Jomini Environmental – SAEMS – Wey Ganga GHG Project Report
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ISO 14064 Part 2 Greenhouse Gas Reduction Project Report
South Asia Energy Management Systems (SAEMS)
Wey Ganga Small-Scale Hydropower Project
Prepared in accordance with ISO 14064 Guidelines Using CDM-SSC-PDD Version 3 and CDM Small Scale Methodology, AMS I.D. Version 14 - Grid Connected Renewable Electricity Generation
Prepared by:
Jomini Environmental Inc.
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SAEMS Wey Ganga Hydropower Project PROJECT DESIGN DOCUMENT FORM (CDM-SSC-PDD) - Version 03
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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
Annex 5: First Verification Period Data
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Revision history of this document
Version Date Description and reason of revision Number 01 21 January Initial adoption 2003 02 8 July 2005 • The Board agreed to revise the CDM SSC PDD to reflect guidance and clarifications provided by the Board since version 01 of this document. • As a consequence, the guidelines for completing CDM SSC PDD have been revised accordingly to version 2. The latest version can be found at
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SECTION A. General description of small-scale project activity
A.1 Title of the small-scale project activity:
Wey Ganga Small-Scale Hydropower Project.
A.2. Description of the small-scale project activity:
This Project Design Document (“PDD”) presents a small-scale, run-of-river hydropower plant in Sri Lanka. The plant started operation in Jun 2004, has a capacity of 8.7 MW and has an estimated output of 22 GWh/yr. The electricity from each of the hydropower plants will be sold to the monopoly government- owned utility in Sri Lanka, the Ceylon Electricity Board (“CEB”), through a standard power purchase agreement (“PPA”) available to all renewable energy based power generators under 10 MW, including small hydropower. The CEB pays producers of renewable energy an amount (adjusted annually) based on short run avoided energy costs of operating thermal power stations. The payment is based on actual electricity generated by the small hydropower facilities and does not include a capacity charge. Currently, the marginal thermal power plants operate on fuel oil or diesel and the share of thermal power in Sri Lanka is expected to increase dramatically over the next ten years. The small hydropower project does not figure in the CEB expansion plan, nor is it factored into the annual electricity supply-demand forecasts. Operation of the small hydropower plant will result in a displacement of electricity from the highest marginal cost thermal power stations.
Applying the simplified methodologies specified for small-scale projects, the small hydropower project will result in an annual emissions avoidance of 0.7600 kilograms of CO2 equivalent per kilowatt hour generated (kg CO2e/kWh). This figure is based on the weighted average emissions of grid connected thermal power stations operating as of September 2009. Other project benefits include reductions in NOx and SOx pollution, generation of short- and long-term local employment, and direct financial contributions to community development projects at each site.
This project report quantifies the Emission Reductions and Removals (“ERRs”) for the first verification period (01 June 2004 – 31 August 2009), and estimates the average annual, and total projected ERRs for the remainder of the project life. Verification will occur on an annual basis should the quantity of ERRs realized be of sufficient quantity to merit verification. After each verification is completed, this project report will be amended to record the actual quantity of ex-post Verified Emission Reductions and Removals (“VERRs”) measured and verified.
Contributions towards sustainable development:
• Reducing the dependence on exhaustible fossil fuels for power generation; • Reducing air pollution by replacing coal-fired power plants with clean, renewable power; • Reducing the adverse health impacts from air pollution; • Contributing to local economic development and employment creation. • Reducing the emissions of greenhouse gases, to combat global climate change;
A.3. Project participants:
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The following are the main Project participants:
SAEMS Capital I B.V. (“SAEMS”) established in February 2006 is a Curaçao corporation that has acquired and operates the small hydropower plant. SAEMS’s business activity is to develop, construct, acquire, own and operate hydropower and other renewable energy projects. Up to September 2009, the company had commissioned seven (7) such plants with a combined total installed capacity of 25 MW. SAEMS is seeking registration of these small hydropower projects under the ISO 14064-2 Standard as a means to buffer the higher investment and financial risks associated with the renewable energy marketplace in Sri Lanka.
Jomini Environmental Inc., (“JEI”), a privately owned international environmental management consulting firm is the exclusive representative of SAEMS for the purposes of the marketing and sale of emissions reductions from the project described in this document. JEI is also the designated official contact for the proposed project activities.
See Annex 1 - Information on participants in the project activity, for contact information of all project participants.
A.4. Technical description of the small-scale project activity:
A.4.1. Location of the small-scale project activity:
A.4.1.1. Host Party(ies):
Sri Lanka
A.4.1.2. Region/State/Province etc.:
Sambaragamuwa Province, Ratnapura District
A.4.1.3. City/Town/Community etc:
Near the city of Kahawatte and the village of Poranuwa.
A.4.1.4. Details of physical location, including information allowing the unique identification of this small-scale project activity :
The Wey Ganga Small Hydropower Project coordinates are:
Latitude 6° 34’8” N / Longitude 80° 33.6’ E
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A.4.2. Type and category(ies) and technology/measure of the small-scale project activity:
Type I – Renewable Energy Project Category: I.D./Version 14 - Grid connected renewable electricity generation.
The project site involves installation of a run-of-river hydropower plant system using well-established technologies. Run-of-river hydropower facilities are emissions-free and considered one of the best forms of low impact renewable energy available today. The civil structures at each project site consist of a gated weir designed to store a low volume of water, an intake arrangement, a channel, a desilting/forebay arrangement, a penstock, a powerhouse and a tailrace. Run-of-river hydropower has very low impact on river flow volumes and all water diverted to the powerhouse is returned to the main stream. The facility runs on a Francis type turbine. This turbine type has well-demonstrated application around the world and is considered optimal for this particular site. The specific technical data for this facility is available from the project proponent, SAEMS.
All electricity generated from this project will be sold to the CEB, the monopoly government owned power utility. The CEB will dispatch the electricity from the hydropower project to end users connected to the national power grid.
The main technical parameters of this project is shown in Table 1.
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Table 1: Main Technical Parameters Main Parameters - Type of Turbine Francis Net head/m 58 Number of turbines 3 Total design flow m3/s 16 Capacity MW 8.7 Design flood (100yr flood 155 m3/s) Gross head/m 60
A.4.3 Estimated amount of emission reductions over the chosen crediting period:
The proposed project activity will result in a reduction of anthropogenic emissions of greenhouse gas by displacing an equivalent volume of electricity that would otherwise be generated by the most expensive thermal power plants tied into the national grid. This expected outcome can be traced back to the expansion plans, dispatch procedures, and small power purchase policies of the CEB. These plans, procedures and policies are discussed in greater detail in Section B of the PDD.
Each year, the CEB prepares an annual energy demand forecast for each of the 8,760 hours contained in a year. The CEB determines the power supply forecast based on strict merit order beginning with the power plant with the lowest generation cost per kilowatt hour. Small-scale renewables, including the project in this PDD, are not included in the supply forecast. Instead, the CEB buys small hydropower output and other small-scale renewable energy generation as a substitute for its highest-cost thermal power output. The project presented here will be subject to standard terms of the CEB’s small power purchase agreement (“SPPA”). The purchase price is derived from the CEB’s estimated short-run avoided cost of electricity generation, which includes the cost of fuel plus operations and maintenance. Based on this power pricing formula for renewable energies, all small hydropower producers will only displace electricity from thermal power plants.
