PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 02
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CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-PDD) Version 02 - in effect as of: 1 July 2004)
CONTENTS
A. General description of project activity
B. Application of a baseline methodology
C. Duration of the project activity / Crediting period
D. Application of a monitoring methodology and plan
E. Estimation of GHG emissions by sources
F. Environmental impacts
G. Stakeholders’ comments
Annexes
Annex 1: Contact information on participants in the project activity
Annex 2: Information regarding public funding
Annex 3: Baseline information
Annex 4: Monitoring plan
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SECTION A. General description of project activity
A.1 Title of the project activity: Mahatma Gandhi Hydro Electric Tail Race Hydro Power Project of APPL, India
A.2. Description of the project activity: The purpose of the project activity, proposed by Ambuthirtha Power Private Limited (APPL) is to generate electricity by using the renewable hydro resources to meet the acute shortage of energy in the region. The development of the project activity would reduce the Green House Gas (GHG) emissions produced by the state grid mix, which is dominated by thermal power plants supplying electricity to the state grid.
The project activity comes under the Sharavathy Valley Power Development Area along the river Sharavathy having a rainfall catchment area of 2274 m2. The Sharavathy valley comprises of 4 power generating stations viz.
1. 55 MW Linganamakki dam power house 2. 144 MW Mahatma Gandhi Hydro Electric (MGHE) station 3. 1035 MW Sharavathy Generating Station (SGS) 4. 240 MW Sharavathy tail race generating station
The project activity is a small containment run-of-the river project which envisages construction and operation of small hydro power generating plant of 22.0 MW capacity at the down-stream of the existing MGHE station and upstream of the existing SGS. The project activity contemplates utilisation of: • Head available between existing MGHE station and Sharavathy station • Tail race discharge from existing MGHE station • Water inflows from independent catchment of Sharavathy river and Talakallale stream • Water released from Jog Falls The head available is approx. 70.5 m resulting in power potential of 22.0 MW. The project activity would generate approximately 113.36 million kWh electricity per annum and sell it to Karnataka Power Transmission Corporation Limited (KPTCL) through a Power Purchase Agreement (PPA).
Project’s contribution to sustainable development
Ambuthirtha Power Private Limited (APPL), owner of the project activity, believes that the project activity would greatly contribute to the sustainable development of the host country (India). Government
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of India has stipulated the following indicators for sustainable development in the interim approval guidelines1 for CDM projects.
Social well being Economic well being Environmental well being Technological well being
The project activity has excellent contribution towards sustainable development and addresses the key issues:
Social well being:
The project activity has already and would in the future result in the enhanced employment of the local people during the construction and operation phases. It has already and would further help to enhance the skills of the labour in the area by training them in different technical areas. The project activity also would not result in any sort of displacement of local people.
The project proponent has initiated various measures to enrich the lives of the local people in the areas of Education, Health, Computerization and Spirituality. Some of these measure are:
1. Steps have been taken to set up a computer lab in the local college which will ensure that the graduating students don't bear the burden of computer illiteracy while stepping into todays age of advanced computerisation.
2. A study of the local area revealed that many young students between the ages of 8-17 are dropping out of the schooling system primarily due to long travel (walk) distances between their remote villages and the school which is further compounded as we are in a heavy monsoon area and strong downpours force parents to not send their wards to schools during those months. The project proponents have initiated steps to provide free transportation to these children to and from school so that their education continues unhindered.
3. It was also noticed that the local area had no full fledged medical facilities and the nearest one was about 10 kms away which could prove difficult many a times during emergencies. The project proponents are exploring as to how to set up a Clinic that would provide free consultation and medicines to the local inhabitants.
1 Ministry of Environment and Forest web site : http://envfor.nic.in:80/divisions/ccd/cdm_iac.html
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4. The project proponents have already extended financial support to a local effort of setting up a place of worship which had come to a standstill due to paucity of funds. Spirituality is seen to bring lot of solace to the local residents and that was the main reason the project proponents decided to ensure that this place of worship does get built.
Economical well being:
The project activity has already and would further create business opportunity for local stakeholders such as bankers, consultants, suppliers, manufacturers, contractors, shopkeepers, providers of transportation facilities etc. Also the power supplied by project activity is cheaper than that supplied by most of the other IPPs leading to direct economic benefit for the state government which due to acute shortage is forced to import power at very high landed rates . The project activity would contribute to the economic well being in the region.
Environmental well being Since, the project activity would use renewable hydro resources for power generation; it would not lead to any emissions in the environment. The project activity is a step towards environmental sustainability by saving exploitation and depletion of a natural, finite and non-renewable resource like coal/gas. The power generated by project activity would be mainly supplied to the metropolitan city of Bangalore. Bangalore suffers from rolling power break downs in peak periods during which large numbers of diesel generators are turned on. Project activity would definitely help to reduce these break downs leading to reduction in use of diesel generators, hence reducing the associated release of carbon dioxide, carbon monoxide, soot etc. The project proponents have reengineered the project to such an extent that the forest land requirement was halved from its original plan. Additionally the proponents along with the local forest officials have already afforested in another area the number of trees cut for the construction of this project clearly demonstrating the eco awareness of the project company Technological well being The technology selected for the power project is highly efficient one, using , latest designs from GE, Francis type turbines and proven world class imported generators
This demonstrates that the project activity contributes to the sustainable development.
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A.3. Project participants: Project owner : Ambuthirtha Power Private Limited
Project promoter : Suchindra Investments Private Limited
Annex I Project Participant / : Yet to be finalised carbon credit buyer
Contact information of the project participants involved in the project activity is provided in the Annex 1 of this document.
A.4. Technical description of the project activity:
A.4.1. Location of the project activity: The project activity is located in Talakallale village, Sagar taluk, Shimoga district. The nearest railway station is at Talaguppa which is about 15 km from the plant and the nearest airport is 400 km away at Bangalore.
A.4.1.1. Host Party(ies): India
A.4.1.2. Region/State/Province etc.: Karnataka
A.4.1.3. City/Town/Community etc: Jog Township and Kargal
A.4.1.4. Detail of physical location, including information allowing the unique identification of this project activity (maximum one page): The project is located downstream of existing MGHE station and upstream of Sharavathy generation station. Water from tail race discharge released from MGHE power station, flows from independent catchment of Sharavathy river and Talakalalle stream and water released from the ‘Jog Falls’ would be available for generation of power. The work site is easily accessible from ‘Jog Falls’ which is about 8 km. The road is in good condition, suitable for transportation of construction material and equipments.
The geographical location of Shimoga district is detailed in the maps below
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A.4.2. Category(ies) of project activity: The project activity is a large scale potential CDM project which fits under the Category 1: Energy Industries (renewable - / non-renewable sources) as per ‘List of Sectoral Scopes’, Version 03.
A.4.3. Technology to be employed by the project activity: The various project components proposed are:
• Main dam on river Sharavathy
• Trench weir across Talakallale Nala
• Head race tunnel (HRT) having a length of 3200 meter
• Intake structure for diverting dam water into the HRT
• Surge tank
• Pressure shaft/ penstock
• Surface power house-to accomodate 2 units of 11 MW each
• A tail race channel
• Switch yard at the down stream of powerhouse
• Inter-link with existing grid.
It is envisaged to construct a concrete gravity type dam of length 175 m at distance of about 500 m downstream of existing MGHE power house. The maximum height of the dam from the foundation level upto crest level of weir is 22 m. The trench weir would lead water through shaft head to HRT. The HRT is designed as a pressure tunnel to convey 42 m3/sec of tail water from MGHE plant to feed to the project activity at intake structure with gates and trash racks. The HRT is 3.0 km in length and is in modified horseshoe shape with finished diameter of 4.5 m. The water conducting system has surge tank to absorb water hammer effect. The water from surge tank would lead to turbines through pressure tunnel and steel penstocks. The powerhouse is designed as a surface powerhouse. The tail water from the project activity would lead to Sharavathy river valley through draft tube with gates and short tail race channel. The power generated at 3.3 kV would be stepped up to 110 kV and transmitted to 110 kV master unit sub-station at Jog for further transmission.
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The variation in head would be between 67.0 m to 70.5 m. Discharge during monsoon could vary between 30 to 35 m3/sec. Hence, Francis type reaction turbine would be most suitable for this range of head and discharge. The Turbo Generator would be coupled with suitable synchronous generators.
There is no transfer of technology to the host country since the technology is locally available.
A.4.4. Brief explanation of how the anthropogenic emissions of anthropogenic greenhouse gas (GHGs) by sources are to be reduced by the proposed CDM project activity, including why the emission reductions would not occur in the absence of the proposed project activity, taking into account national and/or sectoral policies and circumstances: The project activity, which utilises renewable hydraulic resources would replace conventional energy equivalent of 1133.6 million kWh for a period of 10 years thereby resulting in total 943,474 tons CO2 emission reduction over the 10 year crediting period. No transmission and distribution losses are considered since the project activity would export power at high voltage of 110 kV at a short distance. In the absence of the project activity, equivalent electricity load would have been taken up by the grid mix, which is mainly dominated by fossil fuel based power plants leading to CO2 emissions. Thus the project activity would help in reducing anthropogenic GHG emissions as per the combined margin carbon intensity of the state grid. The project activity would export clean electricity to the fossil fuel dominated grid, thereby resulting in continuous GHG reductions as it would avoid equivalent generation of GHG emissions.
