Strategy for gross national happiness (sgnh) Annexures to the Main Document

3. 
   Generation Cost for Accelerated Hydropower Plants
   
   1. 
      Based on the total investment of Nu. 468 billion spread over the period 2007-2027 for construction of 10,000 MW installed capacity with 37 billion units of annual energy generation capacity and as per the discounted cash flow analysis for the 12 projects lined up for development in the next 20 years, long range marginal cost of generation works out to Nu. 2.20 per unit at 10% discount rate.
      

Table 4.2: Estimated Cost of Generation for Accelerated Power Projects

4. 
   Minimum threshold level for Bhutan’s Hydropower Pricing.
   
   1. 
      Hydropower pricing in Bhutan for export in the past has been more through political goodwill (Chhukha Nu. 2.00) or with negotiation on some form of cost plus basis (Kurichu Nu. 1.75 and Tala Nu. 1.80). The Central Electricity Regulatory Commission (CERC) in India allows cost plus model for the state owned power plants. However, this norm might not be sustainable as it does not provide any incentive for reducing costs and burdens the state utilities with costly PPAs. The trend now is to move towards tariff based IPPs where project developments are awarded to the developers offering the lowest tariffs. Whatever is the existing norm, the bottom line is to maintain a lower tariff than those of the competing projects in the region. A project developer would typically include his cost of equity (14 -16%)³⁰ and commercial interests costs of 8-14%. Since we are looking at encouraging IPPs in the future, the tariff could also be determined through open bidding process or electricity spot market³¹ for the project developers. Therefore, the minimum threshold level will vary depending on the corresponding development model.
      

5. 
   Threshold for Bilateral Projects
   
   1. 
      In the case of bilateral projects, the equity is also a grant from GoI. Therefore, RGoB has no direct financial stake and hence we could argue that the minimum financial return threshold is anything that is over and above meeting the cost of the O&M and debt servicing of the project. We could consider these projects as 100% leveraged and do not factor in the cost of equity at all. On the other hand, we could monetize other associated costs like the environmental, social and opportunity cost of water³². Such subjective factors, however, are points of contention that might prove to be a strategic negotiation blunder. Negotiations are typically guided by our fall back positions on what is our “best alternative to a negotiated agreement” (BATNA)³³. In case of Bhutan, bilateral projects will always result in mutually negotiated arrangements as we cannot expect any better mechanisms. The unique model of current project implementation between the two countries further corroborates this argument.
      
   2. 
      Tariff determination eventually becomes a function of many parameters including the location of the plant, peaking capacity, firm power and distance from the load centre. The important thing for us is to be aware of the various tariff ranges and find the one best suited to both parties. Following are some of the existing generation tariffs in India:
      

Table 4.3: Cost per unit of Power in India (CERC-2006)

		Cost per unit of Power
1	35% of power traded in India in 2006	Rs.2.50 to Rs.3.00
2	33% of power traded in India in 2006	Rs.3.00 to Rs.3.50
3	Cost of old hydro generation (198 MW Baira Suil – 1984)	Rs. 0.71
4	Tariff for Chamera-II (300 MW commissioned in 2004)	Rs. 2.55
5	Tariff for Tehri storage plant (1000 MW -2006)	Rs. 3.50
6	Bid tariff for ultra mega thermal projects, pit head – 4000 MW at Sasan by Lanco (Madhya Pradesh – Jan 2008)	Rs. 1.19
7	Bid tariff for Mundhra (Gujarat) ultra mega project with imported coal (4000 MW) by Tata Power – January 2008	Rs.2.26
8	Tariff for Baspa II, IPP Plant (300 MW)	Rs. 2.79
9	Tariff for Malana Power Plant (100 MW)	Rs. 2.35