This small hydropower facility began operating in June 2004 and is expected to operate for 50 years. Using a weighted average emission factor of 0.7600 tonnes CO2/MWh for the thermal power plants in operation as of September 2009, the annual emissions reductions for any twelve-month period is estimated at 16,720 tonnes of CO2e.
Table 2: Estimated Electricity Generation and Emissions Reduction Summary. Average Annual Project Capacity Capacity Emissions Hydropower Electricity Emissions Emissions Rating Factor Factor Plant Generated Reductions Reductions (MW) (%) 6 (kgCO2/kWh) (10 kWh) (tCO2e) (tCO2e) Wey Ganga 8.7 28.9 22.0 0.7600 16,720 836,000
The actual amount of electricity generated and emissions reduced to date is contained in Annex 5. The amount of VERRs generated to date is summarized in Table 3 below:
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Table 3: Verified Emission Reduction and Removals Summary.
Monitoring Period VERRs (tCO2e) 01 Jun – 31 Dec 2004 9,100 01 Jan – 31 Dec 2005 14,594 01 Jan – 31 Dec 2006 16,703 01 Jan – 31 Dec 2007 12,834 01 Jan – 31 Dec 2008 20,328 01 Jan – 31 Aug 2009 9,433 Total to Date: 82,992
A.4.4. Public funding of the small-scale project activity:
The project does not receive any public funding.
A.4.5. Confirmation that the small-scale project activity is not a debundled component of a large scale project activity:
This project consists of a single stand-alone small-scale hydropower plant. This project is not debundled components of a larger project.
A.5. Identification of risks:
There are no risks associated with this project. In the case of the facility not generating power for any reason, such as natural climate conditions, there is no power generated and sold to the grid, and there will be no ERRS to be verified. There are no risks of reversals because monitoring is recorded from sealed electricity meters by the CEB and invoiced as power delivered to the grid. Verification is conducted and ERRs recorded ex-post. Ownership of the ERRs has been clearly delineated with ‘Proof of Title’ contracts, which would be contractually re-assigned should any facility be sold, and would be scrutinized in the verification process.
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:
Indicative simplified baseline and monitoring methodologies for selected small-scale CDM project activity categories: AMS I.D./Version 14 - Grid connected renewable electricity generation.
For more information on the methodology refer to the UNFCCC website: http://cdm.unfcc.int/methodologies/SSCmethodologies/approved.html
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B.2 Justification of the choice of the project category:
The applicability conditions for simplified baseline methodology category I.D. are:
a) The project comprises renewable energy generation units in the form of hydropower; b) The project supplies electricity to, and displaces electricity from, the national electricity distribution that is supplied by at least one fossil fuel fired generating unit; and c) The project capacity is 8.7 MW, which is less than the 15 MW small-scale CDM threshold.
B.3. Description of the project boundary:
For AMS-I.D version 14, the project boundary of this project activity according to the applied methodology category is as follow:
“The physical, geographical site of the renewable generation source delineates the project boundary.”
The project boundary is the physical project site, shown within the red dotted line in Figure 1. This includes the turbine, generation diversion weir, headrace and all components of the hydropower plant. Electricity generated from the project will displace power coming from the project electricity system, which is the Sri Lankan National Electricity Grid.
River feeding the facility
Construction of Transmission Sri Lanka access roads, and Hydropower National foundations, distribution End user facility Electricity substation, of power Grid transmission lines
Transport of project equipment, materials
Installation of project equipment
Figure 1: Project Boundary
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B.4. Description of baseline and its development:
The proposed project activity involves the installation of a new run-of-river hydropower facility that connects to, and delivers electricity to, the Sri Lankan national electricity grid.
The CEB, is a monopoly entity that controls the country’s power grid, prepares annual demand and supply forecasts, manages most power generation facilities in Sri Lanka (except for thermal power plants introduced in the past eight years), sets the terms of small power purchase agreements and leads development of grid expansion plans.
The expansion plan (updated every two years) is designed to respond to two key concerns. First, electricity demand in Sri Lanka is growing at an average annual rate of 6-8%, which will require major investments in new generation facilities over the next decade.1 Second, further exploitation of large scale hydro resources (which have historically provided a large percentage of total power) is becoming increasingly difficult owing to social and/or environmental impacts associated with such developments. The CEB’s 2009-2022 national expansion plan therefore turns to thermal power plants as the primary solution to meeting the country’s growing energy needs. Specifically, the CEB forecasts power generation capacity to increase from its 2008 level of 2,256.5 MW to a target level of 7,686.5 MW in 2022. Of this expansion, 97.2% (5,280 MW) is due to come from new thermal plants.
Baseline uncertainties and alternative scenarios. Based on the facts regarding how CEB prepares and guides both the dispatch of current energy supply as well as the options for future energy investments, the most likely baseline scenario in Sri Lanka is the one that conforms to the CEB’s current generation mix plus the base case expansion plan. The major uncertainties related to this scenario are (i) emergency conditions that lead to generation short-falls and power outages; and (ii) delays in building new power generation facilities. Either of these scenarios is likely to increase average emissions levels because (a) older, higher emissions thermal power plants will have to be used longer and for more operating hours per year, and (b) emergency diesel generators will be required to overcome generation shortfalls. A third possible scenario is a substantial increase in small-scale renewable energy or a greater investment in large-scale hydropower. However, as the earlier discussion emphasized, small-scale hydropower and wind power have very limited potential (100-200 MW for small-scale hydropower) compared to the total expected growth in generation over the next 15 years. Similarly, the country has nearly exhausted its options for large-scale hydropower because of environmental and social concerns.
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:
Power generation capacity expansion is an urgent issue in Sri Lanka. Energy demand in the country has been growing at an average rate of about 6-8% per annum in the past 20 years, a trend that is expected to accelerate over the next decade. According to the CEB, further exploitation of large hydro resources is becoming increasingly difficult owing to social and/or environmental impacts associated with large-scale developments as well as the cost factor. In addition, the extensive reliance on hydropower makes the
1 CEB, Long Term Generation Expansion Plan 2009- 2022, December 2008, pg 1-5.
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power system of this island nation overly vulnerable to drought. Severe drought led to power cuts in 2001 and the CEB has expressed its concern that cuts could occur again in the absence of capacity expansion.
The CEB is the government-owned monopoly power utility that prepares and manages the implementation of the country’s power generation expansion plan. To meet the rapid growth in energy demand, the CEB expansion plan forecasts the addition of 5,430 MW in installed capacity between 2009 and 2022. 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. While the existing generating system consists of a considerable amount of hydropower (42% of installed capacity in 2008), the base case expansion plan focuses on growth in thermal power. Specifically, it includes only 150 MW of hydropower additions and 5,280 MW of thermal power additions. This represents 2.8% and 97.2% of the planned capacity from 2009 – 2022 respectively2.
The potential for small scale hydropower to access the marketplace in Sri Lanka is restricted by the fact that the CEB controls access to, and the terms for, all power production. The CEB is the major owner and operator of most power generation 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 decade, 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 facilities3. The CEB nevertheless maintains control of the process of identifying and licensing these new facilities. Similarly, all small-scale projects must have the preapproval of the CEB and developers must accept the CEB’s energy purchase price that changes annually - not based on verifiable, objective criteria, but rather changes in accordance with the CEB internal calculations.
This discussion serves to highlight 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 favor investments in thermal generation combined with only one new investment in a large-scale, publicly-managed hydropower facility.