A.4.4.1. Estimated amount of emission reductions over the chosen crediting period:
Total estimated emission reduction of 943,474tons of CO2 by the project activity are expected over the fixed crediting period of 10 years.
Table A.4.4.1 (a)
Sl. No. Operating Years CO2 Emission Reductions (tones of CO2)
1. 2006-2007 94347
2. 2007-2008 94347
3. 2008-2009 94347
4. 2009-2010 94347
5. 2010-2011 94347
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Sl. No. Operating Years CO2 Emission Reductions (tones of CO2)
6. 2011-2012 94347
7. 2012-2013 94347
8. 2013-2014 94347
9. 2014-2015 94347
10. 2015-2016 94347
A.4.5. Public funding of the project activity: No public funding from parties included in Annex I is available to the project activity.
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SECTION B. Application of a baseline methodology
B.1. Title and reference of the approved baseline methodology applied to the project activity: The project activity uses following approved methodology for PDD preparation
Title: “Consolidated baseline methodology for grid-connected electricity generation from renewable sources”.
Reference: UNFCCC approved baseline methodology ACM0002/ Version 01, Sectoral Scope: 1, 3 September, based on the proposal submitted by NM0001, NM00012, NM 0023, NM0024, NM0030, NM0036, NM0043, NM0055.
B.1.1. Justification of the choice of the methodology and why it is applicable to the project activity: This methodology is applicable to grid-connected renewable power generation project activities like the APPL’s grid-connected hydro power project under the following conditions:
1. Project activity should be a run-of-river hydro power plant
The project activity is conceived under renewable energy power plant as a run-of-river project utilizing 70.5 m head available between existing MGHE station and Sharavathy station.
2. Project activity should not involve switching from fossil fuel to renewable energy at the site of the project activity
The project activity comes under the Sharavathy Valley Power Development Area along the river Sharavathy and no fossil fuel based power project existed at site during the pre-project scenario.
3. The geographic and system boundaries for the relevant electricity grid can be clearly identified and information on the characteristics of the grid is available
Project’s electricity system is defined by the spatial extent of the power plants that can be dispatched without significant transmission constraints.
The electricity system in India is divided into five regional grid viz. Northern, Eastern, Southern, Western and North Eastern. These regional grids have minimal interchange of electricity between themselves because of the poor transmission and distribution infrastructure. Karnataka is part of the southern grid which further consists of Andhra Pradesh, Kerala, Tamil Nadu, Pondicherry,
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Lakshadweep and Andaman & Nicobar Islands. These states have their own power generating stations owned by the State Government and private parties and also get power from the Central Government owned power generating stations. Power generated by state owned generation units and private owned generation units is mostly consumed by respective states. The power generated by central sector generation plants is shared by all states forming part of the grid in fixed proportion. This is corroborated by the fact that total energy interchanged by Karnataka in the year 2000-2001 was only 0.6 % of the gross energy generation of 22,5002 GWh and total energy interchanged by Karnataka in the year 2002-2003 was only 2.6 % of the gross energy generation of 21,0003 GWh by the state.
2 http://cea.nic.in/ge_re/2000-01/section-3.pdf- gives gross energy generation for Karnataka for 2000-01 3 Page 71, Section 3- General Review 2002-03, Central Electricity Authority- gives gross energy generation for Karnataka for 2002-03
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Table B.1.1 (a) Interstate transfer of energy 2000-20014
S .No Supplier Purchaser Energy transferred (GWH)
1. Maharashtra Karnataka 101.2
2. Goa Karnataka 34.41
3. Karnataka Goa 0.04
4. Karnataka Andhra Pradesh 2.14
5. Kerla Karnataka 0.28
Total Energy Interchanged 138.07
Table B.1.1 (b) Interstate transfer of energy 2002-20035
S .No Supplier Purchaser Energy transferred (GWH)
1. Kerala Karnataka 0.33
2. Chattisgarh Karnataka 16.47
3. Maharashtra Karnataka 5.90
4. Goa Karnataka 56.40
5. Karnataka Goa 465.00
6. West Bengal Karnataka 2.90
Total Energy Interchanged 547.00
The main reason for these insignificant interstate interchanges is that all the state grids are deficit. The status of energy deficit (%) during the year 2003-04 in the states included in Southern grid was as follows:
Table B.1.1 (c) Energy deficit in states of Southern Grid, 2003-046
4 http://cea.nic.in/ge_re/2000-01/Section%20-5a.pdf–gives the interstate energy exchange for 2002-03
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S. No. State Deficit (%)
1. Andhra Pradesh 2.9
2. Karnataka 13.9
3. Kerala 3.8
4. Tamil Nadu 1.4
Since significant power interchanges between the state grids and regional grids is not expected to take place during the crediting period of the project activity, only the Karnataka state grid has been included in the project electricity system for calculating the emission factor. Also information on characteristics of the selected grid is available through KPTCL.
B.2. Description of how the methodology is applied in the context of the project activity: As per the Approved Methodology ACM0002 the project activity is required to (i) Establish additionality as per “Tool for the demonstration and assessment of additionality” as provided in Annex I: to the Executive Board – 16 meeting report. Details of demonstration of additionality are a part of Section B.3. (ii) Calculate baseline emissions due to displacement of electricity as per the guidance provided in ACM0002/Version 01 dated 3 September 2004. The steps followed and the key information and data used to calculate the baseline emission factor and the baseline emissions thereafter are given below. Baseline emissions due to displacement of electricity The baseline scenario for the project activity would not entail export to an electricity grid (justified in Section B.3) and the baselines emissions would amount to emissions due to equivalent power (22 MW) generated by the operation of grid-connected power plants. Therefore as per the methodology, baseline determination of the project activity has taken into account only the CO2 emissions from electricity generation by the state grid mix that would be displaced due to the project activity.
The baseline emissions and the emission reductions from project activity are estimated based on the quantum of electricity to be generated by the project activity and the Baseline Emission Factor (BEF) of
5 Section 5- General Review 2002-03, Central Electricity Authority –gives the interstate energy exchange for 2002- 03 6 http://powermin.nic.in/indian_electricity_scenario/pdf/SR0205.pdf
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the chosen grid calculated as a combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) factors estimated according to the three steps given below.
Calculation of electricity baseline emission factor
STEP 1. Calculate the Operating Margin emission factor (EF OM, y)
As per Step 1, the Operating Margin emission factor(s) (EF OM, y) is calculated based on one of the four following methods:
1. Simple OM, or 2. Simple adjusted OM, or 3. Dispatch Data Analysis OM, or 4. Average OM.
As per the methodology ‘Dispatch Data Analysis’ (1c) should be the first methodological choice. However, this method is not selected for OM emission factor calculations due to non-availability of data.
‘Simple OM’ (1a) method is applicable to project activity connected to the project electricity system (grid) where the low-cost/must run resources constitute less than 50% of the total grid generation in
(i) Average of the five most recent years, or (ii) Based on long-term normal for hydroelectricity production.
The Simple adjusted OM (1b) and Average OM (1d) methods are applicable to project activity connected to the project electricity system (grid) where the low-cost/must run resources constitute more than 50% of the total grid generation.
APPL conducted a baseline study wherein the power generation data for all power sources in the project electricity system were collected from government/non-government organisations and authentic sources and analysed. The project electricity system – the Karnataka state grid was found to be dominated by fossil fuel based power plants. The low operating cost and must run resources which typically include hydro, geothermal, wind, low-cost biomass, nuclear and solar generation constituted less than 50% of the total grid generation and the data in the Table B-2 illustrates the same.
Table B-2: Power generation Mix of Karnataka for five years Energy Source 1999-00 2000-01 2001-02 2002-03 2003-04
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Total Power Generation (MU) 26117.52 26520.57 28063.94 28754.00 30722.40 Total Low-cost/must run resources7 13001.276 11894.857 10932.709 8993.25 9353.527 Low-cost/must run resources % of49.78 44.85 38.96 31.28 30.45 Total grid generation Hydro % of Total grid generation - Average of the five most recent years – 39.06 %
APPL has therefore adopted the ‘Simple OM’ (1a) method to calculate the Baseline Emission Factor of the chosen grid.
The Simple OM emission factor (EF OM simple, y) is calculated as the generation-weighted average emissions
per electricity unit (tCO2/MWh) of all generating sources serving the system, not including low-operating cost and must-run power plants.
The Simple OM emission factor can be calculated using either of the two following data vintages for years(s) y:
(i) A 3-year average, based on the most recent statistics available at the time of PDD submission, or
(ii) The year in which project generation occurs, if EF OM, y is updated based on ex post monitoring.
APPL has calculated the OM emission factor as per the 3-year average of Simple OM calculated based on the most recent statistics available at the time of PDD submission. The generation data for various power generating stations for the most recent three years are presented in the Annex 3 attached.
The following Table B-3 presents the key information and data used to determine the Simple OM emission factor.
Table B-3: Data used for Simple OM emission factor Parameters 2001-2002 2002-2003 2003-2004
Coal Gas Diesel Coal Gas Diesel Coal Gas Diesel
COEFi,j y- is the CO2 emission coefficient of fuel i (tCO2 / mass or volume unit of the fuel), taking into account the Net Calorific Value (energy content) per mass or volume unit of a fuel i (NCVi), the CO2 emission factor per unit of energy of the fuel I(EFCO2,i), and the oxidation factor of the fuel i (OXIDi).