6. 
   Tariff and Royalty/Free Power for IPP through Bidding Process
   
   1. 
      For the IPP plants, the trend in India for determining the tariff is through competitive bidding process especially for the thermal plants. Where State purchases power, bidding is based on the lowest tariff offered by the IPP to the State (e.g. tariff of Nu. 1.19 per unit offered by Lanco for the 4,000 MW thermal based Sasan Project)³⁴. For Bhutan, since most of the energy would be exported by the IPP through their own PPA, the bidding could be based on the maximum royalty/free power that the developer(s) would offer to Bhutan. Or it can be a combination of royalty/free power as well as the minimum tariff for those plants from where both export and domestic demand is also met. The CERC (India) norm for free power is 12%. In individual states, they demand upto 18% free power from IPPs. This threshold again would be site specific. Sophisticated IPPs would in turn maximize their returns through a PPA tariff that is determined through a combination of all the above methods including that of “spot trading” in the electricity market. Whatever the method of determining the minimum threshold level, it is strategically crucial for us to be familiar with market developments in India and to make consistent efforts to reduce our project costs to make our pricing competitive.
      

7. 
   Key Issues that still remain as challenges to Bhutan’s power export
   
   1. 
      Resource constraints, especially given the requirement of investments worth Nu. 468 billion would be a huge challenge. Since internal resources will not be adequate to fund even a single project the entire accelerated development model is built around the continuity of the existing GoI assistance in the power sector with opportunities for private sector participation.
      
   2. 
      Power from Bhutan is far from the load centers in Northern and Western region of India. Existing transmission corridor is through the “chicken neck corridor”, a narrow strip of land in West Bengal bordering Bangladesh. The cost of delivered power at these load centers increases substantially to be able to compete with other sources. However, in the future, there might be a possibility that GoI and regional countries could establish a regional grid for exchange of power³⁵. This will eliminate the above bottleneck.
      

Source: (World Bank Report)³⁶

3. 
   The World Bank report claims that Bhutan’s delivery cost increases due to transmission costs, cost of GoI equity and subsidy in some cases. However, compared to some of the IPP projects carried out in India, the Bhutanese projects are still competitive. For instance, the generation cost of BASPA II and Malana I are Rs. 2.79 per unit and Rs. 2.35 per unit respectively.
   
4. 
   Competition as outlined above from North-Eastern region of India (Arunachal Pradesh with potential of 60,000 MW) and Nepal (80,000 MW) also poses a direct challenge and threat to Bhutan’s hydropower development.
   

1. 
   Reduction of Hydropower Costs in Bhutan
   
   1. 
      To ensure cost competitiveness of Bhutanese hydro power in the Indian market, we need to focus on reduction of project costs. Bhutan’s strategy of accelerated hydropower development could achieve this objective through integration of activities, sharing of infrastructure resources, enhancement of manpower skills, achieving economy of scale and through other measures such as:
      

• 
  Transmission corridors, roads and bridges;
  
• 
  Expedited clearances and permit procedures through a special purpose vehicle (SPV);
  
• 
  Lowering price through tax exemption and policy intervention;
  
• 
  Long term vendor negotiations support by RGoB on the investors behalf given the huge demand for the equipment and supplies.
  
• 
  Manufacturing scheduling to be influenced at the earliest before their orders gets backlogged. Earlier the signal, better their planning and supply time.
  

2. 
   Since Bhutan shares very similar topography and hydropower potential with the other competitors like Arunachal and Nepal, the only major advantage that Bhutanese hydro sector will have over the others is our experiences in executing projects on time. This has substantial implications on the project since any project delayed will not only lead to cost escalation but also result in potential revenue losses. This is mainly due to minimized bureaucracy, high priority accorded by the Government towards hydropower development and absence of pressure groups (Civil Society Organizations and environmental groups).
   
3. 
   Bhutan’s transparent society with minimal corruption will lead to further reduction in costs as developers will not be subject to additional costs due to extortion and bribery. Bhutanese society is also less litigious which normally leads to project delays in the other countries.
   

