CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD) Version 03 - in effect as of: 22 December 2006 CONTENTS

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1 CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD) Version 03 - in effect as of: 22 December 2006 CONTENTS A. General description of the small scale project activity B. Application of a baseline and monitoring methodology C. Duration of the project activity / crediting period D. Environmental impacts E. Stakeholders comments Annexes Annex 1: Contact information on participants in the proposed small scale project activity Annex 2: Information regarding public funding Annex 3: Baseline information Annex 4: Monitoring Information 1

2 Revision history of this document Version Date Description and reason of revision Number January Initial adoption July 2005 I. The Board agreed to revise the CDM SSC PDD to reflect guidance and clarifications provided by the Board since version 01 of this document. II. As a consequence, the guidelines for completing CDM SSC PDD have been revised accordingly to version 2. The latest version can be found at < December 2006 III. The Board agreed to revise the CDM project design document for small-scale activities (CDM-SSC-PDD), taking into account CDM-PDD and CDM-NM. 2

3 SECTION A. General description of small-scale project activity A.1 Title of the small-scale project activity: Title: Branford Mini Hydro Power Project Version: 1.0 Date: 07/09/2010 A.2. Description of the small-scale project activity: The Branford Mini Hydro Power Project (hereinafter, the Project), is a small-scale, run-of-river hydropower plant, located on the Sudu Ganga (River) in the Matale District of Sri Lanka. The Project will have an installed capacity of 2.5 MW and is expected to generate an average of 10,968 MWh of renewable energy per annum. The electricity from the Branford Mini Hydro Power plant will be sold to the national utility grid of Sri Lanka which is operated by the Ceylon Electricity Board (CEB), the monopoly power distributor in Sri Lanka. The generated electricity will be sold to CEB, through a standard small power purchase agreement. This is available to all small scale power producers using Non-Conventional Renewable Energy (NCRE) sources with a power generation capacity up to 10 MW, including mini hydropower. Currently, the marginal thermal power plants connected to the grid operate on fuel oil or diesel and the share of thermal power in Sri Lanka is expected to increase over the next ten years. The small hydropower projects do not figure in the CEB expansion plan, nor are they factored into the annual electricity supply-demand forecasts. Operation of this small hydropower plant will result in a displacement of electricity from the highest marginal cost thermal power stations and will result in an average greenhouse gas (GHG) emission reduction of 7,308 tonnes of CO 2 equivalent per annum. As a renewable energy project, the proposed Project will produce positive environmental and economic benefits, and contribute to local sustainable development mainly through following ways: 1. No relocation is expected as a result of the Project as the entire development occurs within the river reservation. The Project will improve the quality of life for locals living adjacent to the Project site by creating short-term and long-term employment opportunities for the local people during the construction and operation period of the Project. The Environmental Impact Assessment Report (EIAR) identified that approximately 74 people are expected to be employed during construction, and approximately 19 people are expected to be employed during operations. The Project will also contribute to rural infrastructure development by creating safe bathing places for the upstream community. 2. The Project activity will contribute to the Sri Lankan economy by providing electricity to meet increasing energy demands. It will assist the Sri Lankan Government in achieving its commitment to environmentally and economically sustainable development by providing private sector support for renewable energy technologies. On a local level, the flow of financial resources through the investment in the Project will contribute positively towards the local economy in the form of wages for unskilled labour, construction material and local construction equipment. 3

4 3. The Project activity contributes to environmental well being through the displacement of grid electricity generated from fossil fuel-fired power plants and through the reduction of greenhouse gas emissions and other air pollutants. As a small scale run-of-river hydropower project, the Branford Mini Hydro Project has a very low impact on river flow volumes and does not result in the degradation of any natural resources, health standards, etc. at the Project area. A.3. Project participants: Name of Party involved (*) ((host) indicates a host Party) Sri Lanka (host) Private and/or public entity(ies) project participants (*) (as applicable) Branford Hydropower (Pvt.) Ltd. (Project Company) Kindly indicate if the Party involved wishes to be considered as project participant (Yes/No) (*) In accordance with CDM modalities and procedures, at the time of making the CDM-PDD public at the stage of validation, a Party involved may or may not have provided its approval. At the time of requesting registration, the approval by the Party (ies) involved is required. No A.4. Technical description of the small-scale project activity: A.4.1. Location of the small-scale project activity: A Host Party(ies): The Government of Democratic Socialist Republic of Sri Lanka. The Government has established its Designated National Authority, which is now registered with the CDM Executive Board. The DNA contact point is Mr. Sarath Wickramasinghe, Additional Secretary, Ministry of Environment and Natural resources ( Tel: ; airmac@sltnet.lk). A Region/State/Province etc.: Central Province, Matale District. A City/Town/Community etc: Divisional Secretariat: Matale & Raththota Urban & Local Authority: Matale Municipal Council & Rathtota Pradeshiya Sabha Grama Niladari Division: Kaludewala & Viharagama. 4

5 A Details of physical location, including information allowing the unique identification of this small-scale project activity : The Branford Mini Hydro Power Project is located in the Matale District of Sri Lanka, The geographical coordinates of the Project are: N, E. Figure A-1: District Map of Sri Lanka 5

6 Figure A-2: Location of the Branford Mini Hydro Power Project (Location Map 1:50,000) 6

7 A.4.2. Type and category(ies) and technology/measure of the small-scale project activity: According to Appendix B of the simplified modalities and procedures for small-scale CDM project activities the type and category of the proposed project activity as follows: Methodology: AMS I.D. (Version 16). Main Category: Type I Renewable Energy Projects. Sub Category: D Grid connected renewable electricity generation. Application of environmentally sound technology The Project involves the installation of a run-of-river hydropower plant that relies on commercially available, environmentally safe and sound technology. Hydroelectric energy is considered as clean and environmentally friendly because it does not contribute to greenhouse gas emissions. Technical details of the Project activity The proposed Project is a run-of-river type hydropower project with a total installed capacity of 2.5 MW. The Project is expected to generate 10,968 MWh of energy per annum. The hydropower station includes the construction of a weir, power house, switchyard, transmission line, tailrace and access road. Based on the feasibility study conducted for the Project 1, the details are as follows: (i) Weir Designed weir height is 5.5 meters, and the length is approximately 37.7 meters. The weir is a gravity type masonry construction with a concrete cell which is able to withstand a 100 year flood event and to discharge a maximum of 500 m 3 /sec. The co-ordinates of the proposed weir site are: N; E. (ii) Inundation area The inundation area will be along the river bank as the slopes are steep and high for a reasonable distance. It is expected that a 900 meter length along the bed will be inundated due to the pool. (iii) Regulation pond The pond area is approximately 6 ha (0.06 km 2 ) and the volume would be around 0.1 MCM. As the power plant operation would be on the run of the river basis, there will not be any room for water to stagnate. (iv) Forebay tank There is no forebay tank arrangement as the power house is on the left end of the weir, directly feeding from the pond. (v) Penstocks There are no penstocks. Concrete intake arrangement is provided. (vi) Tailrace channel The river bed downstream of the power house will be improved, which will serve as a tailrace channel. The channel will be excavated to reach the lowest river bed level. This facility will utilize the maximum 1 Branford Small Scale Hydropower Project Feasibility Study, February

8 available head in the terrain. The tail race channel will be about 5 meter deep at the power house end and rises gradually to reach the river bed level. The length of the tail race is approximately 30m. (vii) Powerhouse The powerhouse will be located at the left end of the weir considering the site profile and in order to avoid additional conveyance systems to feed the turbines. The roof of the powerhouse will be 18.5 meters high above river bed level. The outer wall of the powerhouse will be raised above the design flood level and will be abutted to the existing natural ground level. (viii) Switchyard It is proposed to construct the switchyard on the left bank of the river at an elevation well above the maximum flood level. It will be located close to the power house. (ix) Power grid and transmission line routes A 33kV three-phase transmission line belonging to the CEB runs close to the proposed construction site. A three phase 33kV transmission line of length approximately 250 m will be constructed from the proposed power station to the nearest tower as indicated in the CEB Grid Connection Proposal, to connect to the existing 33 kv line. (x) Generators and transformers The generator is of the salient pole or cylindrical rotor type and sustains all efforts induced by the turbine, including runaway speed. A suitable gear mechanism will be used to couple the alternator to the turbine to match with specific speed. (xi) Turbines The Project will utilise 2 units of Kaplan / Tubular type turbines. The rated flow rate will be 55.4 m 3 /s and the plant factor is 53 % 2. A summary of the main design features and characteristics of the Project are listed in Table A -1 below. Table A-1: Key technology parameters to be employed for the proposed Project Key Technology Parameter 3 Value Units 2 Type Kaplan / Tubular Turbine Turbine Capacity (each) 1250 kw Rated flow rate 55.4 m 3 /s Rated water head 5.5 m Units 2 Generator Generator Capacity 1600 kva Rated voltage 415 V Weir Height 5.5 m Length 37 m App. Step-up Transformer Quantity 2 nos Rated Capacity 1750 kva, 415V/33kV Interconnection Line Transmission line 33 kv 2 Branford Small Scale Hydropower Project Feasibility Study, February 2008, Section 7, p Branford Small Scale Hydropower Project Feasibility Study, February 2008, Section 9. 8