7 Low-cost/must run resources typically include hydro, geothermal, wind, low-cost biomass, nuclear and solar generation
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NCVi (kcal/kg) 3877 10750 9760 4171 10750 9760 4171 10750 9760 96.1 73.3 74.1 96.1 73.3 74.1 96.1 73.3 74.1 EFCO2,i (tonne CO2/TJ)
OXIDi 0.98 0.995 0.990 0.98 0.995 0.990 0.98 0.995 0.990
1.526 3.277 2.992 1.642 3.277 2.992 1.642 3.277 2.992 COEFi,j y(tonne of CO2/ton of fuel)
Fi ,j, y - Fuel Consumption – is the amount of fuel consumed by relevant power sources j (where j – power sources delivering electricity to the grid, not including low-operating cost and must-run power plants and including imports from the grid). The Fuel Consumption is calculated based on total generation of the relevant power
sources (j) (ΣjGENj,y) , efficiency of power generation with fuel source i (Ei,j)and the Net Calorific Value (energy content) per mass or volume unit of a fuel i (NCVi).
GENj,y is the electricity (MU) delivered to the grid by source j, j refers to the power sources delivering electricity to the grid, not including low-operating cost and must-run power plants, and including imports from the grid. 14281.8 943.57 1466.10 16962.31 1178.18 1103.73 17364.31866.37 800.91 ΣjGENj,y (MU) 0
Efficiency of power generation with fuel source in % (Ei,j) -The most important parameter in calculating the ‘Fuel consumption’ by relevant power sources is the thermal efficiency of the power plant with fuel source i. The methodology requires the project proponent to use technology provider’s nameplate power plant efficiency or the anticipated energy efficiency documented in official sources. The design efficiency is expected to be a onservative estimate, because under actual operating conditions plants usually have lower efficiencies and higher emissions than the nameplate performance would imply. The efficiency of power generation with fuel source is calculated using the most conservative Design Station Heat Rate Value. Ei,j (%) 35.327 45 41.707 35.45 45 41.707 35.45 45 41.707
NCVi (kcal/kg) 3877 10750 9760 4171 10750 9760 4171 10750 9760
Fi ,j, y is the amount of fuel i (in a mass or volume unit, here tons/yr) consumed by relevant power sources j in year(s) y 8967585167739 309744 9865550 209445 233185 1009935 154015 169209 Fi ,j, y (tons/yr) 9 14281.8 943.57 1466.10 16962.31 1178.18 1103.73 17364.31866.37 800.91 ΣjGENj,y (MU) 0
907.49 912.18 915.58 EFOM,simple,y (ton of CO2/MU)
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911.75 EFOM,simple (ton of CO2/MU)
STEP 2. Calculate the Build Margin emission factor (EF BM, y)
As per Step 2 the Build Margin emission factor (EF BM, y) is calculated as the generation-weighted average
emission factor (tCO2/MWh) of a sample of power plants.
The methodology suggests the project proponent to choose one of the two options available to calculate
the Build Margin emission factor EF BM, y
Option 1:
Calculate the Build Margin emission factor EF BM, y ex ante based on the most recent information available on plants already built for sample group m at the time of PDD submission. The sample group m consists of either:
a) The five power plants that have been built most recently, or b) The power plants 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 that sample group that comprises the larger annual generation.
Option 2:
For the first crediting period, the Build Margin emission factor EF BM, y must be updated annually ex post for the year in which actual project generation and associated emissions reductions occur. For subsequent
crediting periods, EF BM, y should be calculated ex-ante, as described in Option 1 above. The sample group m consists of either
a) The five power plants that have been built most recently, or b) The power plants 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 that sample group that comprises the larger annual generation.
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APPL has adopted Option 1, which requires the project proponent to calculate the Build Margin emission
factor EF BM, y ex ante based on the most recent information available on plants already built for sample group at the time of PDD submission. For the project activity under discussion the sample group ‘m’ consists of (a) the 20 % of the power plants supplying electricity to grid that have been built most recently because it comprises the larger annual generation. The data in the Annex 3 illustrates the same. None of the power plant capacity additions in the sample group have been registered as CDM project activities.
The following Table B-4 presents the key information and data used to determine the Simple BM emission factor.
Table B-4: Data used for Simple BM emission factor Parameters 2003-2004
Coal Gas Diesel
COEFi,m,- is the CO2 emission coefficient of fuel i (tCO2 / mass or volume unit of the fuel), taking into account the Net Calorific Value (energy content) per mass or volume unit of a fuel i (NCVi), the CO2 emission factor per unit of energy of the fuel i (EFCO2,i), and the oxidation factor of the fuel i (OXIDi).
NCVi (kcal/kg) 4171 10750 9760
EFCO2,i (tonne CO2/TJ) 96.1 73.3 74.1
OXIDi 0.98 0.995 0.990
COEFi,m (tonne of CO2/ton of fuel) 1.642 3.277 2.992
Where NCVi ,EFCO2,i OXIDi, COEFi,m are analogous to the variables described for the simple OM method above for plants in the sample group m.
Fi ,m, y - Fuel Consumption – is the amount of fuel consumed by relevant power sources m (where m – power sources which are a part of the sample group m delivering electricity to the grid). The Fuel Consumption is calculated based on total generation of the relevant power sources (m) (ΣmGENm,,y) , efficiency of power generation with fuel source i (Ei,m)and the Net Calorific Value (energy content) per mass or volume unit of a fuel i (NCVi).
ΣGENmm,y (MU) 3363.82 866.37 0
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Avg. efficiency of power generation 35.45 45 41.707 with fuel source as (in %)
NCVi (kcal/kg) 4171 10750 9760
Fi ,m, y (tons/yr) 1956451 154015 0
Where GENmm,y (MU) , NCVi ,Fi,m,y, are analogous to the variables described for the simple OM method above for plants in the sample group m.
752.81 BM, EFBM,y (ton of CO2/MU)
STEP 3. Calculate the baseline emission factor (EF y)
As per Step 3 the baseline emission factor EF y is calculated as the weighted average of the Operating
Margin emission factor (EF OM, y) and the Build Margin emission factor (EF BM, y), where the weights w OM
and w BM, by default, are 50% (i.e., w OM = w BM = 0.5), and EF OM, y and EF BM, y are calculated as
described in Steps 1 and 2 above and are expressed in tCO2/MWh.
The most recent 3-years average of the Simple OM and the BM of the base year i.e. 2002-2003 are considered. This is presented in the table below.
Table B-5: Data used for Baseline Emission Factor Parameters Values Remarks (ton of CO2/MU)
Simple OM, EFOM,simple 911.75 Average of most recent 3-years values 752.81 Value of the base year i.e. 2003-2004 BM, EFBM,y (ton of CO2/MU) Baseline Emission Factor, EFelectricity,y 832.28
Calculation of baseline emissions due to displacement of electricity Baseline emissions due to displacement of electricity are calculated by multiplying the electricity
Baseline Emissions Factor (EF y) with the electricity exported to the grid from the project activity.
Electricity generation from the project activity The total power generated and the net power exported to the grid during the crediting period is based on the power project’s capacity, available head, and plant load factor.
The project activity is expected to generate approximately 113.36 million kWh per annum with an average plant load factor of 58.33 %.
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Therefore, a conventional energy equivalent of 1133.6 million kWh for a period of 10 years would be conserved by the project activity. Without the project activity, the same energy load would have been taken up by the state grid mix and CO2 emission would have occurred as per combined margin intensity of grid.
Project Activity There are no project emissions associated with the hydro power project activity.
Leakage The consumption of energy on site and the GHG emission generated during the construction of hydropower project are the indirect on site GHG sources. Considering the life of the power project and the emissions to be avoided in the life span of 50 years, emissions from the above-mentioned sources are too small and hence neglected.
In case of hydro power projects, GHG emissions can also result from inundation of vegetation due to formation of water reservoir. The CDM Executive Board in its 17th meeting requested the Meth Panel to consider the possibility of revising the applicability of hydro-power project activities in methodologies AM0005 and ACM0002 by limiting them to hydro power project activities that have a rate power density equal or higher than 10 W/m2. The project activity utilises 875,000 m 2 forest land area and would generate 22 MW of power. This gives a rate power density of 25 W/m 2 for the project activity, which is more than 10 W/m2 The project activity is small containment run-of-river hydro power project hence, no sources of GHG emissions are identified due to this activity.
However in the baseline scenario GHG emissions would occur on account of fuel extraction, processing, and transport to the thermal power plants supplying electricity to the grid. But no credits on account of reducing these emissions by the project activity are claimed.
Emission Reductions The total net emission reductions due to the project activity are equal to baseline emissions and are presented Section E.6.
B.3. Description of how the anthropogenic emissions of GHG by sources are reduced below those that would have occurred in the absence of the registered CDM project activity: As per the selected methodology ACM0002, the project proponent is required to establish that the GHG reductions due to project activity are additional to those that would have occurred in absence of the
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project activity as per the ‘Tool for the demonstration and assessment of additionality’ Annex-1 to EB 16 Report. Additionality of project activity is discussed further.