5. 
   The Accelerated Projects (10,000 MW Target)
   
   1. 
      The addition of 10,000 MW of hydropower generation capacity by 2028 has been set for accelerated hydropower development. Even though the sector faces the most daunting challenge of mobilizing huge resources, this ambitious target nevertheless has the following rationale based on earlier plans.
      
   2. 
      The PSMP has suggested the development of seven projects with total installed capacity of about 5,000 MW and investment of about US$ 4.00 billion from 2003-2022. The revised target of 10,000 MW is an increment of another 5,000 MW over and above the power system master plan’s target. This increased target is based on increased time period till 2028 for project development, changing power market scenario (increased demand in India) and also given Bhutan’s urgency to move ahead before competing projects in the region leaves us behind. Moreover, the addition of a single reservoir scheme (Sunkosh) with a capacity of 4,060 MW makes the target highly achievable. The only additions to the earlier project lists are: Sunkosh, Dagachhu, Nikachhu, Amochhu and Rotpashong.
      
   3. 
      Also past experiences indicate that achievements in hydro sector even by India have been always lagging behind their targets due to time, cost over-runs and other challenges. For instance, GoI has been able to add a capacity of only 6,896 MW against their target of 15,750 MW for their 10^th Plan. This indicates that unless we aim at a substantial target, the chances of achieving anything close would be impossible. Therefore, 10,000 MW for Bhutan has to be pursued vigorously to achieve the desired target.
      
   4. 
      With the target of 10,000 MW by 2028, the following projects are being selected from the master plan for implementation. While most projects are selected based on the PSMP ranking list, other projects like Sunkosh are selected for energy security and strategic reasons. The rest are selected for potential IPP investment given their development costs and other infrastructure facilities.
      

Table 5.1 List of the Accelerated Projects

5. 
   Project Profiles
   
   1. 
      Sunkosh Project
      
      1. 
         Sunkosh is the biggest storage scheme designed for multipurpose benefits. In the past it has not been prioritized as it was considered too massive (4,060 MW) and complex with submergence of 62 Km² area within Bhutan. However, this is the right time to develop Sunkosh as it will be crucial for enhancing energy security for Bhutan and perhaps the most attractive project for GoI given its multipurpose benefits. The DPR of the project has already been completed in 1995. The project will also catalyse development of other infrastructure (Lhamoizingkha township) and recreational facilities around the reservoir lake.
         
      2. 
         There is also the possibility of optimizing the design capacity (from 4,060 to 2,060 MW), with the same generating capacity, increasing the project viability. The issues of concern are: environmental and resettlement issues (120 households at Deorali Geog) and transboundary water rights with Bangladesh as the project irrigation scheme plans to divert the water towards Teesta barrage with a 142 km canal (13 km within Bhutan). These aspects shall be reviewed during updating of the DPR cost estimates and environmental impact assessments (EIA) as part of the pre-construction survey report (PCR).
         
      3. 
         The DPR study of the Sunkosh Multi-purpose project was carried out by the Central Water Commission, Government of India, in 1995. The project envisages two stage development with main dam complex sited near Kerabari and the lift dam located near Lhamoizingkha. The powerhouse of the main dam is placed downstream on the left bank of Sunkosh, whereas the powerhouse of the lift dam is located at the toe of the lift dam on right bank. The project has the following salient features:
         
      4. 
         Main Dam Complex : The scheme envisages a 265 m high, 770 m long rockfill dam with gross storage capacity of the reservoir of 6,325 million m³, surface area at full reservoir level (FRL) of about 61.78 km² and reservoir stretch of about 52 km; four numbers 12.5 m finished diameter head-race tunnel of length 560 m to 660 m will convey a total maximum discharge of 520 m³/s; a surface power house operating under a net rated head of about 194 m, and open tailrace channel of about 50 m long. An installed capacity of 4,000 MW (8 x 500 MW) has been proposed, with an annual 90% dependable energy generation of 6542 GWh. The cost of generation for firm energy and total 90% dependable energy is Nu. 1.62 per unit and Nu. 1.38 per unit respectively (1995 price level).
         