As the rest of this section demonstrates, the small-scale hydropower project in this PDD is considered additional to the Sri Lanka energy sector emissions baseline based on an analysis of selected barriers listed in the Tool for the demonstration and assessment of additionality.4 Specifically, we demonstrate that the project faces significant barriers related to (i) heightened investment risk (common to all small- scale renewable investments in Sri Lanka), (ii) low market penetration of run-of-river small hydropower technology, and (iii) non-transparent procedures in the calculation of tariff schedules for small hydropower operators.
(i) Investment risk barrier
Energy generation investment opportunity in Sri Lanka is relatively limited. In that limited market, small hydropower investments are subject to much higher risks than investments in thermal power projects. The difference in level of risk is in large part linked to the power purchase terms set by the CEB. In the
2 CEB, Long Term Generation Expansion Plan 2009- 2022, December 2008, pg 7-3 3 CEB, Long Term Generation Expansion Plan 2009- 2022, December 2008 4 CDM: Methodological Tool Version 01.1, Tool for the demonstration and assessment of additionality
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case of thermal power plants the CEB pays a capacity charge sufficient to cover all up-front capital costs including an agreed rate of return on the investment. In addition, separate payments are made for energy on a pass through basis. Thus, private thermal power plant operators and investors are guaranteed a no risk rate of return on their investment provided the technical aspects of the plant are sound.
In contrast, investors and operators of small hydropower facilities (and other small renewables) do not receive a capacity charge. Instead, small hydropower developers are paid based strictly on the CEB's short-run avoided costs. These avoided costs can fluctuate considerably from year to year and small hydro developers can suffer, and have in the past suffered, losses in individual years. Unlike thermal power plant operators, small hydropower investors cannot claim a payment to compensate for drought-induced generation shortfalls. These arrangements act as a disincentive to investments in small-scale hydropower and argue for the additionality of the SAEMS investment at Wey Ganga.
(ii) Low market penetration/uncommon practice barrier
The CEB long term expansion plan 2009-2022 concludes that the country has limited potential for small- scale hydropower (100-200 MW). As indicated earlier, the CEB forecasts only 2.8% of future energy generation in 2009-2022 to come from hydropower. Looking at the impact of the project in this PDD, it is clear that hydropower makes very marginal contributions to the current and future generation mix. With an aggressive schedule for future expansion of thermal power capacity, small scale hydropower will continue to be a marginal technology in Sri Lanka with low market penetration, unless CDM or voluntary credit market revenues enable small hydro developers to take on the higher risks associated with investing in small run-of-river hydro plants.
(iii) Barriers related to uncertainties in power purchase agreement conditions
Small-scale hydropower investors also face uncertainties and risks related to power purchase terms of the CEB, a monopoly utility. Each year the CEB sets a power purchase agreement price level for the wet and dry seasons. However, the CEB does not transparently demonstrate to small power producers the methodology for calculating these power purchase prices. The tariff is based on a 3-year running average of the avoided cost of the most expensive thermal unit replaced. The tariff should therefore follow the rate of increase of crude oil price. The crude oil price has been steadily increasing, while the tariff does not follow the same trend of increase. As a result, private investors have considerable difficulty predicting the direction of price changes and the degree of fluctuation from one year to the next. The only recourse is for producers to enter into arbitration over rate calculations.
In recent years the CEB has also increased the project implementation cost for small hydro projects, by getting developers to upgrade existing CEB lines at their own expenses.
This analysis of three different barriers suggests that small hydropower investments like the ones at Wey Ganga are additional to a national baseline which is clearly oriented to favor large-scale thermal investments combined with a limited number of large-scale, publicly managed hydropower investments. Faced with the multiple investment barriers described here, SAEMS began in early 2006 to evaluate the possibility of improving project rates of return and reducing its financial risks through registration of its projects under a recognized GHG program.
B.6. Emission reductions:
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B.6.1. Explanation of methodological choices:
The baseline scenario of the project is the continued operation of the existing power plants in the system and the addition of new thermal generation sources to meet electricity demand.
In accordance with the small-scale methodology AMS - I.D. Version 14, baseline emissions are equal to power generated by the project activity and delivered to the grid, multiplied by the baseline emission factor. According to the small scale methodology I.D the baseline emission factor for electricity supplied to the national grid served by a mix of generating capacity (not solely fuel oil and diesel) is calculated as either:
a) A combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) according to procedure prescribed in the ‘Tool to calculate the emission factor for an electricity system’.5
OR
b) The weighted average emissions of the current generation mix.
Power consumption in Sri Lanka is growing rapidly, which requires the construction of additional generating capacity. This project’s 8.7 MW hydropower station is therefore expected to displace predominantly new capacity that is added to the grid and power generated by plants at the operating margin. The first of the two options captures the recent and accelerating trend towards fossil fuel based energy production in Sri Lanka. The second would poorly represent the likely baseline because of the increasing reliance on fossil fuels indicated by the following table of planned expansion of generating capacity by the CEB.
Table 4: Planned expansion of generating capacity by the CEB6 Plant Capacity (MW) Kerawalapitiya combined cycle (2009) 300 Gas Turbines (2010) 285 Coal Steam (2011) 600 Upper Kotmale Hydro Power (2012) 150 Puttalam- Coal Steam I (2012) 300 Puttalam- Coal Steam II (2013) 300 Puttalam- Coal Steam III (2014) 300 Trinco- Coal Steam II (2015) 300 Coal Steam (2016) 300 Coal Steam (2017) 300 Coal Steam (2018) 300 Coal Steam (2019) 300 Coal Steam (2020) 300 Gas Turbines (2020) 105
5 Annex 12 Methodological tool (Version 01.1) “Tool to calculate the emission factor for an electricity system.” 6 CEB, Long Term Generation Expansion Plan 2009-2022, December 2008, pg 10-3,4.
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Coal Steam (2021) 300 Total 4440
Given the increasing reliance on fossil fuels planned by the CEB it would not be possible to justify a baseline of the weighted average emissions of the current generation mix, as this will change towards an increasing reliance on fuels with significantly greater emission intensity.
The combination of the operating margin and the build margin better represents the current and likely future developments, as it balances the emission intensities of all plants constructed since 1992 (and a few older fossil fuel facilities) with that of the last plants added to the grid. This is a conservative approach because the reality over the upcoming years with commissioning of the coal power plants will be presumably much worse in terms of CO2 emission.
The latest version of the ‘Indicative simplified baseline and monitoring methodologies for selected small- scale CDM project activity categories’ AMS-I.D. Version 14 defines the baseline for grid connected electricity generation to be the product of electrical energy baseline expressed in kWh of electricity produced by the renewable generating unit multiplied by an emission factor. The Emission factor can be calculated in a transparent and conservative manner by using Annex 12 Methodological tool (Version 01.1) “Tool to calculate the emission factor for an electricity system”.
The baseline for the Wey Ganga project is defined as the kWh produced by the small hydropower plant multiplied by an emission factor (measured in kgCO2/kWh).
As discussed in Section B2 the combined margin (CM) consisting of the combination of operating margin (OM) and build margin (BM) will be calculated to determine baseline emissions according to Steps 1-6 described in the methodological tool.
The key methodological steps are:
1. Identify the relevant electric power system 2. Select an operating margin (OM) method 3. Calculate the operating margin emission factor according to the selected method 4. Identify the cohort of power units to be included in the build margin (BM) 5. Calculation of the build margin emission factor 6. Calculation of combined margin (CM) Emission Reduction
Step 1. Identify the relevant electric power system
This hydropower project will be connected to the national grid of Sri Lanka, which is operated and monopolized by the CEB. This national grid is a unique transmission and distribution line to which all power plants in Sri Lanka are connected. Hence the national grid is the project electricity system.