9 Length 250 m Technology Transfer There will be no new technology transfer involved in the Project, as Sri Lanka has the capacity to design and implement hydropower projects. A.4.3 Estimated amount of emission reductions over the chosen crediting period: The Project activity is expected to generate an estimated annual emission reduction of 7,308 tco 2 e and a total reduction of 51,157 tco 2 e during the first crediting period of the Project (17/05/ /05/2018). Years Estimation of annual emission reductions in tonnes of CO 2 e May December , , , , , , ,308 January April ,436 Total estimated reductions (tonnes of CO 2 e) 51,157 Total number of crediting years 7 years Annual average of the estimated reductions over crediting period 7,308 (tco 2 e) A.4.4. Public funding of the small-scale project activity: No Annex I Party public funding is directly involved in the proposed Project. A.4.5. Confirmation that the small-scale project activity is not a debundled component of a large scale project activity: As per the criteria mentioned in Appendix C of the simplified modalities and procedures for small-scale CDM project activities, the Branford Mini Hydro Power Project is not a debundled component of a large scale project activity. The project participant has not registered nor applied for registration for any other small-scale CDM project in the same category and technology / measure whose project boundary is within 1 km of this Project activity. 9

10 SECTION B. Application of a baseline and monitoring methodology B.1. Title and reference of the approved baseline and monitoring methodology applied to the small-scale project activity: Version 16 of AMS I.D. (Renewable Energy Projects: Grid connected renewable electricity generation). Version 5.2 of the tool for the demonstration and assessment of additionality. Version 02 of the tool to calculate the emission factor for an electricity system. B.2 Justification of the choice of the project category: The applicability conditions for AMS.I.D (Version 16) includes the following: 1. This category comprises renewable energy generation units, such as photovoltaic, hydro, tidal/wave, wind, geothermal and renewable biomass that supply electricity to a national or a regional grid. 2. This methodology is applicable to project activities that (a) install a new power plant at a site where there was no renewable energy power plant operating prior to the implementation of the project activity (Greenfield plant). 3. The project activity results in new reservoirs and the power density of the power plant, as per definitions given in the Project Emissions section, is greater than 4 W / m The capacity of the entire unit (generators) does not exceed 15 MW. The Project comprises of renewable energy generation units (i.e. hydropower) that supply electricity to the Ceylon Electricity Board (CEB) distribution system which is composed mainly of fossil fuel fired generating units. The Project involves the installation of a new power plant at a site where there was previously no renewable energy power plant in operation. The Project has a total installed capacity of 2.5 MW, which is less than the maximum eligibility limit of 15 MW for a small-scale CDM project activity. The surface area of the reservoir is 0.06 km 2 and the power density is W / m 2 which is greater than the methodology threshold of 4 W/m². This corresponds precisely with the approved small scale methodology AMS 1.D (Version 16) therefore, the methodology AMS-I.D. is applicable to the Project. B.3. Description of the project boundary: The Project boundary, as defined in Appendix B of the simplified modalities and procedures for smallscale CDM project activities, encompasses the physical and geographical site of the hydropower plant itself. The Project boundary for the baseline will include the national electricity grid of Sri Lanka. The Project boundary is shown in Figure B-1 below. As per the guidance and rules for small-scale project activities, the emissions related to production, transport and distribution of fuel used for power plants within the baseline boundary are not included in 10

11 the baseline calculations. For the same reason the emissions related to transport are also excluded from the Project boundary. Project Boundary Figure B-1: Diagram of the Project Boundary B.4. Description of baseline and its development: The Project activity is installation of a new grid-connected renewable power plant/unit. According to AMS.I.D (version 16), the baseline scenario is the electricity delivered to the grid by the project activity that otherwise would have been generated by the operation of grid-connected power plants and by the addition of new generation sources. Two alternative scenarios to the Project activity are identified and considered: 1. Implementation of the Project activity without considering the CDM benefit; and 2. Continued operation of the existing thermal power plants in the system and the addition of new generation sources to meet increased electricity demand. From the above, alternative a) faces barriers which are discussed further in section B.5. Alternative b) the continued operation of the existing mainly fossil fuel based power plants in the CEB grid and the addition of new generation sources to meet increased electricity demand, is the most probable alternative scenario. Therefore alternative b) is identified as the baseline scenario of the Project. 11

12 Baseline Calculations According to AMS.I.D (Version 16), the baseline emissions are the product of electrical energy baseline EGBL, y expressed in MWh of electricity produced by the renewable generating unit multiplied by the grid emission factor (measured in t CO 2 e / MWh) and calculated in a transparent and conservative manner. Baseline emissions calculations are based on AMS I.D. (Version 16) and Tool to calculate the emission factor for an electricity system (Version 02). The Project adopts method (a) - the Combined Margin, to calculate the baseline emission factor of the grid. The Simple Operating Margin (OM) has been calculated EX-ANTE for grid power plants, using the data vintages for years y, as the full generation-weighted average for the most recent 3 years for which data are available at the time of PDD submission. According to the availability of data at the time of PDD submission, Simple Operating Margin has been calculated using Option A1: Based on data on the net electricity generation and a CO 2 emission factor of each power unit. The Build Margin (BM) has been calculated EX-ANTE based on Option 1: Most recent information available on units already built for sample group m at the time of PDD submission. Explanations and formulae are given in Section B.6.1, and detailed calculations in Annex 3. B.5. Description of how the anthropogenic emissions of GHG by sources are reduced below those that would have occurred in the absence of the registered small-scale CDM project activity: Additionality In accordance with Paragraph 28 of the simplified modalities and procedures for small-scale CDM project activities, a simplified baseline and monitoring methodology may be used for a small-scale CDM project activity if project participants are able to demonstrate to a Designated Operational Entity that the project activity would otherwise not be implemented due to the existence of one or more barrier(s) listed in Attachment A to Appendix B: a) investment barrier, b) technological barrier, c) barrier due to prevailing practice, d) other barriers. Analysis of the Project activity for additionality is based on EB 39, Annex 10, Tool for the demonstration and assessment of additionality (Version 05.2). The Branford Mini Hydro Power Project faces barriers elaborated in the following paragraphs and hence would not have been implemented in the absence of CDM revenue. Investment Analysis The purpose of the investment analysis is to determine whether the proposed Project is not: the most economically or financially attractive; or not economically or financially feasible without the sale of CERs. Three analysis methods are available to conduct the investment analysis: simple cost analysis; investment comparison analysis; and the benchmark analysis. Since the Project generates income from electricity sales, the benchmark analysis has been selected to justify the investment and the Equity Internal Rate of Return (IRR) of investment (excluding that which is financed by debt) is identified as the financial indicator. Since Branford Hydropower (Pvt.) Ltd. is the sole project developer in this Project, the internal company benchmark (expected return on equity) was applied which is also used for similar projects with similar risks in the same sector in Sri Lanka (Table B-1). 12

13 Table B-1: Similar Hydropower Projects in Sri Lanka Name of the project Benchmark used Palmerston Small Hydropower Project (0.8MW) 25% Upper Neluwa Small Hydropower Project (3MW) 30% Somerset Small Hydropower Project (1.1 MW) 25% Kadawala Phase 1 Small Hydropower Project 25% (5.2MW) As per the Additionality Tool (version 5.2), the benchmark was derived from the government bond rate, and increased by a sutiable risk premium to reflect private investment and project type. Based on the monthly bulletin published by the Central Bank of Sri Lanka in January , treasury bonds of more than 3 years would have a yield rate of 20% 5. As the yield rate does not take into account the risk premium, a conservative investor risk premium of 5% (in line with industry standards), was incorporated into the benchmark. When considering all the above factors, the Project participant (Branford Hydropower (Pvt.) Ltd.) Board of Directos and investors have resolved, that the benchmark equity IRR for the Project (including the risk premium) is 25% 6. In accordance with the benchmark analysis, if the financial indicators of the proposed Project, such as the Equity IRR, are lower than the benchmark, the proposed Project is not considered to be financially or economically attractive. The basic parameters for the calculation of financial indicators for the Project are shown in Table B-2. Table B-2: Parameters used for the calculation of financial indicators Parameters Unit Value Installed capacity MW 2.5 Financial calculation period Years 20 Project Lifetime (technical) Years 20 Crediting period Years 7 Capital Investment Million Rs Annual electricity generation MWh/y 10,968 Electricity tariff (average) Rs/kWh Operational cost (average) Million Rs/year 1.26 Royalty % 13.1 Benchmark Equity IRR % 25 Depreciation % 5.0 Years of depreciation Years 20 4 Central Bank of Sri Lanka. Bulletin January 2009, pg where yield rate is defined as the average of bid and offer rates 6 An extract of a Board Resolution from the Aitken Spence Plc Board of Directors, dated 16 th March