Step 0. Preliminary Screening based on the starting date of the project activity
APPL wishes to have the crediting period starting after the registration of their project activity. The project developer began exploring the possibility of sale of carbon credits generated by project activity early in the development cycle (in 2003). The funds expected to be generated against the sale of CERs generated by the project activity were taken into consideration by the financers in their appraisal report. Also the project proponent had started to actively scout for the CDM advisor for the necessary documentation.
Step 1. Identification of alternatives to the project activity consistent with current laws and regulations
Sub-step 1a. Define alternatives to the project activity
It is required to identify realistic and credible alternative(s) that were available to project activity of APPL or similar project developers that provide output or services comparable with the project activity. These alternatives are required to be in compliance with all applicable legal and regulatory requirements.
APPL identified plausible project options, which include all possible courses of actions that could be adopted in order to produce electricity for the end –users of the Karnataka State.
There are five plausible options available to meet the power requirement equivalent to 22.0 MW.
Project Option 1 – Present Grid Mix
In this scenario the end user would get electricity from the current grid mix which consists of a mix of thermal (coal and diesel), hydro, nuclear and other renewable energy based power plants and an equivalent amount of carbon dioxide would be generated at the thermal power generation end.
Project Option 2 – Equivalent capacity (22.0 MW) Coal (fossil fuel) based power plant, supplying power to the present grid mix.
In this scenario the end user would get power from the grid mix consisting of the project option 2 along with the present generation mix. With an increased thermal capacity addition of 22.0 MW coal based power plant, there would be an increase in the amount of carbon dioxide generated by state grid mix for
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equivalent electricity. Such small capacity coal based independent power plants to supply electricity to the grid are not a common practice due to the techno-economic circumstances that cannot be overcome. There is no small size coal based power plant supplying power to the grid and the minimum capacity of the coal-based power plant, which supplies electricity to the state grid is 210 MW8. Therefore, project option – 2 is not an option available with APPL as developer of small size independent power project and hence excluded.
Project Option 3 – Equivalent capacity (22.0 MW) Gas (fossil fuel) based power plant, supplying power to the present grid mix.
In this scenario the end user would get power from the grid mix consisting of the project option 3 along with the present generation mix. With an increased thermal capacity addition of 22.0 MW gas based power plant, there would be an increase in the amount of carbon dioxide generated by the state grid mix for equivalent electricity. The gas based power plants are possible only if the gas is available as fuel. Due to its locational disadvantage, gas as fuel for power generation to the plant is not available. Also there are no gas based thermal power plants supplying electricity to the grid. Hence, this project option 3 is not available with APPL and may be excluded.
Project Option 4 – Equivalent capacity (22.0 MW) Diesel (fossil fuel) based power plant, supplying power to the present grid mix.
In this scenario the end user would get power from the grid mix consisting of the project option 4 along with the present generation mix. With an increased thermal capacity addition of 22.0 MW diesel based power plant, there would be an increase in the amount of carbon dioxide generated by the state grid mix for equivalent electricity. There are diesel based power plants supplying electricity to grid. Hence, this project option 4 is available with APPL.
Project Option 5 – Project activity not undertaken as CDM project activity
In this scenario the end user would get power from the grid mix consisting of the project option 5 along with the present generation mix.
From the above assessment we may conclude that APPL project activity has three other project options available
Project Option 1 – Present Grid Mix
8Raichur Thermal Power Station
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Project Option 4 – 22.0 MW fossil fuel (diesel) based power plant, supplying power to the present grid mix
Project Option 5 – Project activity not undertaken as CDM project activity.
Sub-step 1b. Enforcement of applicable laws and regulations
All the credible options available to APPL are in compliance with legal and regulatory requirements of the host country.
Step 2. Investment analysis OR
Step 3. Barrier analysis.
APPL proceeds to establish project additionality by conducting the Step 3: Barrier Analysis.
APPL is required to determine whether the project activity faces barriers that:
(a) Prevent the implementation of the project activity; and (b) Do not prevent the implementation of at least one of the alternatives through the following sub- steps: Sub-step 3a. Identify barriers that would prevent the implementation of type of the proposed project activity Other Barriers
Organisational barrier
Traditionally, the project promoters had been operating distilleries and have least knowledge and exposure of complications associated with commercial production and sale of electricity. The hydro power project is a steep diversification to power sector economics, where the project promoters have to meet challenges of power policies, delivery/non-delivery of power, techno-commercial problems associated with electricity boards etc. They have to transform and develop expertise to deal with the economics of electricity generation, distribution and dealing with power sector economics, bureaucracy etc.
As a relatively small facility with a maximum output of 22 MW, the project activity faced the barrier of project development costs. Also, the transaction costs for financing are disproportionately high, as is often in the case for low-capacity renewable projects.
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One of the major criteria’s to access financing is that, prospective financiers look for reliable, creditworthy, and firm sources of revenue for the project. Being a small market player, APPL did not have an easy access to the project finance. The loan application by project proponent was rejected by several banks due to non availability of sufficient equity which resulted in significant delay in achieving the financial closure. The project proponent finally managed to secure loan against high collateral including their house. APPL had to provide lenders with an asset cover of 175% of loan amount, although the normal is practice is about 100-125% only.
The project activity is not based on conventional thermal power technology with proper fuel linkage, where the availability of fuel is not a constraint. In hydro power projects the availability of water as per design discharges in always uncertain, which immediately raises the level of perceived risk by prospective financers. Also the domestic financial market in Karnataka has been characterized by high interest rates. The sale of carbon credits generated by project activity was considered before the financer decided to invest in the project activity and that the proceeds from the sale of carbon should only flow into the Trust & Retention Account (controlled by the financial institutions) is a clear and important term of sanction of loan from the financial institutions. The prospect of registering the project activity as a CDM activity has thus helped to establish the project sustainability, it also helped to reduce the project financing risk of the financers and helped the project developer to proceed further.
Institutional Barriers (a) APPL has signed Power Purchase Agreement (PPA) with KPTCL. For their earnings, the project proponents depend on the payment from KPTCL against the sale of electricity to the grid. It is known that the condition of electricity boards in India is not very healthy and it is likely that there would be problems with cash flows of APPL. Total outstanding dues against Karnataka payable to Central Power Sector Utilities (CPSUs) as on 30th November 2004 were 54.45 crores9. Many of the State Electricity Boards have also in the recent past lowered the tariff in sudden moves without proper justification. APPL has thus to take this risk and face this institutional barrier on which they have limited or no control. This situation makes CDM funds even more critical for APPL to maintain cash flow.
(b) The PPA entered between APPL and KPTCL does not provide for deemed generation charges and any minimum guaranteed off take level of power. Therefore a permanent risk to the project activity exists wherein the project has to be shutdown in case of surplus power or off-peak
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situation. The situation has already been experienced by few project developers in Karnataka where KPTCL issued orders to stop generation due to low demand of power across the state during particular time. (c) The MGHE is one of the main water sources for the project activity. Hence the future operation of the project activity would depend on the releases from main MGHE station which is in control of the Karnataka government. Furthermore, the main water storage for this project ie, Linganamakki Dam also stores water for the state’s largest hydro power project (and presently its lifeline) Sharavathy Generating Station (SGS). In the past so many years where the monsoon has been weak and erratic, the government has been releasing water in a controlled way to run MGHE project. This has a major effect on electricity and revenue generation of APPL’s proposed project and is one of the major reason why the project proponents as well as financial institutions and investors have been very keen and insistent to get CDM revenues to augment the financial risk. As per the PPA signed between APPL and KPTCL, 70 % of the total CDM revenue is to be transferred to Karnataka government. Considering the high economic benefits, Karnataka government would support the project’s sustainability by ensuring continuous supply of water, if project activity gets registered as CDM project activity. (d) The project is under construction and the construction cost since the inception has significantly increased by over INR 50 Million due to increase in steel, copper and diesel prices. This is a huge burden on the cash stricken APPL. Early registration and significant advance from the prospective buyer would help to expedite the timely commissioning of the project.
It is estimated that, of the total project proponents who get approval from state government to establish small hydro power projects in Karnataka, only a few are successful in commissioning and operation of the projects due to some of the above mentioned barriers. The data on the Common Practice Analysis (given below) of the small hydro power projects suggests that the barriers discussed are strong enough to hinder growth of the sector. CDM funding would help to mitigate the anticipated financial losses due to various institutional barriers and help to improve the sustainability of the project so that project can generate emission reductions over a greater period of time.
Sub-step (3b). Show that the identified barriers would not prevent a wide spread implementation of at least one of the alternatives (except the proposed project activity):
9 http://powermin.nic.in/indian_electricity_scenario/pdf/SR1104.pdf
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It has been observed in Sub-step 3a that the - project activity has its associated barriers to successful implementation. The barriers mentioned above are directly related to venturing into a new business of export of power to grid through construction of hydro power project and do not inhibit option 1 discussed above.
Step 4-a. Common Practice Analysis
The state of Karnataka has vast potential for development of small hydro power projects. The state has allotted 801.110 MW equivalent of small hydro power projects out of which only 180 MW potential has been commissioned and only 34.211 MW is exported to the grid through private parties. Out of the remaining 145 MW only 25 MW is generated by state government and exported to grid.