Step 2. Select an Operating Margin (OM) Method
The methodological tool offers four options for the calculation of the OM emission factor (EFOM,y). The options are as follows;
1) Simple OM
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2) Simple Adjusted OM 3) The Dispatch Data Analysis OM 4) The Average OM
Of these, the preferred method is dispatch data analysis, however this option cannot be used because dispatch data are not available to the public or to project participants. For the same reason the simple adjusted OM methodology cannot be used. The average OM cannot be used because low cost/must run resources (hydropower and wind power) constitute less than 50% of the total grid generation (Table 4)7.
The OM emission factor can be calculated as the Simple OM method only where low-cost must run resources constitute less than 50% of total grid generation in 1) average of the five most recent years, or 2) based on long term averages for hydroelectricity production. As shown in Table 4 below, the low cost/must run resources constitute less than 50% of the total grid generation in average of the five most recent years.
Therefore the Simple OM method was selected for calculation of the operating margin emission factor.
Table 5: Generation over the five most recent years for which data are available8 GWh 2004 2005 2006 2007 2008 Total Hydro 2,960 3,453 3,451 3,947 4,130 17,941 Non 3 2 5 4 8 30 Conventional Total Low 2,963 3,455 3,456 3,951 4,138 17,963 cost must run GWh 2004 2005 2006 2007 2008 Total Thermal 5,080 5,314 5,314 5,864 5,763 27,335 Total 8,043 8,769 8,769 9,814 9,901 45,296 Generation % low cost 37% 39% 39% 40% 42% 39.7% must run
For the Simple OM, the emissions factor can be calculated using either an ex ante option or ex post option. This project uses the ex post option. In accordance with the methodological tool the ex post calculation of the OM Emission Factor is applied to the year in which the project activity displaces grid electricity, requiring the emission factor to be updated annually during monitoring.
Step 3. Calculate the Operating Margin (OM) Emission Factor (EFOM,y)
There are three hierarchical options for calculating the Simple OM in the methodological tool. The preferred method for this calculation is Option A based on fuel consumption and net electricity generation of each power plant. This data is not available to the public or project participants in Sri Lanka. In this case Option B was used, and data is based on net electricity generation, the average efficiency of each power unit and the fuel types used in each power unit.
7 CEB, Statistical Digest, 2008 8 CEB, Statistical Digest, 2005-2008
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Where Option B is used, the Simple OM factor is calculated based on the electricity generation of each power unit and an emission factor for each power unit, as follows:
EFgrid,OMsimple,y = ∑EGm,y * ∑EFEL,m,y ∑EGm,y
Where: EFgrid,OMsimple,y = Simple operating margin CO2 emission factor in year y (tCO2/MWh) EGm,y = Net quantity of electricity generated and delivered to the grid by power unit m in year y (MWh) EFEL,m,y = CO2 emission factor of power unit m in year y (tCO2/MWh) m = All power units serving the grid in year y except low cost / must run power units y = Ex Post: The year in which the project activity displaces grid electricity, requiring the emissions factor to be updated annually during monitoring.
The emission factor of each power unit m should be determined using either Option B1 or Option B2 depending on data available. Option B2 was used because fuel consumption and electricity generation data is not available. Option B2 suggests emission factors should be determined based on the CO2 emission factor of the fuel type used and the efficiency of the power unit.
EFEL,m,y = ∑EGCO2,m,i,y * 3.6 ηm,y
EFEL,m,y = CO2 emission factor for power unit m in year y (tCO2/MWh) EFCO2,m,I,y = Average CO2 emission factor of fuel type I used in power unit m in year y (tCO2/GJ) ηm,y = Average net energy conversion efficiency of power unit m in year y (%) y = Ex Post: The year in which the project activity displaces grid electricity
EFgrid,OMsimple,y is derived as follows;
EFgrid,OMsimple,y = 0.7818
Step 4. Identify the cohort of power units to be included in the build margin
The sample group of power units m used to calculate the build margin consists of the larger of:
a) The set of five (5) power plants 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.
This project has determined that the build margin includes the five most recent power plants commissioned. These were determined by a comparison of the weighted average of 20% of the considered power plant cohort to the last five commissioned power plants using the maximum available annual power generation in MWh. The comparison clearly shows that the last five power plants are considerably greater than the 20% consideration.
Step 5. Calculation of the Build Margin (BM) Emission Factor (EFBM,y)
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The BM Emission Factor is the generation-weighted average emission factor (tCO2/MWh) of all power units m during the most recent year y for which power generation data is available, calculated as follows:
EFgrid,BM,y = ∑EGm,y * ∑EFEL,m,y ∑EGm,y
Where: EFgrid,BM,y = Build margin CO2 emission factor in year y (tCO2/MWh) EGm,y = Net quantity of electricity generated and delivered to the grid by power unit m in year y (MWh) EFEL,m,y = CO2 emission factor of power unit m in year y (tCO2/MWh) m = Power units included in the build margin y = Most recent historical year for which power generation data is available
In accordance with Annex 12 Methodological tool (Version 01.1) “Tool to calculate the emission factor for an electricity system” the ex post calculation of the BM Emission Factor is applied to the year in which the project activity displaces grid electricity, requiring the emission factor to be updated annually during monitoring.
EFgrid,BM,y is derived as follows;
EFgrid,BM,y = 0.7381
Step 6. Calculate the Combined Margin (CM) Emission Factor (EFCM,y)
The Combined Margin emission factor (EFCM,y) is the weighted average of the OM emission factor (EFOM,y) and the BM emission factor (EFBM,y), where the weighting factors are wOM = 0.5 and wBM = 0.5 during the first crediting period, and 0.25 and 0.75 respectively in the second and third crediting period.
EFgrid,CM,y = EFgrid,OM,y * wOM + EFgrid,BM,y * wBM
So in the first crediting period, the CM emission factor is derived as follows:
EFgrid,CM,y = 0.5 * 0.7818 + 0.5 * 0.7381 = 0.7600 kgCO2/kWh
The baseline emissions of the project were calculated using the baseline emission factor described above. Based on this annual emission reductions of the project were calculated as follows:
Annual power generation * Weighted average emission reduction = Baseline emissions
B.6.2. Data and parameters that are available at validation: (Copy this table for each data and parameter) Data / Parameter: EGm,y Data unit: MWh Description: Net quantity of electricity generated and delivered to the grid by power unit m in year y Source of data used: CEB, Long Term Generation Expansion Plan 2009-2022, December 2008, pg A4-6 Value applied: All data are available for validation
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Justification of the Dispatch data is not disclosed to the public or project proponents. The CEB choice of data or provides the most updated data relevant to power generation in Sri Lanka that description of could be accessed by public. measurement methods and procedures actually applied : Any comment:
Data / Parameter: EFEL,m,y Data unit: tCO2MWh Description: CO2 emission factor of fossil fuel type i in year y Source of data used: 2006 IPCC Guidelines for National Greenhouse Gas Inventories Oxidation factors; IPCC default values, see Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Workbook, p.1.8. Value applied: All data are available for Validation Justification of the With reference to Version 1.1 of ``Tool to calculate the emission factor for an choice of data or electricity system`` description of measurement methods and procedures actually applied : Any comment:
Data / Parameter: EGm,y Data unit: MWh Description: Net quantity of electricity generated and delivered to the grid by power unit m in year y Source of data used: CEB, Long Term Generation Expansion Plan 2009-2022, December 2008, pg A4-6 Value applied: All data are available for validation Justification of the Dispatch data is not disclosed to the public or project proponents. The CEB choice of data or provides the most updated data relevant to power generation in Sri Lanka that description of could be accessed by public. measurement methods and procedures actually applied : Any comment:
See Annex 3 for detailed description of all calculations.