14 Based on the above data, the Equity IRR of the Project is 22.3%. Table B-3 below shows the Equity IRR with and without the income from the sale of CERs. Without the revenue from carbon credits the Equity IRR of the Project is 22.3%, which is lower than the minimum amount required from the investor and thus the Project is not economically attractive. However, taking into account the CDM revenues, the Project Equity IRR is 26.6% which is higher than the benchmark applied to this Project. Therefore the CDM revenues will enable the Project to overcome the investment barrier. Table B-3: Project Equity IRR with and without CERs Project Equity IRR without Benchmark Project Equity IRR with CERs CERs 22.28% 25% 26.60% Sensitivity Analysis The objective of sensitivity analysis is to show whether the conclusion regarding the financial attractiveness is robust to reasonable variations in the critical assumptions. The following key parameters have been selected as sensitivity indicators to test the financial attractiveness for the proposed Project: 1) Capital investment; 2) Annual operation and maintenance (O&M) costs; 3) Electricity tariff; and 4) Annual electricity output. The results of the sensitivity analysis are shown in Table B-4 and Figure B-2 below, with the assumption that the above factors fluctuate within the range of -10% to +10%. 14

15 CDM Executive Board Table B-4: Sensitivity Analysis of the Proposed Project on Equity IRR Key Parameters -10% -5% 0% 5% 10% Capital investment 24.26% 23.22% 22.28% 21.39% 20.58% Annual O&M costs 22.31% 22.29% 22.28% 22.25% 22.23% Electricity tariff 15.96% 19.02% 22.28% 25.70% 29.32% Annual electricity output 15.96% 19.02% 22.28% 25.70% 29.32% Sensitivity Analysis 30.00% 28.00% 26.00% 24.00% IRR 22.00% 20.00% 18.00% 16.00% 14.00% -15% -10% -5% 0% 5% 10% 15% Variation Range Capital Investment Electricity Tariff O&M Cost Electricity Output Figure B-2: Sensitivity Analysis of the Proposed Project on Equity IRR The Equity IRR of the proposed Project varies to different degrees in accordance with the fluctuation of the four parameters within the range of negative 10% to positive 10%. Figure B-2 shows that electricity tariff and annual electricity output display the same trends when varying the associated parameters by ±10% (the trend lines are on top of one another). They are also the most senstive factors as their IRRs vary greatly within the variation range. In comparison, capital investment and annual operational and maintenance cost are relatively more insensitive factors (with capital investment being the more sensitive). Based on Table B-4 and Figure B-2, Equity IRR of the Project exceeds the benchmark IRR of 25% under the following favourable conditions: 1. Electricity tariff increased by 5% and 10%; or 2. Annual electricity output increased by 5% and 10%. However, despite the high IRRs, the surrounding economic situation that has resulted in such conditions must also be considered. For example, when electricity tariff increases by 5 10%, it is likely due to a 15

16 significant increase in inflation in the country which leads to higher interest rates. This has been clearly witnessed in the past 10 years in Sri Lanka. Higher interest costs means that the benchmark return increases and therefore the IRR for the Project will always be lower than the benchmark at that time. Similarly with the annual electricity output, to have it increased by 5 10% would mean expansion of capacity through plant upgrades or the like, which would imply additional invetment cost that must be incorporated to the financial considerations. Therefore, the results show that under the current condition, without the revenue from CERs the Project cannot be expected to be economically feasible. Barrier Analysis Energy demand in Sri Lanka has been growing at an average rate of about 6.3% per annum 7 in the past 10 years ( ), a trend that is expected to accelerate over the next decade. Further exploitation of large hydropower resources is becoming increasingly difficult due to the social and / or environmental impacts associated with large-scale developments. Such constraints have increased the country s dependence on thermal power 8, which increased from 21% in 1990 to 60% in The Ceylon Electricity Board (CEB) is the government-owned monopoly power utility that prepares and manages the implementation of the country s long-term power generation expansion plan. To meet the rapid growth in energy demand, the CEB expansion plan forecasts the addition of 4,180 MW in installed capacity between 2005 and The generation expansion plan takes into consideration contributions from existing and committed power facilities, and identifies additional capacity needs to meet future energy demand at the least possible generation cost. The CEB base case expansion plan focuses on growth in thermal power, and specifically includes only 150 MW of hydropower additions (between 2010 and 2014) and 4,030 MW of thermal power additions in the next 15 years 3. The potential for small scale hydropower to access the marketplace in Sri Lanka is restricted by the fact that CEB controls access and the terms for power production. The CEB is the major owner and operator of most power plants in Sri Lanka and is responsible for issuance of power production licenses. All power generation licenses specify that output must be sold to the CEB. Over the past years, the CEB has increasingly turned towards commissioning power plants on build, operate, own and transfer (BOOT) contracts with private operators. Note that all BOOT contracts have been for the construction of thermal power plant facilities. The CEB nevertheless maintains control of the process of identifying and licensing these new facilities. This highlights the dominating role of the CEB in setting the specific market and policy conditions for sector expansion. Given the tremendous growth in electricity demand, the CEB has instituted a number of policies and practices that strongly favour investments in thermal generation combined with only one new investment in large-scale, publicly-managed hydropower facilities. The analysis of these barriers demonstrates that small hydropower investments like the Branford Project is additional to the national baseline which is clearly oriented in favour of large-scale thermal investments combined with a limited number of large-scale, publicly managed hydropower investments. 7 CEB Long Term Generation Expansion Plan , December Aesieap Gold Book. 9 CEB, Statistical Digest

17 Early CDM Consideration The Project proponent was aware of CDM prior to the construction of the Branford Mini Hydro Power plant and the benefits of CDM were a decisive factor in the decision to go ahead with the Project. The main events related to the consideration of CDM in the decision to proceed with the Project activity are illustrated in the table below. The respective documentation has been provided to the DOE during the validation process as evidence of CDM consideration. Table B-5: Overview of key events in the development of the Project Date Key Event Evidence 13 th December 2006 Intention to design and commence the Letter of intent Project February 2008 Preliminary financial feasibility study conducted (the results indicated that the project was not attractive due to the low IRR) 27 th June 2008 Sri Lanka Sustainable Energy Authority (SEA) has granted Provisional Approval to the Project 25 th September 2008 Environmental Impact Assessment Report (EIAR) of the Branford Mini Hydro Power Project on Sudu Ganga Income and cash flow statement (with and without CDM incentives) Provisional Approval from SEA Environmental Impact Assessment Report 23 rd December 2008 Dialogue established with a CDM consultant CDM proposal 24 th February 2009 Project EIAR approved by the Mahaweli Authority of Sri Lanka 13 th March 2009 CDM consultant engaged Contract for CDM services 16 th March 2009 Decision to go ahead with the CDM Project. Environmental Approval from Mahaweli Authority of Sri Lanka Extract of a Board Resolution from the Aitken Spence PLC Board of Directors 24 th June 2009 Pre-host country approval received by the Sri Lanka DNA PIN and Pre-host country approval letter 19 th October 2009 Equipment purchase (turbines and generators) Contract Agreement with Guglar Water Turbines GMBH 9 th June 2009 Power Purchase Agreement Standard Power Purchase completed Agreement with the CEB. 15 th October 2009 Construction start date Awarding letter to Civil Contractor 17 th May 2011 Commissioning date Project Schedule (Annex 5) The above events clearly demonstrate that the Project proponent was aware of the potential benefits of CDM before the start of the Project activity and that it played a crucial role in overcoming the barriers towards implementation of the proposed activity. Impact of CDM registration Without the incentives from CDM, the above barriers would prevail and the Project would not go ahead due to the low IRR. In contrast, CDM registration will enhance the viability of the Project and ensure that 17

18 GHG emissions are reduced below the baseline through the displacement of fossil fuel based power with the generation of renewable electricity B.6. Emission reductions: B.6.1. Explanation of methodological choices: Emission reductions from the proposed Project can be calculated based on the version 16 of AMS.I.D (Renewable Energy Projects: Grid connected renewable electricity generation) and version 02 of the tool to calculate the emission factor for an electricity system. Baseline The Project activity is the installation of a new grid-connected renewable power plant, therefore the baseline scenario is the electricity delivered to the grid by the Project activity that otherwise would have been generated by the operation of grid-connected power plants and by the addition of new generation sources. Baseline emissions The baseline emissions are the product of electrical energy baseline EGBL, y expressed in MWh of electricity produced by the renewable generating unit multiplied by the grid emission factor. Emission Factor The Emission Factor can be calculated in a transparent and conservative manner as follows: a) A combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) according to the procedures prescribed in the Tool to calculate the Emission Factor for an electricity system. OR b) The weighted average emissions (in t CO2/MWh) of the current generation mix. The data of the year in which project generation occurs must be used. As the data of weighted average emissions of the current generation mix (b) is not available in Sri Lanka, the Project has adopted method (a) to calculate the baseline emission coefficient. 1) Calculation of Combined margin CO 2 emission factor, EF grid,cm,y Calculations for the Combined Margin are based on data from official and publicly available sources. Power plant capacity additions registered as CDM project activities were excluded from all calculations. 18