Table B.3 (a) Plants owned by private parties which export electricity to grid in Karnataka
S.No Project Capacity (MW)
1. Shivpura 18.0
2. Shahpur 6.6
3. Madhavamantri 3.0
4. Narayanpur 6.6
Total 34.2
This substantiates the fact that the option 5- project activity without CDM benefits is not a widespread proposition for the private parties in similar socio-economic environment of the Karnataka state. In absence of the CDM project activity there would be lesser private sector participation in construction of small run-of-river hydro power projects exporting power to the grid due to the identified barriers. The project activity occurs in only 5 %12 of the similar industries (Independent Power Producers, IPP) and is therefore not a common practice.
Also there is significant difference between the circumstances faced by APPL and the other IPPs who are supplying power to grid by similar project activities.
10 Karnataka Renewable Energy Development Limited 11 Central Electricity Authority, Energy generation, programme and plant load factor: an overview, March 2004 12 Karnataka Renewable Energy Development Limited-80 small hydro power projects were allotted by Govt. of Karnataka
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• The PPAs for other IPPs were signed at a much higher rate of INR 3.66 per kWh as compared to INR 2.9 per kWh for APPL. The comparatively higher returns against the sale of power made the projects financially more viable and attractive.
• Also these projects have been set-up by experienced project proponent having reasonable background of hydro power business.
• Other IPPs being financially prosperous, securing the project funding has been quite easy for them at lower interest rates as compared to the adversity faced by APPL, being a new entrant in the hydro power business.
Step 5. Impact of CDM registration
The benefits and incentives expected due to approval and registration of the project activity as a CDM activity would certainly improve the sustainability of the project activity and would help to overcome the identified barriers (Step 3). For instance the additional revenues through CDM funding could compensate financial losses arising out of lack of water resources for power generation, reduction in power purchase by KPTCL or non-payment of money by KPTCL against sale of electricity.
The corporate decision to invest
in the CDM project activity through equity in additional transaction costs such as preparing documents, supporting CDM initiatives and developing and maintaining M&V protocol to fulfil CDM requirements was guided by the anthropogenic greenhouse gas emission reductions the project activity would result in and its associated carbon financing the project activity would receive through sale of CERs under the Clean Development Mechanism .
Further, with CDM project activity registration, many more private parties in Karnataka would take up similar initiatives under CDM resulting in higher quantum of anthropogenic greenhouse gas emissions reductions.
As per the above-mentioned steps the project activity is additional and the anthropogenic emissions of GHG by sources would be reduced below those that would have occurred in the absence of the registered CDM project activity.
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B.4. Description of how the definition of the project boundary related to the baseline methodology selected is applied to the project activity:
As per the definition of project boundary of ACM0002, the spatial extent of the project boundary includes the project site and all power plants connected physically to the electricity system that the CDM project power plant is connected to.
The project boundary is from the main dam to the point of power supply to nearest substation where the project proponent has a full control. Thus, boundary covers main dam, trench weir, head race tunnel intake structure, surge tank, pressure shaft/ penstock, surface power house, tail race channel and switch yard and all other accessory equipments.
For the purpose of determining the Build Margin and Operating Margin emission factor the project electricity system is limited to power plants owned by state government, private parties and central government which supply electricity to the Karnataka state grid. The justification for the same is given in section B.1.1.
Flow chart and project boundary is illustrated in the following Figure:
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Mahatma Project Boundary Gandhi Hydro Electric Project (MGHE) Water Flow
MGHE Tail Race Hydro Sharavathy Project Generating Station
Electricity to Auxiliary state grid consumption
Electricity to end-user
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B.5. Details of baseline information, including the date of completion of the baseline study and the name of person (s)/entity (ies) determining the baseline: Date of completion of baseline study: 23/02/2005
Ambuthirtha Power Private Limited has determined the baseline for the project activity. The entity is a project participant listed in Annex-I where the contact information has also been provided.
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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: June 2004
C.1.2. Expected operational lifetime of the project activity: 50 years and 0 months
C.2 Choice of the crediting period and related information:
C.2.1. Renewable crediting period
C.2.1.1. Starting date of the first crediting period: >>
C.2.1.2. Length of the first crediting period: >>
C.2.2. Fixed crediting period:
C.2.2.1. Starting date: June 2006 (tentative)
C.2.2.2. Length: 10 years and 0 months
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SECTION D. Application of a monitoring methodology and plan
D.1. Name and reference of approved monitoring methodology applied to the project activity: The project activity uses “Consolidated monitoring methodology for zero-emissions grid-connected electricity generation from renewable sources”.
Reference: UNFCCC approved baseline methodology ACM0002/ Version 01, Sectoral Scope: 1, 3 September, based on the proposal submitted by NM0001, NM00012, NM 0023, NM0024, NM0030, NM0036, NM0043, NM0055.
D.2. Justification of the choice of the methodology and why it is applicable to the project activity: The monitoring methodology is used in conjunction with the approved baseline methodology ACM0002- “Consolidated baseline methodology for grid-connected electricity generation from renewable sources”. The applicability criteria for the approved baseline methodology ACM0002 and approved monitoring methodology ACM0002 are identical and have been justified in section B.1.1
The methodology requires the project participant to monitor power generation units exported to the grid. Since the project activity is a grid connected renewable hydro power project, emission reduction quantity is dependent on the net units exported to the grid, which would avoid generation of equivalent power by the carbon intensive grid mix. Therefore the project activity’s monitoring requirements are in line with the ‘Approved monitoring methodology ACM002’ which is suitable monitoring methodology applicable for the project activity.
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D.2. 1. Option 1: Monitoring of the emissions in the project scenario and the baseline scenario
D.2.1.1. Data to be collected in order to monitor emissions from the project activity, and how this data will be archived:
ID number Data Source of Data Measured (m), Recording Proportion How will the Comment (Please use variable data unit calculated (c) frequency of data to data be numbers to or estimated (e) be archived? ease cross- monitored (electronic/ referencing paper) to D.3)
Not applicable
D.2.1.2. Description of formulae used to estimate project emissions (for each gas, source, formulae/algorithm, emissions units of CO2 equ.) Not applicable
D.2.1.3. Relevant data necessary for determining the baseline of anthropogenic emissions by sources of GHGs within the project boundary and how such data will be collected and archived :
ID number Data Source of data Data Measured (m), Recording Proportion How will the data be Comment (Please use variable unit calculated (c), Frequency of data to archived? numbers to estimated (e), be (electronic/ paper) ease cross- monitored referencing to table D.3)
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1. EGy Electricity KPTCL MWh Directly Hourly 100% Electronic supplied Measured to the grid by the project activity 2. CO2 tCO2/ Calculated Once at the 100% Electronic Calculated as weighted sum of OM EFelectricity,y emission MWh beginning and BM emission factors factor of of a crediting the grid period 3. CO2 t CO2/ Calculated Once at the 100% Electronic Calculated as Step 1 of AM0015 EFOM,Simple,y operating MWh beginning margin of a crediting emission period factor of the grid 4. EFBM,y CO2 build t CO2/ Calculated Once at the 100% Electronic Calculated as Step 1 of AM0015 margin MWh beginning emission of a crediting factor of period the grid 5. Fi,j,y Amount KPTCL Tons Calculated Once at the 100% Electronic Calculated based on the Total power of fossil beginning generation, Average Net Calorific fuel i, of a crediting Value of the Fuel used and the consumed period Designed Station Heat Rate data of by each power plants of UP grid power source/ plant in year y
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6. COEFi,j,y CO2 IPCC/local t CO2 / Standard Once at the 100% Electronic Calculated based on the IPCC default emission ton of /Calculated beginning value of the Emission Factor, Net factor of fuel of a crediting Calorific Value and Oxidation Factor each fuel period of the Fuel used by the power plants type i, of UP grid 7. GENj,y Electricity KPTCL MWh/ - Once at the 100% Electronic Obtained from authentic and latest delivered annum beginning local statistics to the grid of a crediting by power period source j in year y
D.2.1.4. Description of formulae used to estimate baseline emissions (for each gas, source, formulae/algorithm, emissions units of CO2 equ.) With reference to ACM0002 baseline emissions are estimated as under
Calculation of electricity baseline emission factor
An electricity baseline emission factor (EF electricity, y) is calculated as a combined margin (CM), consisting of the combination of operating margin (OM) and build margin (BM) factors according to the following three steps. Calculations for this combined margin is based on data from an official source (where available) and made publicly available.
STEP 1. Calculation of the Operating Margin emission factor(s) (EF OM, simple, y)
Simple OM approach has been chosen for calculations since the low-cost/must run resources constitutes less than 50% of total grid generation in the KPTCL grid mix, Simple OM factor is calculated as under.