      5. 
         Lift Dam Complex: The scheme envisages a composite dam of rockfill and concrete gravity with height of 37.5 m and 62.5 m respectively. The length of the concrete dam is 343 m and rockfill is 1329 m. The gross storage volume at FRL is 144 million m³ and surface area of about 8.21 km² with reservoir stretch of about 13 km. Three number penstock pipes of 4 m diameter and length of 99.50m length each conveying a total design discharge of 60 m³/s; a surface power house operating under a net rated head of about 36.5 m, and open tailrace channel of about 43 m long. An installed capacity of 60 MW (3 x 20 MW) has been proposed, with an annual 90% dependable year energy generation of 376.3 GWh. The cost of generation (90% dependable year) is Nu. 0.86 per unit (1995 price level).
         
      6. 
         The total estimated cost of the project excluding the irrigation system and transmission line cost is Nu. 65,346.51 million (1995 price level) of which Nu. 56,182 million is allocated for power component. The cost of generation for project as a whole for 90% dependable year energy is Nu. 1.36 per unit (1995 price level). A budget of Nu. 30.00 million has been proposed during the 10^th five year plan for pre-construction survey and to update the EIA study report and the project cost. The updated project cost has been taken as Nu. 168.546 billion with escalation over the DPR cost and generation cost of Nu. 3.41 per unit.
         

2. 
   Dagachhu Hydropower Project
   
   1. 
      Dagachhu hydropower project is being prioritized because of the CDM benefits and the unique model of development. The feasibility study is completed (June 2006) and the Government has already accorded the approval to develop the project under the CDM mechanism and commercial financing with domestic equity and soft loans. The CDM benefits to this 114 MW project shall be almost Euro 2.5 million annually at the current certified emission reduction rates (CERs). While the continuity of the Kyoto protocol is in question post 2012, it is expected that the value of the CERs will increase in the near future. This project can in fact be a project dedicated for the environment to further promote Bhutan’s environmental conservation and institute a mechanism of “payment for ecosystem services” within the context of the accelerated hydropower development. Domestic equity participation can be mobilized from environmental funds like the Bhutan Trust Fund (BTF) and the domestic capital markets (liquidity from NPF and Bank of Bhutan) and debt shall be arranged through soft financing from development partners like the Government of Austria (responsible for the feasibility study of the project) and/or Asian Development Bank (ADB), through ordinary capital resource (OCR).
      
   2. 
      The above implementation model will provide a new dimension to the hydropower project development. This new approach will provide the much needed capacity building for the local agencies and players to mobilize resources for hydropower development to carry through financial closures and make deals on cross border power trading and internal project financing. Such experiences will enable Bhutan to expedite its hydropower development and open up an investment opportunity to the Bhutanese capital market which is almost non-existent at present. Most important, such a bold move would reinforce Bhutan’s commitment to environmental conservation while accelerating hydropower development with local efforts and resources through innovative approach and means.
      
   3. 
      Dagachhu is a pure run-of-the-river scheme with no diurnal pondage facility along the course of Dagachhu, which is a tributary stream of Punatsangchhu. The project is located on left bank of Dagachhu with the power house located 10.5 km upstream of the Punatsangchhu confluence. As per the feasibility study report, the scheme envisages a 20.50 m (above river bed) high and 18.20m long diversion weir, 3 surface desilting basin, 7.79 km long head-race tunnel conveying a maximum design discharge of 50.0 m³/s, an underground power house operating under a gross head of about 304 m, and tail-race tunnel of about 679 m long. An installed capacity of 114 MW has been proposed, with an annual average energy generation of 500 GWh. The power shall be evacuated by 19 km 220 kV transmission line from the powerhouse switchyard to the 220 kV substation at Tsirang, which will be connected to the Western grid for onward evacuation to India via Malbase substation at Pasakha. Only 492 GWh mean annual energy is expected to be delivered at Indo-Bhutan border for export.
      