B.6.3 Ex-ante calculation of emission reductions:
Baseline emissions
Baseline emissions include only CO2 emissions from electricity generation by fossil fuel fired power plants that are displaced due to the project activity. It is calculated as follows;
BEy = EGy * EFgrid,CM,y
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Where: EGy - Electricity supplied by the run-of-river hydropower facility to the grid
Where: EGy = 22,000 MWh
Where: EFgrid,CM,y = 0.7600 tCO2/MWh
Therefore: BEy = 22,000 * 0.7600 = 16,720 tCO2
Project emissions
This is the small scale hydropower project, therefore the GHG emission from the project activity is considered as zero (PEy = 0)
Leakage
Because the technology used is neither transferred to nor transferred from another activity leakage is 9 considered to be zero (Ly = 0)
Reduction emissions
Expected annual emission reductions are calculated as follows:
ERy = BEy - PEy - Ly = BEy
= 16,729 tCO2e
B.6.4 Summary of the ex-ante estimation of emission reductions:
Average Annual Project Capacity Capacity Emissions Hydropower Electricity Emissions Emissions Rating Factor Factor Plant Generated Reductions Reductions (MW) (%) 6 (kgCO2/kWh) (10 kWh) (tCO2e) (tCO2e) Wey Ganga 8.7 28.9 22.0 0.7600 16,720 836,000
B.6.5 Summary of the verified emission reductions and removals:
Monitoring Period VERRs (tCO2e) 01 Jun – 31 Dec 2004 9,100 01 Jan – 31 Dec 2005 14,594 01 Jan – 31 Dec 2006 16,703 01 Jan – 31 Dec 2007 12,834
9 Appendix B of the simplified modalities and procedures for small-scale CDM activities
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01 Jan – 31 Dec 2008 20,328 01 Jan – 31 Aug 2009 9,433 Total to Date: 82,992
B.7 Application of a monitoring methodology and description of the monitoring plan:
B.7.1 Data and parameters monitored:
The only data that will be monitored is the net amount of power supplied to the grid by the hydropower station. This data type is based on the metered output of electricity from the power plant and is double checked by receipt of sales from the CEB.
(Copy this table for each data and parameter)
Data / Parameter: EGy Data unit: MWh Description: Electricity output produced by the Wey Ganga hydropower facility and supplied to the national electricity grid Source of data to be Direct measurement from on-site metering systems and electricity sales receipts used: for electricity sold to the CEB. Value of data 22,000 Description of The data is directly measured in kWh meters at the project site and collated by measurement methods the centralized information system of the project proponent as outlined in and procedures to be Section B7.2. The measurement process involves: applied: 9 Hourly measurement and monthly recording. 9 Electronic archiving during the crediting period and kept for 2 years after the last VER is issued in each crediting period. 9 Two metering systems are used, the plant meter and the CEB meter. QA/QC procedures to The data from electricity sales receipts will be cross checked against meter be applied: readings taken at the project site. The CEB installed and maintains a primary meter to measure electricity passing to the grid to enable correct invoicing purchased electricity. The metering equipment is located in close proximity to the facility and is sealed. Any comment:
B.7.2 Description of the monitoring plan:
The applicability conditions for simplified monitoring methodology category AMS-I.D are:
a) The project comprises renewable energy generation units in the form of run-of-river hydropower;
b) The project supplies electricity to and displace electricity from the national electricity distribution system that is supplied by at least one fossil fuel fired generating unit; and
c) The project capacity is 8.7 MW, which is less than the 15 MW threshold for small-scale CDM projects.
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Pursuant to the simplified monitoring methodology used for the project the only variable that requires monitoring is the actual generation of electricity from the project site. This is performed as follows:
• Upon completion of construction, the CEB required independent testing of the facility and inspection of its equipment. The CEB witnessed the testing procedure. • The CEB installed and maintains a primary meter to measure electricity passing to the grid to enable correct invoicing purchased electricity. The metering equipment is located in close proximity to the facility and is sealed. • Metering equipment is tested and calibrated annually. • The CEB read the meter monthly for determination of the electrical energy delivered to, and accepted by, the CEB under terms of the SPPA. • The power plant is automated and operators measure generation levels hourly and record them on site monthly. • In case of any problem with operations or manager, the operator contacts a seniors engineer for corrective action. • Emergencies cannot cause unintended emissions since there is no fuel used by the plants. In the event of a shut-down of the grid, the hydropower facility will automatically switch off and water will no longer be diverted to the turbine. • At the time of verification, the Project Proponent can make available records of electricity generation, meter calibration, and CEB power purchase receipts. The verifier can also visit the project site to confirm the status of operations.
The facility plant manager is responsible for completing the monthly electricity generation log, reconciling the CEB power purchase invoices, and ensuring maintenance and calibration of the plant equipment. These are forwarded on a monthly basis to, and screened by, the project proponent (SAEMS), which maintains the central information system for collating and aggregating the project data. Spot audits are conducted during site visits by the project proponent on at least an annual basis. The project proponent forwards the aggregated project data to the authorized project representative (Jomini). The project data is then collated, an updated baseline scenario is determined, the emission reduction enhancements are calculated, and the verification instruction is then issued.
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 and monitoring methodology section: 17 September 2009.
The baseline and monitoring methodology was prepared by:
Jomini Environmental Inc. 2174 King Road East, Suite 300 King City, ON L7B 1A4 Canada Tel: +1 905 833 1801 Fax: +1 905 833 1946 Email: [email protected]
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This entity is a project participant as listed in Annex 1
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:
The starting date for this project is the commission date as defined as the point when the power plant entered into service. The following table indicates both the date of launch of construction and of commissioning of the plant.
Project Actual or Anticipated construction start date
Actual or Anticipated operational date
Actual or Anticipated Actual or Anticipated Project construction start date operational date Wey Ganga Apr-03 Jun-04
C.1.2. Expected operational lifetime of the project activity:
This project will last for 50 years from the project start date, 30 May, 2054.
C.2 Choice of the crediting period and related information:
C.2.1. Renewable crediting period
Not applicable
C.2.1.1. Starting date of the first crediting period:
Not applicable
C.2.1.2. Length of the first crediting period:
Not applicable
C.2.2. Fixed crediting period:
C.2.2.1. Starting date:
1 June 2004
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C.2.2.2. Length:
50 years, 0 months
C.2.2.3. End date:
30 May 2054
SECTION D. Environmental impacts
D.1. If required by the host Party, documentation on the analysis of the environmental impacts of the project activity:
The Central Environment Authority (“CEA”) requires a detailed Environmental Report for small hydro power plant projects such as the Wey Ganga Project. Because of the small nature of the investment, the CEA requires an Environmental Report to be completed, rather than a full blown Environmental Impact Assessment. This report follows a format provided by the CEA. The CEA subsequently visited the proposed site with a team of experts. All clarifications were addressed, and the CEB granted approval in the form of an Environmental Clearance.
An Environmental Report was completed for this project, and is available upon request from the project proponent. The report incorporates the following sections:
• Project description (area, weirs/intakes, desilting tanks, head race channels/spills, forebays/desilting tanks, penstocks, power house/tailraces, access roads, and transmission line).