19 Table B-6: Parameters used in the combined margin CO 2 emission factor calculations Parameter SI unit Description EF grid,cm,y tco 2 /MWh Combined margin CO 2 emission factor for the project electricity system in year y EF grid,bm,y tco 2 /MWh Build margin CO 2 emission factor for the project electricity system in year y EF grid,om,y tco 2 /MWh Operating margin CO 2 emission factor for the project electricity system in year y The following seven steps are applied to calculate the emission factor for an electricity system: STEP 1. Identify the relevant electricity systems. STEP 2. Choose whether to include off-grid power plants in the project electricity system (optional). STEP 3. Select a method to determine the operating margin (OM). STEP 4. Calculate the operating margin emission factor according to the selected method. STEP 5. Identify the group of power units to be included in the build margin (BM). STEP 6. Calculate the build margin emission factor. STEP 7. Calculate the combined margin (CM) emissions factor. Step1: Identify the relevant electricity system. The Project boundary for the baseline will include the national electricity grid of Sri Lanka. The Project boundary is shown in Figure B-1 (above). Step 2: Choose whether to include off-grid power plants in the project electricity system (optional). The baseline emission factor for the Sri Lankan national electricity grid system was calculated for grid power plants only (not including off-grid power plants). Step 3: Select a method to determine the operating margin (OM). The calculation of the operating margin emission factor (EF grid,om,y) is based on one of the following methods: (a) Simple OM; or (b) Simple adjusted OM; or (c) Dispatch data analysis OM; or (d) Average OM. To calculate the Operating Margin emission factor, the Dispatch Data analysis (method c) couldn t be used in this case as the hourly dispatch data were not available in Sri Lanka. The data of load curves are not publicly available in Sri Lanka. Therefore, the Simple Adjusted OM (method b) cannot be used for the proposed Project. The low-cost must run resources constitute less than 50% of the total grid generation in the CEB Grid. The percentage of the low-cost must run resources are: 43.5% in 2003, 37% in 2004, 39% in 2005, 49% in 2006 and 41% in 2007 (see Table B-6 below), which accords with the defined condition of method (a), 19

20 CDM Executive Board but not method (d). Thus method a), the Simple OM can be used to calculate the Operating Margin emission factor. Table B-6: CEB Grid electricity generation over the five most recent years ( ) Generation (GWh) Total Total Low-cost/Must-run power plants - CEB (Hydro & Wind), PPP Hydro-small*) Thermal power plants - CEB, Hired & PPP) Total Generation % of Low cost/must-run 43.53% 36.85% 39.40% 49.40% 40.25% 41.99% * with Waste Heat, Solar, Biomass and Dendro Power Plants SPP Small Power Producers IPP Independent Power Producers Source: CEB Statistical Digest Step 4: Calculate the operating margin emission factor according to the selected method. The Simple OM emission factor is calculated as the generation-weighted average CO 2 emissions per unit net electricity generation (tco 2 /MWh) of all generating power plants serving the system, not including low-operating cost and must-run power plants. It can be calculated EX-ANTE, using the data vintage based on the most recent 3 years for which data is available at the time of PDD submission, and EF OM is fixed during the crediting period. According to the availability of data, the Simple OM can be calculated using Option A based on the data for net electricity generation and delivered to the grid, fuel types and fuel consumption of each power plant / unit. As per the Tool to calculate the emission factor for an electricity system (Version 02) for the Simple OM, the following equations were used to calculate the operating margin for each year. Option A: Calculation based on the net electricity generation and a CO 2 emission factor according to the selected method Under this option, the simple OM emission factor is calculated based on the net electricity generation of each power unit and an emission factor for each power unit, as follows: 20

21 Determination of EF EL,m,y The emission factor of each power unit m should be determined as follows: Option A1. If for a power unit m data on fuel consumption and electricity generation is available, the emission factor (EF EL,m,y ) should be determined as follows: Based on these data, the Simple OM Emission Factor (EF grid,om simple,y ) is calculated as tco 2 e / MWh (see Annex 3 for details). Detailed calculations can be found in Section B.6.3 and Annex 3. 21

22 Step 5: Identify the group of power units to be included in the build margin (BM). The BM emissions factor is the generation-weighted average emission factor (tco 2 /MWh) of all power units m during the most recent year y for which power generation data is available. The sample group of power units m used to calculate the BM consists of either: (a) The set of five power units that have been built most recently, or (b) The set of power capacity additions in the electricity system that comprise 20% of the system generation (in MWh) and that have been built most recently. Project participants should use from these two options the sample group that comprises the larger annual generation. Power plant capacity additions registered as CDM project activities should be excluded from the sample group m. If 20% falls on part capacity of a plant, that plant is included in the calculation. The capacity addition of the five most recent plants has been calculated and compared to 20% of the annual total generation for Table B-8 : Selection of Sample group for Build Margin Energy (GWh) Total Generation to CEB grid in % of the system generation in Generation of the five most recent plants As shown in Table B-7, the capacity addition of the most recent five plants is lower than 20% of the annual total generation in Therefore the sample group was selected as the most recent power plants contributing up to 20% of the annual total generation (Annex 3). From the sample group, the Build Margin has been calculated EX-ANTE based on option 1: Most recent information available on plants already built at the time of PDD submission. Step 6: Calculate the build margin emission factor. According to the tool to calculate the emission factor for an electricity system, Build Margin emission factor for year 2007 is calculated using the following equation: 22

23 CO 2 emission factor for each power unit m (EF EL,m,y ) was determined using the same method as in Operating Margin (Option A1, based on the data for fuel consumption and electricity generation of each power plant / unit) The Build Margin emission factor (EF grid, BM,y ) is calculated as tco e / MWh (see Annex 3 for 2 details). Step 7: Calculate the combined margin (CM) emissions factor. The Combined Margin emission factor (EF grid, CM,y ) is calculated using the following equation: w OM = 0.5 by default w BM = 0.5 by default The weights applied to the OM and BM are fixed at 0.5, therefore in order to calculate the CM we apply these to the Simple OM and BM as calculated above. The calculations have drawn upon publicly available information. The Combined Margin emission factor (EF grid, CM,y ) is tco 2 / MWh (see Annex 3 for details). 2) Calculation of Baseline Emissions, BE y The Baseline emissions are calculated as 7,308 tco 2 / yr (see Annex 3 for details). 23

24 3) Calculation of Project emissions According to ACM0002 (version 10) the power density of the Project activity (PD) is calculated as: The Project has a total installed capacity of 2.5 MW, which is less than the maximum eligibility limit of 15 MW for a small-scale CDM project activity. The surface area of the reservoir is 0.06km 2 and the power density is W / m 2 which is greater than the methodology threshold of 4 W/m². 4) Calculation of emission reductions Emission reductions are calculated according to the following formula: The Project does not involve project emissions or leakage. Therefore, project emission reductions are equal to baseline emissions. Using the results of the preceding sections, we can calculate the emission reductions. The emissions reductions are calculated as 7,308 tco 2 e / year (see Annex 3 for details). 24

25 B.6.2. Data and parameters that are available at validation: Data / Parameter: Installed capacity of the Project activity Data unit: MW Description: Installed capacity of Project activity Source of data used: Value applied: 2.5 Justification of the choice of data or description of measurement methods and procedures actually applied : Any comment: Data / Parameter: EG P, y Data unit: MWh/year Description: Average net electricity exported to the grid by the Project activity. Source of data used: Monthly invoice produced by the CEB. Value applied: 10,968 Justification of the choice of This data is required to estimate the baseline emissions. The electricity data or description of exported by the Project activity is recorded jointly by the CEB and measurement methods and representative of the Project proponents. The monthly invoice is procedures actually applied : prepared based on the jointly certified reading. Meters would be calibrated as per CEB standards by the CEB. Any comment: EG m,y Data / Parameter: Data unit: MWh Description: Net quantity of electricity generated and delivered to the CEB grid by power unit m in year y Source of data used: Ceylon Electricity Board (2005, 2006, 2007). Sales and Generation Data Book. Value applied: See Annex 3. Justification of the choice of Due to the lack of publicly available official data from , data or description of most recent information available ( ) was used in the measurement methods and calculations. procedures actually applied : Any comment: Official Data EF CO2,m,i,y Data / Parameter: Data unit: tco 2 /GJ Description: The CO 2 emission factor of fuel type i used in power unit m in year y Source of data used: 2006 IPCC Guidelines for National Greenhouse Gas Inventories Volume 2: Energy, Table 2.2. Value applied: See Annex 3. Justification of the choice of IPCC default value. data or description of 25