   4. 
      The total estimated cost of the project is US$ 182.40 million (2008 price level, excluding transmission line cost and interest during construction). The accumulated interest during construction would be US$ 37.27 million, thereby bringing the total capital cost of the project to US$ 219.67 million. As per the feasibility report, the generation cost of the project is about Nu. 2.58/kWh. However, as per the simulation done by the Department of Energy considering soft term loan financing and 40:60 debt equity financing mix, the long run levelised cost of delivery works out to Nu. 2.68/kWh. The net return on equity from electricity sales on annual basis varies from 7% in the first year to 10.21% in the 16^th year. The IRR and NPV work out to 10.57% and Euro 3.4 million. Considering 10% as the opportunity cost of capital in the Bhutanese market and with the starting tariff of Nu. 2.25 per unit in 2011, the proposed financing option seems viable. The PTC (India), the buyer of the Dagachhu power has already indicated a starting tariff of Nu. 2.25 per unit. For signing of power purchase agreement (PPA) with PTC, the export tariff will be negotiated with indicated starting tariff of Nu. 2.25 per unit.
      
   5. 
      This project is being promoted as a CDM project using the Indian baseline. Through this mechanism, the Dagachhu power will reduce about 330,000 tons of CO₂ equivalent in India and qualify for certified emission reduction (CER) certificate worth Euro 2.50 million per annum at the current CER rates of Euro 8.00/CER till 2012. The Kommunalkredit Public Consulting (KPC) of Austria has already indicated a price of Euro 8.00/CER.
      
   6. 
      The Austrian Government has committed Euro 300,000 for the preparation of tender documents and tendering aspects of Dagachhu project. The above tendering work is proposed to be contracted out to M/s Bernard Engineers to save time and expedite the project construction. The project development will be done through turnkey (EPC contract) model and is expected to start within 2007.
      

3. 
   Punatsangchhu-I Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme on Punatsangchhu located 8.50 km downstream of Wangdue Bridge. The dam site is located at Lawakha and the powerhouse is sited just downstream of Rurichhu.
      
   2. 
      Consequent upon signing of Memorandum of Understanding (MoU) between the RGoB and the GoI for the preparation of DPR on 15^th September 2003, WAPCOS (India) Ltd. has completed the DPR and submitted the draft DPR in August 2006.
      
   3. 
      As per the draft DPR, the project envisages installed capacity of 1,095 MW (6 x 182.50 MW) with annual average energy generation of 5,377.45 GWh. The project will have 137m high concrete dam, 4 intakes, 4 underground desilting chambers, 7.50 km long (10.3m diameter) headrace tunnel, 2 vertical pressure shaft and an underground powerhouse. The total estimated cost of the project as per the draft DPR is Nu. 49,894.60 million (2006 price level, without including interest during construction).
      
   4. 
      During the 4^th Project Monitoring Committee (PMC) meeting held on 4-5 September 2006 in Thimphu, it was agreed that Nu. 150.0 million will be re-prioritized in the 9^th plan on reimbursable basis for pre-construction activities such as roads and bridges in order to save time. The pre-construction activities will be undertaken by the DoE with WAPCOS as the Consultant. The agreement between DoE and WAPCOS is yet to be signed.
      
   5. 
      The two governments have also exchanged draft agreement with regard to the actual implementation of the project. DoE’s comments/views/suggestions on the draft agreement prepared by GoI for implementation of the project had been forwarded back to GoI. It is hoped that this agreement will be signed within the next few months so as to allow the construction of the project to begin by the end of 2007. The agreement is in partial modification of the Tala model with 60% loan and 40% grant.
      