• List of clearances and authorizations obtained, including:
o Approval for construction activities o Approval from CEB for sale of electricity. o Approval from National Water Supply and Drainage Board/Divisional Secretary for diversion of water. o Approval from the Mahaweli Authority if water streams are controlled by them.
• Description of site topography, geology, hydrology, fauna and flora, upstream and downstream users, and social/cultural sensitive areas.
• Discussion of possible impacts such as erosion, land scarring, migration, construction hazards, changes in land use patterns, relocation, etc.
• Description of monitoring program and any mitigation measures of the project.
A general comment on the nature of small-scale run-of-river hydropower projects is helpful in order to provide a clear understanding of the extremely low impact of this type of investment. Small-scale run-of- river hydropower has a very low impact on river flow volumes and all water diverted to the powerhouse is returned to the main stream. A very small ponding area occurs behind the low weir constructed across the river to facilitate the diversion of water into a channel. The volume of water accumulated behind the
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weir varies depending upon the site conditions but is typically less than five (5) minutes of the average water flow of the river. It is also relevant to point out that small hydropower plants do not create any type of atmospheric, noise or other pollution and they cannot therefore have any negative impact on persons living in the close vicinity of these plants.
The project has secured the Environmental Clearance from the CEA and this report is available from the project proponent. This clearance reflects the finding that the environmental impact of the project is negligible and specifies the requirements for ongoing site monitoring.
It should be noted that the facility has been constructed in accordance with the Environmental Report and the Environmental Clearance, and is in normal operation.
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:
Not applicable
SECTION E. Stakeholders’ comments
E.1. Brief description how comments by local stakeholders have been invited and compiled:
The stakeholders for this project were identified as part of the process of seeking environmental clearance to proceed with the project. In all cases meetings were conducted with the individuals living and working in the vicinity, or the applicable landowners, to explain the project’s objectives and benefits. Those consultations allowed the developer to design the projects so that they did not/will not interfere with current land use and economic activity. In addition, as part of gaining the approval of the CEA, the Environmental Report determined that there is no impact on the local communities.
E.2. Summary of the comments received:
Comments received from local stakeholders were generally positive. Participants were eager to participate as employees of the project.
E.3. Report on how due account was taken of any comments received:
This project has been constructed in accordance with determinations made in the Environmental Report, requirements from the Environmental Clearance, and is in full successful operation.
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Annex 1
CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY
Project Proponent Organization SAEMS Capital I B.V. Street: Building: United International Trust N.V. State: Postal Code: Country: Curaçao, Netherlands Antilles Telephone: ++59 (99) 736 6277 Fax: +59 (99) 736 6161 Email:
Represented by Title: Sole Director Last Name: Elias First Name: Gregory Department: Telephone: Fax: Email: [email protected]
Authorized Project Representative Organization Jomini Environmental Inc. Street: 2174 King Rd East Building: Suite 300 State/Province: Ontario Postal Code: L7B 1A4 Country: Canada Telephone: +1 905 833 1801 Fax: +1 905 833 1946 Email: [email protected]
Represented by Title: Chief Operating Officer Last Name: Mueller First Name: Chris Department: Telephone: +1 905 833 1801 Email: [email protected]
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Annex 2
INFORMATION REGARDING PUBLIC FUNDING
No public funding was available for the project.
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Annex 3
BASELINE INFORMATION
Detailed description of emission reduction calculations:
Wey Ganga project emissions are zero.
Description of the formulae used to estimate the anthropogenic emissions by sources of GHGs in the baseline.
The baseline GHG calculations are broken down into six steps as determined and defined in Section B. All calculations are contained in the spreadsheet attached as Annex 3 – Baseline Information. All variables have been assigned a letter code (A, B, C, D….) which allows for easy cross-reference to the explanations below.
Step 1: Calculate the relative power contribution of each thermal power plant on the grid (expressed as a percentage of total kWh generated)
This calculation is based on the following series of equations. a. Determine expected total operating hours/year:
The following equation assumes all power plants are operating at optimal load levels. This allows for the most conservative estimate of emissions given that emissions factors tend to rise when thermal power plants operate at low load levels.
Actual operating 8760 hours/year – maintenance days – forced outage rate hours/year (%) [ D ] [ (A – (B*24 hours)) * (1-(C/100) ]
Data source: CEB Time Availability formula1 b. Determine maximum annual energy output (kWh/year) of each power plant
Annual energy output = Actual Operating hours * Capacity (MW) (MWh/yr) [ D * E ]
Data source: CEB c. Calculate percentage power contribution of each power plant (% of MWh/year)
Percentage power = Annual energy output of each plant / of each plant (%) Sum of energy output of all plants [ G ] [ F / Σ F1….n ]
1 CEB, Long Term Generation Expansion Plan 2009-2022, December 2008, pg A4-6 26
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Step 2: Calculate the Operating Margin (OM) emissions factor (EFOM,y) for each thermal power plant a. Determine each plant’s heat rate (MJ/MWh)
3 Plant heat rate = (100 / plant conversion efficiency) * 3.6 * 10 (MJ/MWh)
3 [ J ] [ (100 / I ) * 3.6 * 10 ]
3 Data source: CEB for plant conversion efficiency rates; IPCC for terajoule conversion factor of 3.6 * 10 joules/MWh. b. Estimate an adjusted carbon content of fuel for each power plant
Adjusted carbon content = carbon content of each fuel * of each fuel combustion efficiency of power plant (tC/TJ) [ M ] [ K * L ]
The combustion efficiency (oxidation factors) and CO2 emission factors are based on IPCC 2006 default values.2 3
Default values used for oxidation factors and CO2 emission factors of fuels. Fuel (104 tonnes) Oxidation Factor Carbon Emission (fraction) Factor (TC/TJ) Diesel 0.99 20.2 Fuel Oil 0.99 21.1
c. Calculate emissions factor (kgCO2/MWh) of each power plant
3 6 Emissions factor = (Heat rate * adjusted carbon content of fuel * 10 ) / 10 (kgCO2/MWh)
3 6 [ N ] [ J * M * 10 / 10 ] d. Convert kgCO2/MWh calculation to CO2 emissions per kilowatt hour
3 CO2 emissions = ( kgCO2/MWh * 44/12 ) / 10 (kgCO2/kWh) 3 4 [ O ] [ (N * 44/12) / 10 ]
2 2006 IPCC Guidelines for National Greenhouse Gas Inventories 3 Oxidation factors: IPCC default values, see Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Workbook, p. 1.8.
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Step 3: Calculate the approximate operating margin of non-renewable plants connected to the grid a. Determine weighted average emissions of each power plant
Weighted average = CO2 emissions of each plant * percent contribution of Emissions power to the grid
(kgCO2/kWh) [ P ] [ O * G ]
b. Sum weighted average emissions
Weighted average = Sum of emissions factor for emissions of all power plants 1 through n plants (kgCO2/kWh) [ Q ] [ Σ P1….n ]
This calculation results in a figure of [Q] = 0.7818 kgCO2/kWh as the operating margin emission factor.
Step 4: Identify the cohort of power units to be included in the build margin
The build margin includes the five most recent power plants commissioned. These were determined by a comparison of the weighted average of 20% of the considered power plant cohort to the last five commissioned power plants using the maximum available annual power generation in MWh. The comparison clearly shows that the last five power plants are considerably greater than the 20% consideration.