26 measurement methods and procedures actually applied : Any comment: Data / Parameter: Data unit: Description: Source of data used: IPCC value. FC i,m,y Million litres Amount of fossil fuel type i consumed by power unit/ power plant m belong to Ceylon Electricity Board (CEB) in year y Ceylon Electricity Board (2005, 2006, 2007). Sales and Generation Data Book. Value applied: See Annex 3. Justification of the choice of Due to the lack of publicly available official data from , data or description of the most recent information available ( ) was used in the measurement methods and calculations. Fuel consumption in each power plant is measured by procedures actually applied : CEB using fuel flow meters and recorded by power plant staff once every shift (8 hours), and the annual total fuel consumption data is published by CEB in the Sales and Generation Data Book. Any comment: Fuel consumption data of CEB is subject to audit both internally and externally before published. Data / Parameter: Data unit: Description: Source of data used: FC i,m,y Million litres Amount of fossil fuel type i consumed by power unit/ power plant m belong to Independent power producers (IPPs) in year y Sri Lanka Sustainable Energy Authority SEA (2005, 2006, 2007). Sri Lanka Energy Balance: An Analysis of Energy Sector Performance, Value applied: See Annex 3. Justification of the choice of Due to the lack of publicly available official data from , data or description of the most recent information available ( ) was used in the measurement methods and calculations. procedures actually applied : SEA requests fuel consumption data from IPPs annually. Any comment: All IPPs signed a Power Purchase Agreement with CEB, which states the fuel consumption per kilowatt-hour for different operating regimes. Payments by CEB to IPPs are based on fuel price and energy meter readings. Data / Parameter: NCV Data unit: GJ / litre Description: Net calorific value (energy content) of fossil fuel type i in year y Source of data used: Sustainable Energy Authority Sri Lanka Energy Balance: An analysis of energy sector performance, Sri Lanka Value applied: See Annex 3 Justification of the choice of Data published by Sri Lanka Sustainable Energy Authority data or description of measurement methods and procedures actually applied : 26

27 Any comment: - B.6.3 Ex-ante calculation of emission reductions: Estimated Baseline Emissions The annual baseline emissions are the product of the baseline emissions factor and the electricity delivered to CEB grid by the proposed Project activity. The annual electricity delivered by the Project is estimated as 10,968 MWh/year. The baseline emission factor is estimated to be tco 2 /MWh. Therefore, the baseline emissions are: BE y = EG y * EF y BE y = 10,968 (MWh / year) * (tco 2 e /MWh) = 7,308 tco 2 e/year Detailed calculations can be found in Annex 3. Project emissions The Project emissions (PEy) are 0 t CO 2 e/yr. Leakage According to AMS I.D leakage is also considered zero for this Project activity (Ly = 0 t CO 2 e/yr). Estimated Emission Reductions The emission reductions of the proposed Project activity are: ER y = BE y - PE y ER y = 7,308 0 (tco 2 e/year) ER y = 7,308 tco 2 e/year Detailed calculations can be found in Annex 3. 27

28 B.6.4 Summary of the ex-ante estimation of emission reductions: The crediting period will start from May CDM registration is expected in December The estimated ex-ante emission reductions of the Project activity from are given in Table B-9. Table B-9: Summary of Emission Reductions Year Estimation of baseline emissions (tco 2 e) Estimation of project activity emissions (tco 2 e) Estimation of leakage (tco 2 e) Estimation of overall emission reductions (tco 2 e) May Dec , , , , , , , , , , , , , ,308 Jan April , ,436 Total tonnes of CO 2 e 51,157 51,157 B.7 Application of a monitoring methodology and description of the monitoring plan: B.7.1 Data and parameters monitored: Data / Parameter: Data unit: Description: Source of data to be used: Value of data Description of measurement methods and procedures to be applied: QA/QC procedures to be applied: Any comment: EG Y kwh Net electricity exported to the grid. Monthly invoice. Value of data would be used to calculate the baseline emissions. Measured in the CEB energy meter (revenue meter) at the Project boundary. The electricity exported is recorded by the CEB and jointly certified by CEB and Branford Hydropower (Pvt.) Ltd. The data would be archived electronically and manually for the entire crediting period and two years thereafter. The meter is calibrated as per CEB standards. 28

29 Data / Parameter: Data unit: Description: Source of data to be used: Value of data Description of measurement methods and procedures to be applied: QA/QC procedures to be applied: Any comment: Data / Parameter: Data unit: Description: Source of data to be used: Value of data applied for the purpose of calculating expected emission reductions in section B.5 Description of measurement methods and procedures to be applied: QA/QC procedures to be applied: Any comment: EG gross MWh Gross electricity generated by the Project activity. Generation meter in the powerhouse. Electricity generated will be continuously monitored and hourly measurements will be taken. Measured in the generation meter at the powerhouse. The data would be archived electronically and manually for the entire crediting period and two years thereafter. Meters would be calibrated as per manufacturer standards. Cap PJ W Installed capacity of the hydro power plant after the implementation of the project activity. Project site 2.5 MW Installed capacity is determined based on recognised standards. The installed capacity will be monitored annually. Publicly available national / international standards will be used. AMS.I.D version 16 refers to latest version of ACM0002 for monitoring of parameters for hydropower projects (in this case ACM0002 version 10 is used). Data / Parameter: A PJ Data unit: km 2 Description: Surface area of the reservoir, measured at Full Supply Level after the implementation of the Project activity. Source of data to be 0.06 km 2 used: 29

30 CDM Executive Board Value of data applied for the purpose of calculating expected emission reductions in section B.5 Description of measurement methods and procedures to be applied: QA/QC procedures to be applied: Any comment: The area of the reservoir would be measured from topological surveys, maps, satellite pictures, etc. The area of the reservoir will be monitored annually. AMS.I.D version 16 refers to latest version of ACM0002 for monitoring of parameters for hydropower projects (in this case ACM0002 version 10 is used). Data / Parameter: Data unit: Description: Source of data to be used: Measurement procedures (if any) Monitoring frequency QA/QC procedures to be applied: Any comment: EF grid, CM,y tco 2 /MWh Combined margin CO 2 emission factor for grid connected power generation in year y calculated using the latest version of the Tool to calculate the emission factor for an electricity system As per the Tool to calculate the emission factor for an electricity system As per the Tool to calculate the emission factor for an electricity system As per the Tool to calculate the emission factor for an electricity system As per the Tool to calculate the emission factor for an electricity system B.7.2 Description of the monitoring plan: This section details the steps taken to monitor the GHG emissions reductions from the Branford Mini Hydro Power plant on a regular basis. The Monitoring Plan for this Project has been developed to ensure that from its inception, the Project is well organized in terms of the collection and archiving of complete and reliable data. The Monitoring Plan prepared for this Project is based on the following approved CDM methodologies: Version 16 of AMS.I.D (Grid connected renewable electricity generation); and Version 02 of the tool to calculate the emission factor for an electricity system. 30

31 The Monitoring Plan covers all the activities within the Project boundary and outlines the proposed GHG data management, control and reporting systems, e.g. instructions, procedures, record keeping systems, assumptions, technical equations, models and other means that support complete, accurate and conservative CER estimates. The Monitoring Plan consists of the following sections: 1. Project Management / Monitoring organization The organisation of the CDM monitoring team will be established prior to the start of the crediting period. Clear roles and responsibilities will be assigned to all staff involved in the CDM project and the Plant Manager is nominated as the CDM Manager. The organisational structure of the CDM team is shown in Figure B-3. Figure B-3: Structure of the CDM monitoring team The Plant Manager supervises the overall operation of the plant and as the CDM Manager he will also have the overall responsibility of the CDM monitoring system. In the event of a trained member of the monitoring staff being absent from duties, the integrity of the monitoring system will be maintained by other trained staff. The CDM Manager will communicate with the General Manager and provide annual monitoring reports. 2. Recording of results The process of data collection will start on the date the Project commences its operations. The data measurement procedures, Quality Assurance and Quality Control procedures, person(s) responsible and frequency of monitoring are detailed as follows 100% of the data is monitored at the site by means of accurately calibrated instruments and authentic procedures dedicated for the intended purposes. The net electricity delivered to the grid will measured by the CEB revenue meter (primary meter) located at the CEB metering point at the end of Project boundary. When taking electricity meter readings a detailed account of the main meter, specific uncertainty levels and associated accuracy level of measurement instruments will be recorded. This will be measured monthly and jointly certified by CEB and Branford Hydropower (Pvt.) Ltd. 31