EF OM, simple, y is calculated as the average of the most recent three years (2000-2001, 2001-2002 & 2002-2003)
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EFOM ,simple, y = ∑ Fi, j, y ×COEFi, j / ∑ GEN j, y i, j j where
COEF i, j - is the CO2 emission coefficient of fuel i (t CO2 / mass or volume unit of the fuel), calculated as given below and
GEN j, y - is the electricity (MWh) delivered to the grid by source j
F i, j, y - is the amount of fuel i (in a mass or volume unit) consumed by relevant power sources j in year(s) y, calculated as given below j -refers to the power sources delivering electricity to the grid, not including low-operating cost and must-run power plants, and including imports from the grid
The Fuel Consumption F i, j, y is obtained as
GEN ×860 ∑ j, y F = j ∑ i, j, y NCV × E i i i, j where
GEN j, y - is the electricity (MWh) delivered to the grid by source j
NCV i - is the net calorific value (energy content) per mass or volume unit of a fuel i
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The CO2 emission coefficient COEF i is obtained as
COEF = NCV × EF × OXID i i CO 2 ,i i where
NCV i -is the net calorific value (energy content) per mass or volume unit of a fuel i
EFCO2,i -is the CO2 emission factor per unit of energy of the fuel i
OXID i -is the oxidation factor of the fuel
STEP 2. Calculation of the Build Margin emission factor (EF BM, y)
It is calculated as the generation-weighted average emission factor (t CO2/MWh) of a sample of power plants m of grid, as follows:
EF BM , y = ∑ Fi,m , y × COEF i ,m / ∑ GEN m , y i ,m m where
F i, m, y, COE F i ,m and GEN m, y - are analogous to the variables described for the simple OM method above for plants m.
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Considered calculations for the Build Margin emission factor EF BM, y as ex ante based on the most recent information available on plants already built for sample group m of KPTCL at the time of PDD submission. The sample group m consists of the 20 % of power plants supplying electricity to grid that have been built most recently, since it comprises of larger annual power generation. (Refer Annex 3)
Further, none of the power plant capacity additions in the sample group have been registered as CDM project activities.
STEP 3. Calculate the electricity baseline emission factor (EF electricity, y)
It is calculated as the weighted average of the Operating Margin emission factor (EF OM, simple, y) and the Build Margin emission factor (EF BM, y):
EF electricit y , y =W OM × EFOM ,Simple , y × W BM × EF BM , y
where the weights w OM and w BM, by default, are 50% (i.e., w OM = w BM = 0.5), and EF OM, Simple, y and EF BM, y are calculated as described in Steps 1 and 2 above and are expressed in t CO2/MWh.
BEelectricity, y = EFelectricity, y ×EGy where
BE electricity, y - are the baseline emissions due to displacement of electricity during the year y in tons of CO2
EG y- is the net quantity of electricity generated by the project activity during the year y in MWh, and
EF electricity, y- is the CO2 baseline emission factor for the electricity displaced due to the project activity in during the year y in tons CO2/MWh.
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D. 2.2. Option 2: Direct monitoring of emission reductions from the project activity (values should be consistent with those in section E).
D.2.2.1. Data to be collected in order to monitor emissions from the project activity, and how this data will be archived:
ID number Data Source of Data Measured (m), Recording Proportion How will the data Comment (Please use variable data unit calculated (c), frequency of data to be archived? numbers to estimated (e), be (electronic/ ease cross- monitored paper) referencing to table D.3)
Not applicable
D.2.2.2. Description of formulae used to calculate project emissions (for each gas, source, formulae/algorithm, emissions units of CO2 equ.): Not applicable
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D.2.3. Treatment of leakage in the monitoring plan
D.2.3.1. If applicable, please describe the data and information that will be collected in order to monitor leakage effects of the project activity ID number Data Source of Measured (m), Recording Proportion How will the data Comment Data (Please use variable data calculated (c) frequency of data to be archived? unit numbers to or estimated (e) be (electronic/ ease cross- monitored paper) referencin g to table D.3)
Not applicable
D.2.3.2. Description of formulae used to estimate leakage (for each gas, source, formulae/algorithm, emissions units of CO2 equ.)
Not applicable
D.2.4. Description of formulae used to estimate emission reductions for the project activity (for each gas, source, formulae/algorithm, emissions units of CO2 equ.) Formula used for estimation of the total net emission reductions due to the project activity during a given year y is as under.
ERy = BEelectricity, y − PE y − Ly
where
ER y- are the emissions reductions of the project activity during the year y in tons of CO2
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BE electricity, y- are the baseline emissions due to displacement of electricity during the year y in tons of CO2
PE y- are the project emissions during the year y in tons of CO2
L y – are leakage emissions during the year y in tons of CO2
Since PE y and L y are equal to zero
ERy = BEelectricity, y
D.3. Quality control (QC) and quality assurance (QA) procedures are being undertaken for data monitored
Data Uncertainty level of data Explain QA/QC procedures planned for these data, or why such procedures are not necessary. (Indicate table and (High/Medium/Low) ID number e.g. 3.-1.; 3.2.) 1. EGy - Electricity Low Electricity meters would be properly maintained with regular testing and calibration schedules supplied to the grid developed as per the technical specification requirements to ensure accuracy. by the project activity 2. EFelectricity,y - CO2 Low This is calculated emission factor of the grid 3. EFOM,Simple,y - Low This is calculated CO2 operating margin emission factor of the grid 4. EFBM,y - CO2 Low This is calculated build margin emission factor of the grid
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5. Fi,j,y / Fi,m,y - Low This is calculated Amount of fossil fuel i, consumed by each power source/ plant in year y
6. COEFi,j,y / Low This is calculated COEFi,m,y - CO2 emission factor of each fuel type i, 7. GENj,y / GENm,y Low This is based on authentic grid data. - Electricity delivered to the grid by power source j/m in year y
D.4 Please describe the operational and management structure that the project operator will implement in order to monitor emission reductions and any leakage effects, generated by the project activity
APPL would implement an operational and management structure in order to monitor emission reductions generated by the project activity.
The Shift Incharge would be assigned the responsibility of monitoring and recording of electricity supplied to the grid as per the monitoring plan (ref. Annex 4). On a weekly basis, the monitoring reports would be checked and discussed with Project Manager. In case of any irregularity observed, necessary action would be taken immediately. On monthly basis, these reports would be forwarded to the management.
The Project Manager would be a qualified engineer with 15-20 years experience in power industry and all the Shift Incharges would also be qualified engineers with 10-12 years of experience in power industry. They would undergo an exhaustive training programme, including plant operations, data monitoring, report generation etc. This template shall not be altered. It shall be completed without modifying/adding headings or logo, format or font. PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 02
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D.5 Name of person/entity determining the monitoring methodology:
Ambuthirtha Power Private Limited has determined the monitoring plan for the project activity. The entity is a project participant listed in Annex-I where the contact information has also been provided.
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SECTION E. Estimation of GHG emissions by sources
E.1. Estimate of GHG emissions by sources: Being a hydro power project, no direct anthropogenic emissions by sources of greenhouse gases within the project boundary are identified.
E.2. Estimated leakage: The emissions outside the project boundary due to project activity are estimated to be nil. Please refer section B.2 for the details of the same.
E.3. The sum of E.1 and E.2 representing the project activity emissions: The sum is zero
E.4. Estimated anthropogenic emissions by sources of greenhouse gases of the baseline:
Baseline emissions (BE electricity, y) are calculated using the formula:
BEelectricity, y = EFelectricity, y ×EGy
where EG y = 113.36 million kWh/annum
EF electricity, y = 0.492 kg CO2/kWh
The net annual baseline emissions are = 94,347 t CO2
E.5. Difference between E.4 and E.3 representing the emission reductions of the project activity:
Emissions reductions (ER y) are calculated using formula:
ERy = BEelectricity, y − PE y − Ly
Since project emissions (PE y) and leakages (L y) are zero, the emission reductions are equal to baseline emissions as given in table below.
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E.6. Table providing values obtained when applying formulae above: Table E.6 (a) Emission reductions
Sl. No. Operating Baseline Project CO2 Emission Reductions
Years Emissions (tCO2) Emissions (tCO2) (tCO2) 0 1. 2006-2007 94347 94347 0 2. 2007-2008 94347 94347 0 3. 2008-2009 94347 94347 0 4. 2009-2010 94347 94347 0 5. 2010-2011 94347 94347 0 6. 2011-2012 94347 94347 0 7. 2012-2013 94347 94347 0 8. 2013-2014 94347 94347 0 9. 2014-2015 94347 94347 0 10. 2015-2016 94347 94347
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SECTION F. Environmental impacts
F.1. Documentation on the analysis of the environmental impacts, including transboundary impacts: Assessment of Environmental Impact due to the project activity has been carried out. A brief summary of the Environmental Impact Assessment (EIA) report is available as Enclosure-I.
F.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: Host party regulations require APPL to obtain environmental clearance in the form of “No objection Certificate” from the State Pollution Control Board and carry out EIA studies to understand if there are any significant environmental impacts. APPL has carried out EIA study and obtained necessary statutory clearances based on the EIA study. The study indicated that the impacts are not significant.
The following consents were obtained from the State Pollution Control Board for the project activity:
• ‘Consent to Establish’ under Air (Prevention and Control of Pollution) Act, 1981 (Central Act 14 of 1981) as amended
• ‘Consent to Establish’ under the Water (Prevention and Control of Pollution) Act, 1974 (Central Act 6 of 1974) as amended.
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SECTION G. Stakeholders’ comments >>
G.1. Brief description how comments by local stakeholders have been invited and compiled: Stakeholders of this project includes the government and non-government parties, local population, NGO’s, social organisations of that region etc., who are involved in the project activity with different roles and at different stages. All the necessary clearances from the government parties have been obtained.
Notification (in English and the local vernacular language) through regional and national newspapers for public hearing giving a one month notice to attend was brought out requesting the stakeholders to participate and communicate any suggestions/objections regarding the project activity in writing. The brief summary of the project was circulated to all the stakeholders before the hearing. On the day of hearing, APPL representatives presented the salient features of the company and the project activity to the stakeholders and requested their suggestions/objections. The opinions expressed by the stakeholders were recorded and are available on request.