Step 5: Calculate the build margin (BM) emission factor (EFBM,y) for each thermal power plant a. Determine weighted average emissions of each power plant
Weighted average = percent contribution of power to the grid * the emissions emissions of the five most factors for the five most recent power plants recent power plant additions to the grid (kgCO2/kWh)
[ S ] [ O * R ]
b. Sum weighted average emissions
Weighted average = Sum of emissions factors for emissions of all power plants 1 through 5 plants (kgCO2/kWh)
4 2006 IPCC Guidelines for National Greenhouse Gas Inventories, 44/12 converts tC into kgCO2 28
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[ T ] [ Σ S1….5 ]
The above calculation results in a figure of [T] = 0.7381 kgCO2/kWh as the build margin emission factor.
Step 6: Calculate the Combined Margin emission factor (EFCM,y)
The baseline emission factor Combined Margin (CM) EFCM is the weighted average of the Operating Margin emission factor (EFOM) and the Build Margin emission factor (EFBM). Where the weights wOM and wBM are 0.5 and 0.5 in the crediting period.
EFCM = EFOM * wOM + EFBM * wBM
[ Q * wOM + T * wBM ] = (0.7818 * 0.5 + 0.7381 * 0.5) = 0.7600 kgCO2/kWh
The baseline emissions of the project were calculated using the baseline emission factor described above. Based on this the annual emission reductions of the project were calculated as follows.
Annual power generation * Weighted average emission reduction = baseline emissions
Difference between project emissions (0) and baseline emissions represents the emission reductions due to the project activity during a given period.
Based on the above equations, for any twelve-month period, the hydropower project will result in the following emissions reductions:
Electricity Generation and Emissions Reduction Summary. Average Annual Project Capacity Capacity Emissions Hydropower Electricity Emissions Emissions Rating Factor Factor Plant Generated Reductions Reductions (MW) (%) 6 (kgCO2/kWh) (10 kWh) (tCO2e) (tCO2e) Wey Ganga 8.7 28.9 22.0 0.7600 16,720 836,000
Baseline emissions uncertainties. Section B.5 presented the possible alternative scenarios to the emissions estimates calculated here. The primary sources of emissions uncertainties stem from slower than expected power plant expansion and energy shortfalls related to drought or power plant failure. Both scenarios will result in higher, not lower emissions as older power plants remain on-line longer and the gap from any generation short-fall will be filled by emergency generators. Given these alternatives, the baseline emissions calculated above are conservative estimates.
The total project-related emissions from the sum of all three project sites is 836,000 tonnes CO2e.
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Operating Margin 2009 Simple OM, Option B, ex post option
Step 1: Calculate the relative power contribution of each thermal power plant on the grid
Hours / Maintenance Forced Actual Operating Hours Capacity Annual Max Energy Contribution to total energy Power Plants Date Commissioned Fuel Source Year (days/year) Outage Rate (Time Availability) (MW) (MWh/yr) supply (% of MWh) G = F/∑(total thermal power Variable AB C D EF = (D x E) available) Facilities as of September 2009 CEB‐operated Kelantissa Power Station 1 ‐ Gas Turbine (Old) Dec 81, Mar 82, Apr 82 Auto diesel 8760 36 20 6316.8 85 536,928.0 5.37% 2 ‐ Gas Turbine (New) Aug‐97 Auto diesel 8760 10 10 7668.0 115 881,820.0 8.82% 3 ‐ Combined Cycle Aug‐02 Naphtha 8760 30 6.4 7525.4 165 1,241,697.6 12.42% CEB‐operated Sapugaskanda Power Station 4 ‐ Diesel May 84, Sep 84, Oct 84 Residual Oil 8760 50 17 6274.8 72 451,785.6 4.52% 5 ‐ Diesel Extension Sep 07, Oct 09 Residual Oil 8760 50 12 6652.8 72 479,001.6 4.79% CEB‐operated Chunnakam Power Station 6 ‐ Chunnakam Feb‐05 Fuel Oil 8760 40 2.74 7586.3 8 60,690.2 0.61% Independent Power Producers 7 ‐ Lakdhanavi 1997 Auto diesel 8760 30 8 7396.8 22.5 166,428.0 1.66% 8 ‐ Asia Power Ltd 1998 Auto diesel 8760 30 8 7396.8 51 377,236.8 3.77% 9 ‐ Colombo Power (Pvt) Ltd 2000 Auto diesel 8760 30 8 7396.8 64 473,395.2 4.74% 10 ‐ Ace Power Matara 2002 Auto diesel 8760 30 8 7396.8 24.8 183,440.6 1.83% 11 ‐ Ace Power Horana 2002 Auto diesel 8760 30 8 7396.8 24.8 183,440.6 1.83% 12 ‐ AES Kelantissa (Pvt.) Ltd CC 2003 Fuel Oil 8760 30 8 7396.8 163 1,205,678.4 12.06% 13 ‐ Heladanavi (Pvt) Ltd 2003 Auto diesel 8760 30 8 7396.8 100 739,680.0 7.40% 14 ‐ ACE Power Embilipitiya 2004‐2005 Auto diesel 8760 30 8 7396.8 100 739,680.0 7.40% 15 ‐ Kerawalapitiya CC Sep 08, Mar 09 Fuel Oil 8760 40 2.74 7586.3 300 2,275,884.0 22.77% Capacity Sub Total End 2009: 9,,.996 786 7 100.00%
3030 Operating Margin 2009 Simple OM, Option B, ex post option
Step 2: Calculate the Operating Margin emissions factor for each thermal power plant
Plant Conversion Heat Rate Carbon Content Combustion Carbon Content Emissions factor (kg Emissions factor (kg Power Plants Efficiency (%) (MJ/MWh) (unadjusted tC/TJ) Efficiency Factor (adjusted tC/TJ) C/MWh) CO2/kWh) Variable I J= (100/I)*3.6 x 103 KLM = K x L N = J x M x 103/106 O = (N x 44/12)/103 Facilities as of September 2009 CEB‐operated Kelantissa Power Station 1 ‐ Gas Turbine (Old) 19.1 18,848 20.2 0.99 19.998 376.926 1.3821 2 ‐ Gas Turbine (New) 31.5 11,429 20.2 0.99 19.998 228.549 0.8380 3 ‐ Combined Cycle 46.1 7,809 20.0 0.99 19.800 154.620 0.5669 CEB‐operated Sapugaskanda Power Station 4 ‐ Diesel 36.4 9,890 21.1 0.99 20.889 206.595 0.7575 5 ‐ Diesel Extension 39.5 9,114 21.1 0.99 20.889 190.381 0.6981 CEB‐operated Chunnakam Power Station 6 ‐ Chunnakam 35.9 10,028 20.2 0.99 19.998 200.537 0.7353 Independent Power Producers 7 ‐ Lakdhanavi 28.1 12,811 20.2 0.99 19.998 256.202 0.9394 8 ‐ Asia Power Ltd 30.1 11,960 20.2 0.99 19.998 239.179 0.8770 9 ‐ Colombo Power (Pvt) Ltd 30.1 11,960 20.2 0.99 19.998 239.179 0.8770 10 ‐ Ace Power Matara 28.1 12,811 20.2 0.99 19.998 256.202 0.9394 11 ‐ Ace Power Horana 28.1 12,811 20.2 0.99 19.998 256.202 0.9394 12 ‐ AES Kelantissa (Pvt.) Ltd CC 48.1 7,484 21.1 0.99 20.889 156.342 0.5733 13 ‐ HHeladanavieladanavi (P(Pvt)vt) Ltd 30.1 11,960 20.2 090.999 19.998 239.179 0.8770 14 ‐ ACE Power Embilipitiya 30.1 11,960 20.2 0.99 19.998 239.179 0.8770 15 ‐ Kerawalapitiya CC 37.5 9,600 21.1 0.99 20.889 200.534 0.7353 Capacity Sub Total End 2009