4. 
   Mangdechhu Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme along the course of the Mangdechhu river, downstream of Trongsa town. As per the feasibility study conducted in 1999 and the updated PSMP, the scheme envisages a 66 m high diversion dam, 12.167 km long headrace tunnel and an underground powerhouse. An installed capacity of about 672 MW has been proposed, with an annual average energy generation of 2,909 GWh. The total estimated cost of the project as per the updated PSMP is US$ 587.7 million (2003 price level).
      
   2. 
      The MoU between the RGoB and the GoI for the preparation of DPR of the project was signed on 25^th January 2005. The implementation agreement has been signed between the DoE and NHPC of India on 29^th September 2006 at a contract price of Nu. 75.90 million + 12.24% Service tax. The 20% mobilization advance for the DPR study has already being released to the Consultant in December 2006 from the RGoB pre-finance. A first release of Nu.27.960 million was received from the GoI for the DPR study on 4^th January 2007. The DPR study will be completed by end of 2008.
      
   3. 
      As per the discussions between the two Governments, the GoI indicated that it would not be possible to undertake further projects on the same financing arrangement as that of Tala HEP. Except for Punatsangchhu I, which will be developed in similar pattern of Tala model (changes in loan and grant), the implementation of Mangdechhu and Punatsangchhu II projects would be taken up through the Joint Venture (JV) route in which the GoI agencies such as NHPC and the RGoB agencies could form the JV companies to develop these projects with debt equity structure of 70:30. In order to save time for construction of the projects, it was also discussed that NHPC would take up development of infrastructure for Mangdechhu.
      

5. 
   Punatsangchhu-II Hydroelectric Project
   
   1. 
      This is a run-of-the-river project located downstream of Punatsangchhu-I. As per the pre-feasibility study conducted in 1993 and updated PSMP, the scheme envisages a 70 m high diversion dam, 11.5 km long head-race tunnel and an underground power house. An installed capacity of 992 MW has been proposed, with an annual average energy generation of 4,667 GWh. The total estimated cost of the project as per the updated PSMP is US$ 875.10 million (2003 price level).
      
   2. 
      The MoU for the preparation of DPR of the project was signed between the RGoB and the GoI on 25^th January 2005. M/s WAPCOS has been selected for the DPR study of Punatsangchhu-II, so as to allow integrated development of the combined transmission network and other common infrastructures of both Punatsangchhu-I and II for economic reasons. The consultancy agreement for DPR study has been signed between the DoE and WAPCOS on 28^th September 2006 at a contract sum of Nu. 92.507 million + 12.24% Service tax. The 20% mobilization advance for the DPR study has already being released to the Consultant in November 2006 from the RGoB pre-finance. A first release of Nu. 26.596 million was received from the GoI for the DPR study on 4^th January 2007. The DPR study will be completed by end of 2008.
      

6. 
   Nikachhu (Tangsibji) Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme along the course of the Nikachhu river, tributary of Mangdechhu. The project is located between Chendebji (3km downstream of the Chunapchhu confluence) and the power house (located at Tangsibji near the Nikachhu/Mangdechhu).
      
   2. 
      As per the updated PSMP, the scheme envisages a 48 m high diversion dam (above foundation), 6.60 km long head-race tunnel conveying a design discharge of 29.30 m³/s, an underground power house operating under a gross head of about 837 m, and tail-race tunnel of about 1.50 km long. An installed capacity of 208 MW has been proposed, with an annual average energy generation of 1,042 GWh.
      
   3. 
      The updating of the 1980s DPR study report of the Tangsibji project (60 MW) is planned to be carried out in the 10^th FYP. The above technical features of the project are based on desktop and reconnaissance level studies.
      

7. 
   Kholongchhu Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme along the course of the Kholongchhu river, tributary of Gongri. The project is located on Kholongchhu from the outlet (in Gongrichhu) just downstream of Duksum to the dam site approximately 6 km along the river upstream from the confluence. The dam site is situated 2 km north of where the road to Khamdang takes-off from Trashigang-Trashi Yangtse road.
      