32 Data (gross electricity) from the generation meter at the powerhouse will be monitored continuously and recorded automatically. This information will be printed out. In addition to the automatic system Operator will manually record information in a log. Monthly, all the electricity generation data will be incorporated into an electronic master sheet which would act as the electricity generation data archive. An auxiliary meter (back-up meter) will also be installed in the powerhouse in case of main generation meter failure. Data collection on the back-up meter will follow the same procedures as data collection on the generation meter outlined above. The installed capacity of the Project and the surface area of the reservoir after the implementation of the Project activity will be monitored annually to monitor the power density of the Project. 3. Data records management procedure. All information such as data records, maps and drawings, Environmental Impact Assessment Report (EIAR) and Feasibility Study reports will be kept as records and made available to the verification party. A documentation system (document register) will be developed to manage all the CDM documents and access all the records easily. The CDM manager has the overall responsibility for document maintenance and review. On a monthly basis, the CDM Manager will review all Project data, document registers and manage the data collection, storage and archiving of all relevant data records. The CDM Manager is responsible for preparing the annual CDM Monitoring Report. 4. Data Archiving At the end of each month, all manually entered monitoring data will be filed electronically (e.g. spread sheets) with paper or CD files as backup. The Project owner will keep all invoices and records and these will be archived both electronically and manually for the entire crediting period and two years thereafter. 5. Maintenance Procedures All equipment will be inspected regularly for functionality, integrity and corrosion. Equipment will be maintained in accordance with manufacturer s instructions. Any defective components or materials shall be reported and replacements obtained and fitted within one day, if there is a possibility of total failure, or otherwise within one week. The CDM Manager shall retain all maintenance documents and a Maintenance Register will be implemented. The main operations and maintenance of the Project includes the gate operations, silt removal, peripheral management and up keep of the Project area. 6. Training Procedures The CDM Manager will manage the process of training new staff, and will ensure that trained staff performs their monitoring duties. Capacity building activities and training will be provided by the Project proponent at the beginning of the Project construction and at the start of the operation to all Project related employees. The training program will be delivered by external CDM specialists, equipment suppliers. A Training Register will be implemented to keep track of all employee training and competence. 7. QA / QC a. Calibration Procedures All measurement equipment (fixed and portable) will be calibrated in accordance with CEB standards. A calibration record will be kept for every instrument irrespective of its frequency of usage and whether or not the equipment is an operational or spare unit. A Calibration Register will be maintained to keep track 32

33 of all calibration records for the Project. The CDM Manager is responsible for organising the calibration and keeping all the calibration records. b. Internal audit procedure Internal audits will undertake to ensure all procedures are being adhered to and to confirm compliance with CDM rules and quality management. The internal audit will carry out annually and no more than two months before each verification event. The CDM Manager is responsible for ensuring that the internal audits take place. 8. Error Handling, Corrective and Preventative Actions Procedure a. Failure of monitoring equipment In an event of main electricity meter failure, a backup meter shall be used in its place. If the backup meter fails, it will be replaced by an accredited equipment-testing organisation. b. Error handling, corrective and preventative procedure The CDM Manager will be notified of any errors found during internal audits. Specialists will be appointed to review the implications of the error and the proposed correction procedures. In case of emergency, the Project entity will not claim emission reductions due to the Project activity for the duration of the emergency. A procedure will be developed to outline the responsibility and authority for handling and investigating non-conformance, taking action to mitigate any impacts caused and for initiating and completing corrective and preventive action. All non-conformances and special events will be recorded in a register. This register will be maintained by the CDM Manager and reviewed at the end of each crediting year. 9. Other The Environmental Monitoring Program for the Project will also be carried out in accordance to the mitigation measures proposed in the environmental management plan (see Annex 4 for further information). At any stage the Project developer is bound to carry out the instructions issued by Mahaweli Authority of Sri Lanka (MASL), Ceylon Electricity Board (CEB), Central Environmental Authority (CEA) or any other party including the villagers, to maintain the Project areas and its reservations to accepted ecological standards. B.8 Date of completion of the application of the baseline and monitoring methodology and the name of the responsible person(s)/entity(ies) Date of completing the final draft of this baseline section 06/08/2010 Name of person / entity determining the baseline: Name: Earth Systems (Pvt) Ltd Address: Suite 17, High St Kew Victoria Australia azain.raban@earthsystems.com.au Tel: +61 (0) Fax: +61 (0) Name: Neo Energie (Pvt) Ltd 33

34 Address: 21 Boteju Road Colombo 5, Sri Lanka Tel: +94 (11) Fax: +94 (11) Please note that neither the persons named nor Earth Systems / Neo Energie are a project participant in this Project. 34

35 SECTION C. Duration of the project activity / crediting period C.1 Duration of the project activity: C.1.1. Starting date of the project activity: 19/10/2009 (date of equipment purchase). C.1.2. Expected operational lifetime of the project activity: 20 years 0 months. C.2 Choice of the crediting period and related information: The project activity will use a renewable crediting period as detailed in C.2.1. C.2.1. Renewable crediting period C Starting date of the first crediting period: 17/05/2011. C Length of the first crediting period: 7 years 0 months. C.2.2. Fixed crediting period: C Starting date: Not applicable C Length: Not applicable 35

36 SECTION D. Environmental impacts D.1. If required by the host Party, documentation on the analysis of the environmental impacts of the project activity: Environmental Impacts The Central Environment Authority (CEA) of Sri Lanka requires a detailed Environmental Impact Assessment Report (EIAR) for projects such as the Branford Mini Hydro Power Project. A specific approval from Mahaweli Authority of Sri Lanka (MASL) is required when using any waterways or reserves coming under the jurisdiction of Mahaweli Authority of Sri Lanka 10. The Project is located on the Sudu Ganga, a tributary of Mahaweli Ganga. As a result, the Project has to obtain environmental clearance from both MASL and CEA. The MASL with the concurrence of the CEA has granted approval for the Project Environmental Impact Assessment Report on 24 th February A comprehensive Environmental Impact Assessment Report (EIAR) was carried out to ascertain the environmental impacts caused by the Project activity. The EIAR identified no significant negative environmental impacts from implementation of the Project. The impacts on various parameters were taken into consideration and are summarised below. Water quality and water use Whilst there will be some flow changes, the Project is not expected to have a significant impact on water quality. Periodic water quality testing will be undertaken and a downstream mitigation flow of 0.5 m 3 /s will be provided to ensure that an uninterrupted flow of water will be maintained to support a healthy aquatic environment and for the down stream users. The Project will not impact agricultural water users and impacts on domestic water use (bathing and washing) will be mitigated through the creation of safe bathing places. The inundation pond area is expected to extend up to 900 meters. As the banks of Sudu Ganga are steep and high, the entire pond will remain within the banks and there will be no inundation of any land area beyond the banks and Sudu Ganga reservation. As the proposed Project is a run of river type, there will be fewer impacts on inundation and water stagnation. The Project has been designed to discharge 100 year return flood of 690m 3 /sec, by spilling over the weir. Sedimentation and erosion With the exception of the tailrace area, no increased downstream erosion is expected as a result of construction. The power house discharge will be properly released into the river to minimise bank erosion and river bed scouring. Erodable areas will be protected through the placement of boulders and tress will be planted to stablise the river bank where necessary. During the Project construction phase the Project proponent will take into consideration the geological conditions, erosion control and energy dissipation, and the safety of structures under high flood conditions. 10 CEB, Guidelines on Private Sector Participation in Small Hydro Power Development 36

37 Biodiversity Most of the plants and animals species recorded in the area are common to the region and not unique to the proposed Project location. To compensate for the removal of selected trees due to construction activities and to enhance local biodiversity, a community based tree planting programme will be carried out along the banks of the river as well as in other identified areas. Conclusion The impact of the Project on the environment is expected to be minimal. No relocation of villagers is required as the Project is located within the river reservation. Minimal impact is expected due to the loss of top soil and erosion caused by clearing and construction work. Impacts from the generation of solid waste, the effects of vibration and noise, the temporary displacement of certain animals and the removal of certain tree species is also expected to be low. Other impacts due to the proposed Project such as the stability of the weir and related structures, effects due to ponding and impact on those who use Sudu Ganga water for domestic purposes have also been studied in detail and are able to be effectively mitigated. An overall Environmental Monitoring Program has been proposed to for implementation during the construction and operation of the Project. D.2. If environmental impacts are considered significant by the project participants or the host Party, please provide conclusions and all references to support documentation of an environmental impact assessment undertaken in accordance with the procedures as required by the host Party: There are no significant adverse impacts associated with the Project activity as described above. The Project has received the approval from the Mahaweli Authority of Sri Lanka with the concurrence of the Central Environmental Authority Sri Lanka on 24 th February

