (3) converter stations and one (1) control centreIt is assumed that the work on all the converter stations will be done simulataneouslyIt is assumed minimum intervention of Stakeholders and Utilities

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Figure 13-4 CASA-1000 Project - Typical Implementation Schedule for 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan

500kV 750km HVDC Transmission Line MonthTajikistan (117km) + Afghanistan (562km) + Pakistan (71km) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

Award of Turnkey Contract(s) and Notice to Proceed1 Transmission Line Design and Engineering

1.1 Mobilization

1.2 Survey of the transmission line route and substation areas (combination of LiDAR and ground survey)

1.3 Preparation of Design and Drawings1.4 Design Review and Approval1.5 Tower Spotting

2 Manufacturing of Transmission Line2.1 Tower Structures2.2 Conductors2.3 Insulators2.4 Miscellaneous Hardware

3 Supply and Delivery 3.1 Tower Structures3.2 Conductors3.3 Insulators3.4 Miscellaneous Hardware

4 Installation and Construction of Transm. Line4.1 De-Mining Operation4.2 ROW Clearing and Access Roads4.3 Soil Investigation ,Foundations and Grounding4.4 Tower Erection4.5 Conductor Stringing

5 Testing and Commissioning of Transm. Line 5.1 Testing 5.2 HVDC Line Ready for Commissioning

Notes:Multiple construction contracts maybe be required to complete works in 34 monthsMinimum two (2) construction crews are required to complete works in 34 monthsIt is assumed minimum intervention of Stakeholders and UtilitiesIt is assumed minimum environmental restrictions

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Figure 13-5 CASA-1000 Project - Typical Implementation Schedule for 500kV HVAC Transmission Line Kyrgyz Republic-Tajikistan

500kV 450km HVAC Transmission Line MonthKyrgyz (430km) + Tajikistan (20km) 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Award of Turnkey Contract and Notice to Proceed1 Transmission Line Design and Engineering

1.1 Mobilization

1.2 Survey of the transmission line route and substation areas (combination of LiDAR and ground survey)

1.3 Preparation of Design and Drawings1.4 Design Review and Approval1.5 Tower Spotting

2 Manufacturing of Transmission Line2.1 Tower Structures2.2 Conductors2.3 Insulators2.4 Miscellaneous Hardware

3 Supply and Delivery 3.1 Tower Structures3.2 Conductors3.3 Insulators3.4 Miscellaneous Hardware

4 Installation and Construction of Transm. Line4.1 ROW Clearing and Access Roads4.2 Soil Investigation ,Foundations and Grounding4.3 Tower Erection4.4 Conductor Stringing

5 Testing and Commissioning of Transm. Line 5.1 Testing 5.4 HVAC Line Ready for Commissioning

Notes:Minimum one (1) construction crew required to complete works in 30 monthsIt is assumed minimum intervention of Stakeholders and UtilitiesIt is assumed minimum environmental restrictions

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13.3 Award of EPC-Turnkey Contracts (18 months)

As mentioned above, the first eighteen (18) months are common to all the components of the project. Data collection and power system studies requires at least six (6) months and the technical specifications another six (6) months. In the worst case scenario, three (3) months more should be added to complete the studies and the specifications.

The preparation of the technical specifications and the tender documents is usually performed simultaneously as well as the pre-qualification of bidders (shortlist). The Tenderers will require at least three (3) months to prepare a complete and responsive tender and then three (3) months more will be required to evaluate tenders and to award EPC-Turnkey Contracts. In the worst case scenario, three (3) months more should be added to prepare and evaluate tenders.

The land required for the 1300MW converter station at the 500 KV substation in Peshawar is not available at the moment. Acquiring rights to this land can be a lengthy process, which could result in delays in cases of litigations with the land owners. It is suggested to take up this issue immediately at the beginning of the Award of EPC-Turnkey Contracts period.

13.4 500kV HVDC Converter Stations and Control Centre (36 months)

The typical completion period for the implementation of the HVDC converter stations is 36 months without including commissioning of the entire HVDC system and assuming minimum intervention of Stakeholders and Utilities and full availability of manufacturing factories. In the worst case scenario, a completion period of 42 months should be considered.

SNC-Lavalin assumes that the three (3) converter stations and the Control Centre are implemented simultaneously by a single EPC-Contractor.

13.5 500kV HVDC Transmission Line Tajikistan-Afghanistan-Pakistan (34 months)

The typical completion period for the implementation of 750km of HVDC transmission lines is 34 months without including commissioning of the entire HVDC system and assuming minimum environmental requirements and minimum intervention of Stakeholders and Utilities. In the worst case scenario, a completion period of 40 months should be considered.

The above completion period assumes two (2) construction crews working in parallel. However, the construction period can be accelerated by assigning works to multiple EPC-Contractors, one having several construction crews.