   2. 
      As per the updated PSMP, the scheme envisages a 51 m high diversion dam (above foundation), 5.90 km long head-race tunnel conveying a design discharge of 151 m³/s, an underground power house operating under a gross head of about 378 m, and tail-race tunnel of about 400 m long. An installed capacity of 486 MW has been proposed, with an annual average energy generation of 2,209 GWh.
      
   3. 
      The pre-feasibility study of the project was carried out by Norconsult of Norway in 1992-93. The preparation of DPR of the project is planned to be carried out in the 10^th FYP.
      

8. 
   Chamkharchhu-I (Digala) Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme along the course of the Chamkharchhu river. The project is located on Chamkharchhu between Khomshar and Digala (from 25km to 8km upstream of the Chamkharchhu/Mangdechhu confluence near Gongphu). The power house is located opposite to Digala village on the right bank of Chamkharchhu.
      
   2. 
      As per the updated PSMP, the scheme envisages a 65 m high diversion dam, 11.80 km long head-race tunnel conveying a design discharge of 148.80 m³/s, an underground power house operating under a gross head of about 527 m, and tail-race tunnel of about 550 m long. An installed capacity of 672 MW has been proposed, with an annual average energy generation of 3,208 GWh.
      
   3. 
      The above features of the project are based on the desktop and reconnaissance level survey and study. The preparation of DPR of the project is planned to be carried out in 10^th FYP. As per the updated PSMP, the project is scheduled for development from 2014 to 2020.
      

9. 
   Chamkharchhu-II (Kheng/Shingkhar) Hydroelectric Project
   
   1. 
      This is a run-of-the-river scheme along the course of the Chamkharchhu river, upstream of Chamkharchhu-I project. The project is located on Chamkharchhu from 8km upstream of Shingkhar to just below Shingkhar school near the suspension bridge across to Raidi village.
      
   2. 
      As per the updated PSMP, the scheme envisages a 50 m high diversion dam, 9.60 km long head-race tunnel conveying a design discharge of 136.20 m³/s, an underground power house operating under a gross head of about 487 m, and tail-race tunnel of about 500 m long. An installed capacity of 570 MW has been proposed, with an annual average energy generation of 2,713 GWh.
      
   3. 
      The above features of the project are based on the desktop and reconnaissance level survey and study. The preparation of DPR of the project is planned to be carried out in 10^th FYP. As per the updated PSMP, the project is scheduled for development from 2018 to 2023.
      

10. 
    Amochhu (El. 815 Yangtsegang) Hydroelectric Project
    
    1. 
       This is a run-of-the-river scheme along the course of the Amochhu river from 1 km upstream of the Ketha Khola confluence to 1 km downstream of the Chushe Khola Confluence.
       
    2. 
       As per the updated PSMP, the scheme envisages a 55 m high diversion dam, 6.60 km long twin head-race tunnel conveying a design discharge of 204 m³/s, an underground power house operating under a gross head of about 288 m, and two tail-race tunnel of about 150 m long each. An installed capacity of 500 MW has been proposed, with an annual average energy generation of 2,210 GWh.
       
    3. 
       The above features of the project are based on the desktop study and no reconnaissance survey and field verification has been carried out. The preparation of pre-feasibility study report of the project is planned to be carried out in 10^th FYP.
       

10. 
    Khomachhu Hydroelectric Project
    
    1. 
       This is a run-of-the-river scheme along the course of the Khomachhu, in Lhuentse Dzongkhag, which is the tributary stream of Kurichhu. The intake is located at about El. 1920 masl.
       
    2. 
       As per the desktop study, the scheme envisages a 40 m high diversion dam, 8 km long head-race tunnel conveying a design discharge of 57.3 m³/s, an underground power house operating under a gross head of about 667 m, and tail-race tunnel of about 700 m long. An installed capacity of 326 MW has been proposed, with an annual average energy generation of 1,507 GWh.
       