G.2. Summary of the comments received: The stakeholders for the project activity and summary of comments received from them:
Stakeholder Summary of Comments/responses
Karnataka Power Transmission As a buyer of the power, the KPTCL is a Corporation Limited (KPTCL) major stakeholder and they hold the key to the commercial success of the project activity. Power Purchase Agreement (PPA) with KPTCL has been signed.
Ministry of Environment and Forest MoEF vide their letter number J- (MoEF), Govt. of India 12011/51/2001-IA-I has accorded environmental clearance as per the EIA notification of Govt. of India. Also the 875,000 m2 forest land has been diverted in favour of the project owner vide letter number A/16/1/KAR/91/HEP.
Water Resources Secretariat (WSC), WSC has also accorded the approval for Government of Karnataka establishment of the project activity.
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Karnataka State Pollution Control Board KSPCB vide their letter number (KSPCB) KSPCB/CFE-CELL/F- 3/AEO/EPH/SUCHINDRA/2000- 2001/290 has accorded ‘Consent for Establishment and Clearance’ from Water and Air Pollution Control point of view.
Karnataka Renewable Energy KREDL vide their official memorandum Development Limited (KREDL) number KRED/06/MGHE/2001/856 has accorded technical clearance for establishing the project activity.
KPCL Employees Union KPCL Employee Union felt that a private entity should not be allowed to operate the hydro power project even though this project poses no environment hazard
Local People The project should generate local employment and help ease the power shortage situation and has no effect on the migratory pattern of the local animals nor poses any rehabilitation problems
G.3. Report on how due account was taken of any comments received: No major concerns were raised during the consultation with stakeholders and satisfactory answers were provided to the issues raised by them.
As per the government regulation KPCL cannot operate the projects which are less than 25 MW so the concern raised by KPCL employees is unfounded.
Important clauses mentioned in the project documents, clearances, power purchase agreement etc., were/would be considered by the project owners.
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Annex 1
CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY
Organization: M/s Ambuthirtha Power Private Limited Street/P.O.Box: M G Road Cross Building: 21/19, II Floor, Craig Park Road City: Bangalore State/Region: Karnataka Postfix/ZIP: 560001 Country: India Telephone: 91 80 25597616/25599654/25595315 FAX: 91 80 25597617 E-Mail: [email protected] URL: - Represented by: Sanjith S. Shetty Title: Managing Director Salutation: Last Name: Middle Name: First Name: Department: Mobile: Direct FAX: Direct tel: Personal E-Mail: [email protected]
Organization: M/S Suchindra Investments Private Limited Street/P.O.Box: M G Road Cross Building: 21/19, II Floor, Craig Park Road City: Bangalore State/Region: Karnataka Postfix/ZIP: 560001 Country: India Telephone: 91 80 25597616/25599654/25595315 FAX: 91 80 25597617 E-Mail: [email protected] URL: - Represented by: Title: Salutation: Last Name: Middle Name: First Name: Department: Mobile: Direct FAX:
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Direct tel: Personal E-Mail:
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Annex 2
INFORMATION REGARDING PUBLIC FUNDING No public funding from parties included in Annex I is available to the project activity.
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Annex 3
BASELINE INFORMATION
The data of Table 3-1, 3-2, 3-3 and 3-4 given above are used for Simple OM emission factor
(EFOM,simple,y). Table 3-1 : Power Generation Mix of Karnataka from State Generating Stations Sl.No Installed Name of Power Plant Fuel Net Generation in MU . Capacity (MW) 2001-02 2002-03 2003-04 A. State- Thermal13 1 RTPS-I to IV Coal 4x210 5922.03 6079.33 5911.48 2 RTPS-V & VI Coal 210 2253.07 3036.22 2999.46 3 RTPS-VII Coal 210 0 275.55 1504.33 4 Power Purchase-VVNL Diesel 745.971 684.976 523.783 Total- Thermal 8921.071 10076.076 10939.053 B State-Hydro14 1 Sharavathy Hydel 10x103.5 4155.68 2827.11 3261.49 2 Chakra Hydel 0 412.46 455.38 3 Linganamakki Hydel 2x27.5 175.77 111.23 126.93 4 Nagajhari Hydel 3x135+3x150 2393.18 1782.86 1700.84 5 Supa Hydel 2x50 387.9 250.31 234.5 6 Ghataprabha Hydel 2x16 72.47 57.79 63.01 7 Varahi Hydel 2x115 870.85 822.53 696.84 8 Mani Hydel 2x4.5 19.41 17.46 10.62 9 Bhadra Hydel 2x12+1x2 23.67 8.76 4.73 10 Kadra Hydel 3x50 282.55 228.69 214.73 11 Kalmala Hydel 1x0.4 0.13 0.05 0.12 12 Sirwar Hydel 1x1 0.22 0.78 0.17 13 Ganekal Hydel 1x0.35 0.49 0.14 0.07 14 Mallapur Hydel 2x4.5 28.34 0.76 8.46 15 Kodasali Hydel 274.82 213.63 212 3x40+4x60 16 Gerusoppa Hydel 408.25 309.63 355.38 17 Bhadra Right Bank Hydel 1x7.2+1x6 20.66 7.49 3.79 18 Kappadagudda Hydel 9x0.225+11x0.23 5.31 10.86 14.98 19 Almatti Dam Power House Hydel 0 0 0.45 20 Power Purchase-VVNL Hydro 215.749 250.234 191.347 Total- Hydro 9335.449 7312.774 7555.837 State Sector Total 18256.52 17388.85 18494.89 Data Source: KPTCL
13 Installed capacity as on 31st August'2004
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Table 3-2 : Power Generation Mix of Karnataka from Independent Power Producers Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 A IPP15 1 Rayalseema Alkalies Diesel 27 189.08 61.8 41.63 2 TATA Electric Company Diesel 81 531.05 356.95 235.5 3 Taneer Bhavi Power Company Gas (Naptha) 220 943.57 1178.18 866.37 Total- IPP(Major) 1663.7 1596.93 1143.5 Data Source: KPTCL
Table 3-3 : Power Generation Mix of Karnataka from Private Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 A IPP-Mini-Hydel 1 ITPL 2.37 1.38 0.66 2 EDCL 24.48 22.87 20.76 3 Murudeshwar Power Corporation Ltd. 48.54 37.91 37.17 4 Bhoruka Power Corporation Ltd. 27 27.3 23.59 5 Bhoruka Power (Shahapur) 0 0 2.86 6 S.M.I.O.R.E 28.46 11.98 4.45 7 Thungabhadra Steel Products 0.39 0.37 0.31 8 Amogha Power Projects 1.96 2.8 1.81 9 Atria Power Corporation Ltd. 21.34 79.29 54.46 10 Vijaylakshmi Hydro Power Ltd. 1.33 1.83 11 Moodatyagil Power Pvt. Ltd. 0.32 0.52 12 Maruthi Power (Kabini) 1.65 13 Maruthi Power (Hemabhathi) 0.5 14 Kalson Power Tech Ltd. 2.89 15 Graphite India Ltd. 1.31 16 Intrernational Power Corpn. Ltd. 3.32 Total- IPP(Mini-Hydel) 154.54 185.55 158.09 B IPP-Co-generation 1 Ugar Sugar Ltd. Bagasse 69.9 51.66 55.48 2 Shamanur Sugars Ltd. Bagasse 100.02 98.31 111.9 3 Shree Renuka Sugars Ltd. Bagasse 34.61 26.33 45.96 4 Bannari Amman Sugars Ltd. Bagasse 57.71 73.82 76.27 5 ICL Sugars Ltd. Bagasse 13.54 17.17 14.19
14 Installed capacity as on 31st August'2004 15 Installed capacity as on 31st March'2003
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Table 3-3 : Power Generation Mix of Karnataka from Private Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 6 Prabhulingeshwara Sugars Bagasse 33.66 38.34 34.07 7 Dandeli Ferro Alloys Limited 4.45 3.57 0 8 Jamkhandi Sugars Limited 0.62 7.14 13.47 9 GEM Sugars 0 8.29 27.59 10 Ryatsara Sahakari S.K.N 2.87 5.69 2.76 11 Devengare Sugar Co. Ltd. 0 0 1.67 Total- IPP(Co-Generation) 317.38 330.32 383.36 C IPP-Biomass 1 Mallavali Power Plant Rice Husk 13.11 21.78 26.47 Coffee Husk, 2 South India Paper Mills Rice Husk & 12.23 23.55 13.11 Copra Shells 3 Bhagarampur Solvets 3.22 4 R.K.Powergen 9.75 5 Samson Distillisers 0.43 Total- IPP(Biomass) 25.34 45.33 52.98 D IPP-Wind 1 Cepco Wind Farm 7.35 20.27 23.57 2 Topaz Wind Farm 0.93 1.86 2 3 Enercon Wind Farm 2.92 23.21 26.95 4 Prabhat Agri biotech Ltd. 1.08 1.05 5 Panarna Business Centre 0 1.24 6 Panarna Credit & Capital 0.66 7 Texmo Precision and Castings 0 2.87 8 Siddaganga Oil Extractions 0 2.86 9 Fiza Developers and Inner Trade 0.01 2.83 10 Suttatti Enterprise 0 2.48 11 Raja Magnetics Ltd. 0 1.11 12 VXL Systems-II 0.77 13 VXL Systems-I 0.77 14 Kamal Trading Company 0.72 15 Jindal Alluminium-1.9MW 3.23 16 Mayura Steels 0.75 17 Shilpa Medicare 0.64 18 Patel Shanti Steels 0.71 19 Balasaheb IJ Limited 0.69 20 Friends Associate Power Projects 0.74 21 Sharp Pumps (P) Ltd. 0.73 22 Rajnikanth Foundation 0.71 23 RSM Autokast Ltd. 1.49