38 SECTION E. Stakeholders comments E.1. Brief description how comments by local stakeholders have been invited and compiled: From the beginning of the Project a permanent dialogue was held with the sectors directly involved in the Project. The Project received the provisional approval from Sri Lanka Sustainable Energy Authority on 26th June Matale Pradeshiya Sabha (Provincial Council) approval was received on 12 th May 2008 and Matale Divisional Secretariat approval was received on 7 th December Simultaneously the Project received the Rattota Pradeshiya Sabha approval (25 th March 2008) and Rattota Divisional Secretariat approval (9 th May 2008). The Mahaweli Authority of Sri Lanka approved the Project Environmental Impact Assessment Report on 24 th February The stakeholder consultation was held in Kaludawala village11 at the Jegadambal Kovil Community Hall in Matale (Gangabada Road, Off Raththota Road, Matale, Sri Lanka) at 5.30 pm on the 9th July About 49 people attended the meeting and some of the key participants were: the Assistant Vice President of the Project company, the Project engineer, the Gramasevaka (government appointed village chief), a World Bank representative from DFCC Bank (social safeguard specialist), CDM consultants and the village community (See Annex 5 for the attendance list). Personal invitations were sent to the Gramasevaka and the representative from World Bank. Public notices of the planned consultation meeting were posted in several public places in the Kaludawala village in all community languages (Sinhala and Tamil). The presentation was conducted by the Project engineer (on behalf of the Project owner) who outlined the planned Project activity in a non-technical manner and in community languages. The meeting agenda is shown below: 11 Project location 38

39 5:15pm 5:30pm 5:30pm 5:45pm 5:45pm 6:15pm 6:15pm - 7:15pm 7:15pm 7:20pm Religious observation at the village Hindu temple Welcome address by the Assistant Vice President of the Project Company Project introduction - by the Project Engineer Agenda included: Introduction to the project and the holding company Explanation of hydro power and its uses including electricity generation Highlighting environmental benefits of the project (i.e. reduced atmospheric pollution compared to other fossil fuel power generating technologies) Benefits of hydropower to Sri Lanka (i.e. reducing governments dependence on foreign oil imports) Disadvantages of projects that use different technologies (i.e. thermal and diesel powered projects) Benefits to the community: Direct and indirect employment opportunities Direct and indirect income sources Questions & Answers: Vote of thanks by the Assistant Vice President and welcomed any further questions or clarifications and shared the contact details of necessary Project representatives. Each issue in the presentation was discussed in detail, including questions raised by the stakeholders throughout the presentation. Figure E-1: Pictures of the local stakeholder consultation meeting carried out for the Branford Mini Hydro Power Project 39

40 E.2. Summary of the comments received: The following questions were raised during the meeting: 1. Will the water level rise up to the boundary markings placed by the Project proponent in various places which is feet (around m) from the river level? 2. During the rainy season normally there is an increase in water level. What will happen once the Project is built? Will there be any impacts to the houses due to flooding? 3. Since the dam will go across the river, could the villagers use it as a bridge to commute to the other side of the river? 4. What are the other community benefits associated with the Project? 5. What are the Project proponent s actions towards the road damages that occur during the construction phase? 6. During the construction phase, large numbers of Project related heavy vehicles that drive through village roads. The increased use of village roads by the Project vehicles will increase the risk of road accidents. The risk of road accidents along the Project transport route is likely to be exacerbated by the close proximity to the villages and high prevalence of children on the road. What steps are being taken (or are planned) to avoid road accidents near the villages? 7. Does the Project proponent have plans to acquire more land for the Project? 8. Is there an increase in the risk of landslides by implementing this Project? 9. What are the actions taken by the Project proponent to eliminate soil erosion? 10. What is the timeline for the Project? E.3. Report on how due account was taken of any comments received: For each comment received the Project proponent assured the following: 1. Will the water level rise up to the boundary markings placed by the Project proponent in various places which is feet (approximately m) from the river level? The markings were made as demarcation of the land area that belongs to the Branford Project and has no connection to the water level. Once the Project is built, the water level will only rise to a maximum of 3 feet (at around 0.9m upstream of the proposed weir location) from the current level. 2. During the rainy season normally there is an increase in water level. What will happen once the Project is built? Will there be any impacts to the houses due to flooding? There is no additional risk of flooding due to the dam. The dam will capture only the amount of water required for the process. Any excess water will be released through the overflow. The risk of flooding is the same as if there was no dam installed. 3. Since the dam will go across the river, could the villagers use it as a bridge to commute to the other side of the river? It is possible, but not advisable. However, the Project proponent is considering the possibility of constructing a new bridge that could be used by the community. 40

41 4. What are the other community benefits associated with the Project? In addition to the direct employment opportunities and indirect income generating opportunities created by the Project, there would be an allocation of funds for community social and welfare activities. 5. What are the Project proponent s actions towards the road damages that occur during the construction phase? Funds have been allocated to maintain the roads during the construction period and once the Project is completed. 6. What steps are being taken (or planned) to avoid road accidents near the villages? The Project proponent has already given and will further strengthen the procedures given to contractors and vehicle operators regarding road safety while driving through villages. 7. Does the Project proponent have plans to acquire more land for the Project? The river area belongs to the Mahaweli reservation. The land adjoining the river area which is about 2.5 acres (0.01km 2 ) was bought by the Project proponent for the Project. There are no further requirements to purchase land from this community. 8. Is there an increase in the risk of landslides by implementing this Project? A detailed geological study conducted for the Project area by some of the leading geologists in Sri Lanka have indicated that there is no danger of landslides from this Project. 9. What are the actions taken by the Project proponent to eliminate soil erosion? A tree planting scheme around the dam area has been planned to minimise soil erosion caused by the Project. 10. What is the timeline for the Project? The Project construction will start in September

42 Annex 1 CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY Organization: Branford Hydropower (Pvt.) Ltd. Street/P.O.Box: Level 8, 315, Vauxhall street Building: Aitken Spence Tower II City: Colombo 2 State/Region: Postfix/ZIP: Country: Sri Lanka Telephone: FAX: URL: Represented by: Title: Managing Director Salutation: Mr. Last Name: de Mel Middle Name: First Name: Devan Department: Mobile: Direct FAX: Direct tel: Personal 42

43 Annex 2 INFORMATION REGARDING PUBLIC FUNDING Not Applicable 43

44 CDM Executive Board Annex 3 BASELINE INFORMATION 1) Calculation of Simple Operating Margin CO 2 emission factor, EF grid,om,y A. Calculation of the Simple Operating Margin of thermal power plants connected to the grid in 2005 Table A.1: Calculation of the Simple Operating Margin of thermal power plants connected to the grid in 2005 Fuel Specific Date Fuel Electricity Fuel CO Commissioned Type Generation Comsumption 2 Emission Factor Power Plants Net Calorific value Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh Litres tco2/gj GJ/litre Formula (a) (b) ( c) (d) b x c x d Source & Calc CEB - Thermal 1 Kelanitissa Gas turbine (old) Diesel 20,793 11,839, , Kelanitissa Gas turbine (new) 1997 Diesel 275,510 94,249, , Kelanitissa power station (Combined Cycle power Plant 1) 2002 Diesel 333,717 74,595, , Naptha 660, ,620, , Sapugaskanda Diesel 1984 Diesel 3,283 1,638, , Residual Fuel 314,328 75,073, , Sapugaskanda Diesel Extention Diesel 2,985 1,091, , Residual Sapugaskanda Diesel Extention Fuel 505, ,643, , IPP - Thermal 2 Lakdhanavi (Diesel) Nov-1997 Fuel Oil 151,082 38,250, , Residual Asia Power Ltd (Diesel) Jun-1998 Fuel 353,692 81,350, , Colombo Power / Barge Mounted Jul-2000 Fuel Oil 475, ,170, , ACE Power Matara Mar-2002 Fuel Oil 163,308 36,780, , ACE Power Horana Dec-2002 Fuel Oil 174, ,

45 CDM Executive Board Power Plants Date Commissioned Fuel Type Electricity Generation Fuel Comsumption Fuel Specific CO 2 Emission Factor Net Calorific value Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh Litres tco2/gj GJ/litre Formula (a) (b) ( c) (d) b x c x d Source & Calc AES Kelanitissa (Combined Cycle) Oct-2003 Diesel 475, , Heladhanavi (Diesel) Oct-2004 Fuel Oil 758, , ACE Power Embilipitiya (Diesel) Mar-2005 Fuel Oil 488, , TOTAL ,157,254 3,512, Sources: 1. Ceylon Electricity Board (CEB), Sales and Generation Data Book Sri Lanka Sustainable Energy Authority Sri Lanka Energy Balance 2005: An analysis of energy sector performance IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, Table 2.2 (pg 2.16). OM Emission Factor B. Calculation of the Simple Operating Margin of thermal power plant connected to the grid in 2006 Table A.2: Calculation of the Simple Operating Margin of thermal power plants connected to the grid in 2006 Fuel Specific Date Fuel Electricity Fuel CO Commissioned Type Generation Comsumption 2 Emission Factor Power Plants 45 Net Calorific value Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh million litre tco 2 /GJ GJ/unit Formula (a) (b) ( c) (d) b x c x d Source & Calc CEB - Thermal 1 Kelanitissa Gas turbine (old) Diesel 4,431 3,036, , Kelanitissa Gas turbine (new) 1997 Diesel 65,030 22,897, , Kelanitissa power station (Combined Cycle power Plant 1) 2002 Diesel 369,193 88,975, ,