10. 
    Rotpashong (El. 720) Hydroelectric Project
    
    1. 
       This is a run-of-the-river scheme along the course of the Kurichhu river, which is located upstream of the existing 60 MW Kurichhu hydroelectric project at Gyalpoizhing.
       
    2. 
       As per the desktop study, the scheme envisages a 55 m high diversion dam, 9.50 km long head-race tunnel conveying a design discharge of 401 m³/s, an underground power house operating under a gross head of about 117 m, and tail-race tunnel of about 450 m long. An installed capacity of 400 MW has been proposed, with an annual average energy generation of 1,883 GWh.
       

5. 
   National Transmission Grid
   

1. 
   For accelerated hydropower development, high voltage transmission lines are crucial for export of power to India and for internal distribution of electricity supply. Project-wise requirement was studied in detail to optimise cost and make the construction of lines environment friendly. Since the load centres are in northern & western India, power from the hydropower projects in the Eastern Bhutan have to be transferred to Siliguri. Considering this aspect, Gelephu is the potential link with India for export of above 3,000 MW from Central & Eastern Bhutan. The possible RoW problem from Tingtibi to Gelephu and with location of International Airport at Gelephu shall be integrated with the overall zoning plans. A minimum RoW requirement of 85 meters for two 400 kV double circuits (1,000 MW) and one 220 kV single circuit (200 MW) is required. In addition, an area of about 10 acres will be required for construction of substation at Gelephu.
   
2. 
   At least a high voltage direct current (HVDC) substation and link is envisaged for export of power from mega projects such as the Sunkosh in future, for which land and RoW shall be provided in Lhamoizingkha Dungkhag. The issue of the ROW for the HVDC link may need to be coordinated with the Indian authorities in West Bengal.
   
3. 
   One option of ensuring corresponding development of transmission network across the border in India commensurate with the accelerated hydropower development plan of Bhutan is to pursue Article 2 of the Umbrella Agreement between the two governments and initiate discussions on export capacity from minimum of 5,000 MW by 2020 to minimum of 10,000 MW by 2028.
   
4. 
   We could also reciprocate the use of Indian transmission network by offering our own transmission network for evacuation of power from some of the sites in Arunachal Pradesh to the load centres in North India. The details of such arrangements are described in Chapter 8 for specific projects like Tawang I (750 MW) and Tawang II (750 MW).
   
5. 
   Transmission networks in Bhutan can be developed by the BPC, the transmission licensee, who already has the institutional capacity to undertake the projects either through self-financing or joint venture with Indian public sector companies like PGCIL and PTC. BPC is currently the utility who owns the transmission network in the country and is also identified as the system coordinator.
   
6. 
   Fair compensation for the RoW required for HV transmission lines is also considered for accelerated hydropower development. Under the draft regulations on RoW transmission line RoW is considered as Easement right and no compensations are being paid.
   
7. 
   Since obtaining the ROW is increasingly becoming difficult³⁷, it is proposed that a regulation on RoWs for power infrastructure be adopted under the proposed National Spatial Act.
   

5. 
   
   Directory: wp-content -> uploads -> 2011
   2011 -> Voices of the Old Sea Norman Lewis
   2011 -> Malevil Robert Merle
   2011 -> The Elephant Keeper’s Children Peter Hoeg
   2011 -> Jv packet •Mars Colonization Affirmative •Mars Colonization Negative
   2011 -> Registration Form (Rev. 8-86) omb no. 1024-0018
   2011 -> All America Looks Up to Virginia;” Virginia and the Declaration of Independence
   2011 -> Rao bulletin
   2011 -> Christopher Columbus was born between 25 August and 31 October 1451 in
   2011 -> The Battle of Frenchtown (1855), Washington Territory: the Political and Demographic Context rev 9/4/11
   2011 -> Seti aff •seti neg •Asteroids Aff
   
   
   
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