13.6 500kV HVAC Transmission Line Kyrgyz-Tajikistan (30 months)

The typical completion period for the implementation of 450km of HVAC transmission lines is 30 months without including commissioning of the entire system and assuming minimum environmental requirements and minimum intervention of Stakeholders and Utilities. In the worst case scenario, a completion period of 36 months should be considered.

The above completion period assumes two (2) construction crews working in parallel. However, the construction period can be accelerated by assigning works to multiple EPC-Contractors, one having several construction crews.

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13.7 Commissioning of Overall Project (4 months)

The program of testing and commissioning, followed by trial operation, comprises the detailed tests for the equipment and systems before energizing each converter station followed by ‘end to end’ testing of the total transmission system. As well local and remote controls will be tested and accepted at the conclusion of this program. The electrical integrity of the transmission line sections will be confirmed during the trial tests.

All EPC-Turnkey Contracts should be commissioning on the same time to allow transfer of power and testing of the entire HVDC and HVAC system. SNC-Lavalin estimates four (4) months for commissioning of the entire system, including one or two months of trial operation.

13.8 Bidder Participation

During the Phase I report a number of potential bidders expressed interest in the project. Bidder interest is a function of the nature and the structure of the project. An assessment of potential bidder interest in the project can be provided, together with recommendations for maximizing participation in the bidding, once there is firm definition of the project. Some of companies that expressed interest in project during Phase I have changed their orientation and ownership as a result of the worldwide financial crisis.

An addendum to this report can be issued once there is a clear decision to go to the next phase of the project.

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14 OPERATION AND MAINTENANCE PLAN

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14 OPERATION AND MAINTENANCE PLAN

The primary goal of Operation and Maintenance (O&M) practices is to achieve a high level of operational reliability and to have reliable power transfers with minimum losses. These practices should help in improving the reliability and maintenance of plant and equipment, maximising capacity utilisation, increasing operating efficiency, and reducing operating and maintenance costs.

The key responsibilities of the Operation and Maintenance function are:

• To ensure quality and reliability of power supply on the line;

• To optimize equipment operating and maintenance costs through effective utilisation of capacity and resources;

• To maintain and enhance the availability and reliability of plant and equipment with effective maintenance planning;

• To improve spares planning and optimize spares inventories;

• To standardize work procedures;

• To ensure the safety of maintenance personnel;

• To provide a mechanism for estimating and controlling maintenance expenses; and

• To generate MIS reports for better decision-making and control.

The proposed HVDC transmission system is a 3-terminal system operating on +/-500kV bipolar overhead transmission line, 750km long, the system linking the hydro generation in Tajikistan to the load centres in Afghanistan and Pakistan. The interconnection system consists of three HVDC converter stations, one each in Tajikistan, Afghanistan and Pakistan. The initial capacity of the three converter stations shall be 1300 MW in Tajikistan, 1300MW in Pakistan and 300MW in Afghanistan. The connecting AC systems shall be 500kV, 50Hz in Tajikistan and Pakistan, and 220kV, 50Hz in Afghanistan.

For the operation and maintenance of the transmission line and converter stations a team of trained personnel and an effective organization would be required. The Operation and Maintenance Plan, which is presented in Appendix H, describes the routine and emergency maintenance tasks and inventory management for operating and maintaining the CASA-1000 Interconnection facility, namely the HVDC line linking Tajikistan, Afghanistan and Pakistan, the Converter Stations and the System Control Centre.

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15 CONCLUSIONS AND WAY FORWARD

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15 CONCLUSIONS AND WAY FORWARD

15.1 Conclusions

The recommended project configuration provides flexibility without constraining future options. Given that there are many active stakeholders, agreements need to be in place to facilitate the process of moving forward in an efficient manner. Any delay in the project will have a negative impact on the economic viability.

15.2 Way Forward

One of the greatest challenges will be coming to an agreement on operational and contractual issues. Some of the operational and contractual issues that need to be addressed in subsequent studies include:

• Risk of non payment

There are many examples (for example the Southern African Power Pool) which have shown that contractual and operational agreements can overcome any potential payment problem. The supply of power to Pakistan is independent of Afghanistan’s ability to meet its financial contractual commitments.

• Accounting of energy transfers

• The contractual and operational challenges of the Kyrgyz-Tajikistan load swap arrangements need to be thought through thoroughly to ensure proper accounting of effective transfer of energy. The agreements would have to address such issues as who will be administering the metering, safeguards to ensuring transparency of dispatch and calculation of losses and throughput, and dispute resolution mechanisms.

• These arrangements are contractual in nature and are outside the focus of the current study and would be part of a subsequent study.

• Dispatch services, tariff and transit fees

• Payment for dispatch services, tariff and transit fees with respect to payments will have to be established, for electricity transmitted through OJSC “National Electric Grid of Kyrgyzstan” as well as through the Barki Tajik system.

• This will have to be established at the time of formulating contractual agreements – this is not in the scope of the present study.

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