46 CDM Executive Board Power Plants Date Commissioned Fuel Type Electricity Generation Fuel Comsumption Fuel Specific CO 2 Emission Factor Net Calorific value Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh million litre tco 2 /GJ GJ/unit Formula (a) (b) ( c) (d) b x c x d Source & Calc Naptha 340,622 91,187, , Sapugaskanda Diesel 1984 Diesel 5,189 1,855, , Residual Fuel 331,418 79,055, , Sapugaskanda Diesel Extention Diesel 4,022 1,255, , Sapugaskanda Diesel Extention Residual Fuel 491, ,070, , IPP Thermal 2 Lakdhanavi (Diesel) Nov-1997 Fuel Oil 103,688 25,970, , Asia Power Ltd (Diesel) Jun-1998 Residual Fuel 334,203 76,750, , Colombo Power / Barge Mounted Jul-2000 Fuel Oil 452, ,110, , ACE Power Matara Mar-2002 Fuel Oil 129,824 29,080, , ACE Power Horana Dec-2002 Fuel Oil 131,778 29,010, , AES Kelanitissa (Combined Cycle) Oct-2003 Diesel 619, ,410, , Heladhanavi (Diesel) Oct-2004 Fuel Oil 619, ,300, , ACE Power Embilipitiya (Diesel) Mar-2005 Fuel Oil 593, ,310, , TOTAL ,595,148 3,211, OM Emission Factor Sources: 1. Ceylon Electricity Board (CEB), Sales and Generation Data Book Sri Lanka Sustainable Energy Authority Sri Lanka Energy Balance 2006: An analysis of energy sector performance IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, Table 2.2 (pg 2.16). C. Calculation of the Simple Operating Margin of thermal power plant connected to the grid in

47 CDM Executive Board TableA.3: Calculation of the Simple Operating Margin of thermal power plants connected to the grid in 2007 Fuel Specific Date Fuel Electricity Fuel CO Commissioned Type Generation Comsumption 2 Emission Factor Power Plants 47 Net Calorific value Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh million litre tco 2 /GJ GJ/unit Formula (a) (b) ( c) (d) Source & Calc CEB - Thermal 1 Kelanitissa Gas turbine (old) Diesel 46,308 23,742, , Kelanitissa Gas turbine (new) 1997 Diesel 218,792 73,268, , Kelanitissa power station (Combined Cycle power Plant 1) 2002 Diesel 550, ,351, , Naptha 517, ,586, , Sapugaskanda Diesel 1984 Diesel 4,752 2,033, , Residual Fuel 399,966 95,308, , Sapugaskanda Diesel Extention Diesel 3,224 1,110, , Sapugaskanda Diesel Extention Residual Fuel 526, ,800, , IPP Thermal 2 Lakdhanavi (Diesel) Nov-1997 Fuel Oil 118,422 29,140, , Asia Power Ltd (Diesel) Jun-1998 Residual Fuel 361,725 83,120, , Colombo Power / Barge Mounted Jul-2000 Fuel Oil 456, ,000, , ACE Power Matara Mar-2002 Fuel Oil 147,708 33,240, , ACE Power Horana Dec-2002 Fuel Oil 142,412 31,250, , AES Kelanitissa (Combined Cycle) Oct-2003 Diesel 786, ,400, , Heladhanavi (Diesel) Oct-2004 Fuel Oil 747, ,640, , ACE Power Embilipitiya (Diesel) Mar-2005 Fuel Oil 663, ,220, , TOTAL 2007 (f) 5,692,264 3,964, OM Emission Factor Sources: 1. Ceylon Electricity Board (CEB), Sales and Generation Data Book Sri Lanka Sustainable Energy Authority Sri Lanka Energy Balance 2007: An analysis of energy sector performance.

48 CDM Executive Board IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, Table 2.2 (pg 2.16). D. Calculation of the full generation weighted average Simple Operating Margin for the most recent 3 years Table A.4: Calculation of the full generation weighted average Simple Operating Margin for the most recent 3 years Symbol Unit Average ( ) Operating Margin EF OM,y tco 2 /MWh emission factor Total Generation f MWh 5,157,254 4,595,148 5,692,264 5,148,222 2) Calculate the Build Margin (EF BM,y ) A. Selection of Sample group Table A.5: Selection of Sample group for Build Margin Energy (GWh) Total Generation to CEB grid in % of the system generation in Generation of the five most recent plants Selection of samples: 20% of the system generation is more than the generation addition from the five power plants that have been built most recently. Therefore, the sample group m will be considered as the power plant capacity additions in the electricity system that comprise 20% of the system generation and that have been most recently, excluding the plant registered as CDM project activities B. Calculation of the Build Margin emission factor 48

49 CDM Executive Board Table A.6: Calculation of the Build Margin emission factor based on the most recent plants contributing to 20% of the system generation Power Plants Symbol Date Commissioned Fuel Type Electricity Generation in 2007 Fuel Comsumption 49 Fuel Specific CO 2 Emission Factor Net Calorific Value EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh litres tco 2 /GJ GJ/litre Formula (a) (b) ( c) (d) Source 1 & Calc AES Kelanitissa* Oct Diesel 786, ,400, ,434 Heladhanavi Oct Fuel Oil 747, ,640, ,239 Karawila Ganga Hydro 2366 None Brunswick Hydro 347 None Sithagala Hydro 2130 None Way Ganga Hydro None Alupola Hydro CDM Project Rathganga Hydro 9613 None Waranagala Hydro None Nakkawita Hydro 27 None Walakada Hydro None Nianwita Oya Hydro 2048 None Atabage Oya Hydro 7222 None Batalagala Hydro 109 None Battaramulla (Solar power) Solar 0 None Walapane (Dendro) Biomass 139 None ACE Power Embilipitiya Mar Fuel Oil 663, ,220, ,050 Hemingford Hydro 436 None Kotapola Hydro 1,436 None Wee Oya Hydro 14,137 None Radella Hydro 500 None Kumburuteniwela Hydro 4,187 None Asupini Ella Hydro 7,013 None

50 CDM Executive Board Date Commissioned Fuel Type Electricity Generation in 2007 Fuel Comsumption Fuel Specific CO 2 Emission Factor Net Calorific Value Power Plants Symbol EG m,y FC i,m,y EF CO 2 i,y NCV i.y EF EL,m,y Unit year MWh litres tco 2 /GJ GJ/litre Formula (a) (b) ( c) (d) Source 1 & Calc Kalupahana Hydro 1,871 None Upper Korawaka Hydro 4,832 None Badalgama (biomass) Biomass CDM Project Delta Estate Hydro CDM Project Hulu Ganga Hydro CDM Project Gomala Oya Hydro 3,058 None Gurugoda Oya Hydro 5,091 None Coolbawan Hydro 2,733 None Henfold Hydro 7,180 None Dunsinane Hydro 8,768 None Nilambe Oya Hydro 911 None Kolapathana Hydro 2,126 None Guruluwana Hydro 6,743 None Kuda Oya Hydro 4,114 None Labuwewa Hydro 5,203 None Forest Hill Hydro 469 None Batatota Hydro 8,204 None Kehelgamu Oya Hydro 8,193 None Kotankanda Hydro 500 None Lower Neluwa Hydro 2 None Total generation in ,389,820 1,530,723 BM Emission Factor *As 20% falls on part capacity of the AES Kelanitissa combine cycle power plant, it has also been included in the calculation. Source: 1. Ceylon Electricity Board (CEB) Long Term Generation Expansion Plan , November 2004; CEB Energy Data Source, 2006; and ECF data for Energy Balance, Ceylon Electricity Board (CEB), 2007, 2006, 2005, 2004, Sales and Generation Data Book. 50

51 CDM Executive Board 3. Ceylon Electricity Board (CEB), Sales and Generation Data Book IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2, Table 2.2 (pg 2.16). 5. Sri Lanka Sustainable Energy Authority Sri Lanka Energy Balance 2007: An analysis of energy sector performance. 3) Calculation of the Combine Margin Emission factor as the weighted average of the Operating Margin emission factor and the Build Margin emission factor Table A.7: Calculation of the Combined Margin Emission Factor Symbol Unit Source Value Operating Margin Emission Factor EF grid,om tco 2 /MWh Calculated Weighting of OM emission factor W OM % default Build Margin Emission Factor EF grid,bm tco 2 /MWh Calculated Weighting of BM emission factor W BM % default Combined Margin Emission Factor EF grid,cm tco 2 /MWh