3131 Operating Margin 2009 Simple OM, Option B, ex post option
Step 3: Calculate the approximate operating margin of non‐renewable plants connected to the grid
Weighted Average Approximate OM Power Plants Emissions (kgCO2/kWh) Emissions (kgCO2/kWh) Variable P = O x G Q (∑ of P) Facilities as of September 2009 CEB‐operated Kelantissa Power Station 1 ‐ Gas Turbine (Old) 0.0742 2 ‐ Gas Turbine (New) 0.0739 3 ‐ Combined Cycle 0.0704 CEB‐operated Sapugaskanda Power Station 4 ‐ Diesel 0.0342 5 ‐ Diesel Extension 0.0334 CEB‐operated Chunnakam Power Station 6 ‐ Chunnakam 0.0045 Independent Power Producers 7 ‐ ‐ Lakdhanavi 0.0156 8 ‐ Asia Power Ltd 0.0331 9 ‐ Colombo Power (Pvt) Ltd 0.0415 10 ‐ Ace Power Matara 0.0172 11 ‐ Ace Power Horana 0.0172 12 ‐ AES Kelantissa (Pvt.) Ltd CC 0.0691 13 ‐ Heladanavi (Pvt) Ltd 0.0649 14 ‐ ACE Power Embilipitiya 0.0649 15 ‐ Kerawalapitiya CC 0.1674
Approximate Operating Margin (EFgrid,OM): 0.7818 Build Margin 2009
Step 4: Identify the cohort of power units to be included in the build margin
Date Maximum Annual No. Power Plant Capacity Power Generation Commissioned (GWh/yr) MW GWh/Yr 1 old laxapana 1950 50 438 2 Kelantissa steam power units 1962 40 350 3 inginiyagala 1963 11 96 4 wimalasurandra 1965 50 438 5 polpitiya 1969 75 657 6 uda walawe 1969 6 53 7 new laxapana 1974 100 876 8 ukuwela 1976 38 333 9 Kelantissa old gas turbines 1980 96 841 10 Bowatenna 1981 40 350 11 Canyon hydro 1983 60 526 12 Sapugaskanda old diesel 1984 72 631 13 victoria 1985 210 1,840 14 kotmale 1985 201 1,761 15 randenigala 1986 38 333 16 nilambe 1988 3 26 17 Rantambe 1990 49 429 18 Samanalawewa 1992 120 1,051 19 Kelantissa new gas turbines 1997 115 1,007 20 Kelantissa new diesel ext. (4 units) 1997 36 315 21 Lakdhanavi 1997 22.5 197 22 Asia Power Ltd diesel engine 1998 51 447 23 Sapuguskanda new diesel ext. (4 units)1999 1999 72 631 24 Colombo Power Ltd diesel engines 2000 64 561 25 Matara diesel plant 2002 24.8 217 26 Combined cycle plant 1 2002 165 1,445 27 Horana diesel plant Dec‐02 24.8 217 28 Kukule Jul‐03 70 613 29 AES Kelantissa (pvt) Ltd ‐ CC Oct‐03 163 1,428 30 Heladanavi (Pvt) Ltd Oct‐04 100 876 31 Chunnakam Feb‐05 8 70 32 ACE Embilipitiya Mar‐05 100 876 33 Kerawalapitiya CC Sep 08, Mar 09 300 2,628 22,558 Conclusion: Use the last five plants as the greater of 20% or 5 plants 20%: 4,512 maximum annual energy production available. Last 5 Plants: 5,878 Build Margin 2009
Step 5: Calculate the build margin emission factor
Contribution to Approximate B M Annual Max Energy Emissions Factor Weighted Average No. Power Plant Build Margin Emissions (MWh/yr) (CO2/kWh) Emissions (kgCO2/kWh) Energy Supply (%) (kgCO2/kWh) F = (D x E) R = OS = O x R T (∑ of S) 29 AES Kelantissa (pvt) Ltd ‐ CC 1,205,678 24.0% 0.573 0.1376 30 Heladanavi (Pvt) Ltd 739,680 14.7% 0.877 0.1292 31 Chunnakam 60,690 1.2% 0.735 0.0089 32 ACE Embilipitiya 739,680 14.7% 0.877 0.1292 33 Kerawalapitiya CC 2,275,884 45.3% 0.735 0.3332
Capacity Sub‐total End 2009: 5,021,613 100.0% Approximate Build Margin (EFgrid,BM): 0.7381
3434 Combined Margin 2009
Step 6: Calculate the combined margin emissions factor
EFgrid,OM wOM EFgrid,BM wBM EFgrid,CM
kgCO2/kWh % kgCO2/kWh % kgCO2/kWh 0.7818 0.5 0.7381 0.5 0.7600 Annex 4
Monitoring Information
Data to be collected in order to monitor emissions from the small-scale project activity and how this data will be archived:
ID Number Data Type Data Data Measured Recording Proportion How will the data be For how Comment (Project – Variable Unit (m), Frequency of Data to archived long is Date) Calculated be (electronic/paper) archived (c), or Monitored data to be Estimated (e) kept
W-mm- Wey Metered kWh M Monthly 100% Electronically and Two years Data will be yyyy Ganga electricity paper records after the last aggregated project supplied to issuance of centrally on electricity the grid. VERRs for monthly output Double each project basis checked with CEB Invoices.
36
ANNEX 5
CDM-SSC-PDD Small Scale Hydropower Project: Way Ganga Verification Totals Monitoring Period: 01 Jun 2004 - 31 Aug 2009
Electricity Generated EFgrid,CM ERRs Monitoring Period Project kWh kgCO2/kWh kgCO2e tCO2e 01 Jun - 31 Dec 2004 Way Ganga Project 13,022,170 0.6988 9,100,521 9,100 01 Jan - 31 Dec 2005 Way Ganga Project 19,657,084 0.7425 14,594,475 14,594 01 Jan - 31 Dec 2006 Way Ganga Project 22,497,700 0.7425 16,703,500 16,703 01 Jan - 31 Dec 2007 Way Ganga Project 17,286,423 0.7425 12,834,369 12,834 01 Jan - 31 Dec 2008 Way Ganga Project 27,440,950 0.7408 20,328,019 20,328 01 Jan - 31 Aug 2009 Way Ganga Project 12,412,894 0.7600 9,433,202 9,433 Project Verification Totals: 112,317,221 82,992 ERR Calculations
Monitoring Period: 01 Jun - 31 December 2004
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 13,022,170 0.6988 9,100,521 9,100 ERR Calculations
Monitoring Period: 01 January- 31 December 2005
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 19,657,084 0.7425 14,594,475 14,594 ERR Calculations
Monitoring Period: 01 January- 31 December 2006
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 22,497,700 0.7425 16,703,500 16,703 ERR Calculations
Monitoring Period: 01 January- 31 December 2007
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 17,286,423 0.7425 12,834,369 12,834 ERR Calculations
Monitoring Period: 01 January- 31 December 2008
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 27,440,950 0.7408 20,328,019 20,328 ERR Calculations
Monitoring Period: 01 January- 31 August 2009
Electricity Generated EFgrid,CM ERRs Project kWh kgCO2/kWh kgCO2e tCO2e Way Ganga Project 12,412,894 0.7600 9,433,202 9,433