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Table 3-3 : Power Generation Mix of Karnataka from Private Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 24 Indan Energy Ltd. 1.48 25 MSPL Ltd. Phase-1 1.99 26 Savitha Chemicals 4.82 27 Elveety Industries 0.57 28 Jindal Alluminium-6.6MW 2.57 14.59 29 Ghodawat Pan Masala (Enercon) 11.83 30 Ghodawat Pan Masala-NH 9.46 31 Sanjay D. Ghodawat 1.55 32 Shriram Transport Finance 8.73 33 Shriram City Union Finance 3.89 34 Shriram Investments 8.03 35 Texmo Industries EP2 4.51 36 Enercon-Karnataka 46.08 37 Lovely Fragrances 1.83 38 J.N.Investments 0.81 39 Reliance Energy Ltd. 0.89 19.08 20.08 40 Topaz Investments-1.2MW 2.14 41 Cepco Industries-0.6MW 0 1.2 42 Shilpa Medicare-0.46MW 1.5 43 Mohite & Mohita 4.06 44 NEG Mican 6.99 45 Pallavi Green Power 0.56 46 Supreme Power Company 1.46 47 Dee Dee Enterprises 1.4 48 Royal Energy Company 1.08 49 Rangad minerals and Mining Ltd. 1.15 50 MSPL Ltd. Phase-II 3.61 51 Mansukmal Investments 0.29 52 Reliance-BSES 3.06 53 Encon Services Ltd. 4.34 54 Mahe Ltd. 12.17 55 Prime Lables Ltd. 0.36 56 Savita Chemicals (Encon Group) 2.37 57 Sanjay D. Ghodawat (I & II) 0.01 58 BS Charnabasappa & Sons 0.01 59 Associated Autotex Ancilliaries Ltd. 0 60 Good Luck Syndicate 0.01 61 Ghodawat Pan Masala (VVS) 0.02 62 Star Flexi Pack Industries 0.01 63 Shreya Laxmi Properties 0
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Table 3-3 : Power Generation Mix of Karnataka from Private Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 64 Shraddha Constructions 0 65 VXL Systems 0.6MW (VVS) 0 66 Cepco Industries-1.2MW(VVS) 0 67 Dee Dee Enterprises (Enercon) 2.01 68 Miscellaneous IPPs 26.66 Total- IPP(Wind) 12.09 94.74 269.63 Private Sector Total 509.35 655.94 864.06 Data Source: KPTCL
Table 3-4 : Power Generation Mix of Karnataka from Central Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 A. Central- Thermal 1 NTPC-SR Coal 3255.45 3689.19 3006.56 2 NTPC-ER Coal 846.52 1616.36 571.23 3 NTPC-NVVN 0 0 112.88 4 NTPC-Talcher 2&3 Coal 0 0 835.85 5 NLC Lignite 2004.73 2265.66 2082.99 6 NLC Expansion-I Lignite 0 0 452.41 7 PTCIL 379.92 190.57 819.66 8 PGCIL-SREB 0 297.24 1404.74 Total- Thermal 6486.62 8059.02 9286.32 B Central-Nuclear 1 Madras Atomic Power Station (MAPS) 431.09 158.63 96.9 2 KAIGA Generating Station 627.17 852.1 829.82 Total- Nuclear 1058.26 1010.73 926.72 C Imports from Other Grids SREB 1 KSEB 0 0 0 2 APTRANSCO 2.52 12.56 0 3 TNEB 0 0 0 Sub-Total 2.52 12.56 0 WREB 1 MSEB 0.59 4.19 0 2 Goa 0 1.18 0 3 CSEB 0 0.14 0 4 MPEB 0 7.12 0 5 GEB 0 3.53 0 6 WREB 56.73 0 0 Sub-Total 57.32 16.16 0 Hydro-T.B. Dam
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Table 3-4 : Power Generation Mix of Karnataka from Central Generating Stations Installed Sl.No. Name of Power Plant Fuel Net Generation in MU Capacity (MW) 2001-02 2002-03 2003-04 1 T.B.H.E 29.65 14.75 6.91 Sub-Total 29.65 14.75 6.91 Total- Imports from Other Grids 89.49 43.47 6.91 Central Sector Total 7634.37 9113.22 10219.95 Data Source: KPTCL
The data of Table 3-5 given below are used for Simple BM emission factor (EFBM,y).
Table 3-5: Power Generation data of the Sample Group for Calculation of Built Margin
Year of Sr.No. Power plant name / location Unit No. Fuel Type Capacity MU commissioning
2003- (MW) 2004 1 RTPS-VII 7 Coal 7x210 2003-2004 1504.33 National 2 NTPC-NVVN 2003-2004 112.88 Generation Mix 3 IPP-Wind Wind 2003-2004 178.56 4 IPP-Biomass Biomass 2003-2004 13.4 5 IPP-Mini Hydel Mini Hydel 2003-2004 9.67 6 IPP-Co-generation Co-generation 2003-2004 1.67 7 NLC Expansion-I Lignite 2003-2004 452.41 8 Almatti Dam Power House Hydel 2003-2004 0.45 9 NTPC-Talcher 2&3 3 Coal 2003 835.85 10 IPP-Wind Wind 2002-2003 18.47 11 IPP-Mini Hydel Mini Hydel 2002-2003 2.35 12 IPP-Co-generation Co-generation 2002-2003 27.59 13 Chakra Hydel 2002-2003 455.38 National 14 PGCIL-SREB 2002-2003 1404.74 Generation Mix 15 IPP-Wind Wind 2001-2002 72.6 16 IPP-Biomass Biomass 2001-2002 39.58 17 IPP-Mini Hydel Mini Hydel 2001-2002 56.27 18 IPP-Co-generation Co-generation 2001-2002 16.23 19 NTPC-ER Coal 2001-2002 571.23 Taneer Bhavi Power 20 Naphtha 220 2001-2002 866.37 Company TOTAL 6640.03
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20% of Total Gross Generation 6144.48
Data Source: KPTCL
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Annex 4
MONITORING PLAN
Description of monitoring plan The project activity would have main and backup meters to record the net power supplied to the grid. Meters would be calibrated and marked at regular intervals so that the accuracy of measurement can be ensured all the time.
Key Project Parameters affecting Emission Reductions
Net Power exported to the grid:
The project revenues are based on the net units exported as measured by main metering system and/or backup metering system. The monitoring and verification system would mainly comprise of these meters as far as power export is concerned. KPTCL would be billed by APPL based on joint meter reading promptly following the end of each month for energy supplied.
The general monitoring principles are based on:
Frequency
Reliability
Registration and reporting
Since the emission reduction from the project are determined by the net units exported to the grid (and then multiplying with appropriate emission factor) it becomes important for the project to monitor the net export of power to the grid on real time basis.
Frequency of monitoring
APPL would carry out the hourly data recording. The KPTCL and APPL would jointly read the main and backup metering system on the first day of every month.
Reliability
The amount of emission reduction is proportional to the net electricity supplied to grid by the project activity. The reliability of the monitoring system is governed by the accuracy of the measurement system and the quality of the equipment to produce the result. The project proponent would also ensure quality of the equipment used for monitoring.
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The KPTCL would own, test and maintain the main metering system. The backup metering system shall be installed, tested, owned and maintained by APPL. The main and backup metering system shall be sealed in the presence of both parties. All metering instruments would be electronic trivector meters of accuracy class 0.2 %. All the main and check meters would be tested for accuracy every calendar quarter with reference to a portable meter which shall be of an accuracy class of 0.1 %. When the main metering system and/or backup metering system and/or any component is found to be outside the acceptable limits of accuracy or otherwise not functioning properly, it would be repaired, re-calibrated or replaced, as soon as possible. All instruments would carry tag plates, which indicate the date of calibration and the date of next calibration. Any meter seal shall be broken only by KPTCL’s representative in the presence of APPL’s representative whenever the main or backup metering system is to be inspected, tested, adjusted, repaired or replaced.
Registration and reporting
The KPTCL and APPL shall jointly read the metering system and shall keep the complete and accurate records for proper administration. Hourly data recording by the Shift Incharge will be there. Weekly reports stating the generation would be prepared by the shift incharge and verified by the Plant Manager. In addition to the records maintained by APPL, KPTCL would also monitor the actual power exported to the grid and certify the same.
Verification
The performance of the project would lead to CO2 emission reductions. In other words, the higher the electricity exports to the grid the more would be the emission reductions.
There are two aspects of Verification
[A] Verification of the Monitoring System which includes:
Verification of various measurement and monitoring methods
Verification of instrument calibration methods
Verification of measurement accuracy
[B] Verification of Data collected which includes
Net export of power.
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The project proponent is required to provide the necessary supportive to enable verification of both the monitoring system and the data archived.
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