6_PDD_IGL_07042010 _clean copy

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 1

CLEAN DEVELOPMENT MECHANISM PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 03 - in effect as of: 28 July 2006

CONTENTS A. General description of 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 project activity Annex 2: Information regarding public funding Annex 3: Baseline information

Annex 4: Monitoring plan

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 2 SECTION A. General description of project activity A.1. Title of the project activity: >> Biomass based Cogeneration Project activity taken up by India Glycols Limited at Gorakhpur, U.P. Version 07 Date: 07/12/2010

A.2. Description of the project activity : >> India Glycols Limited (hereafter called project proponent (PP) or IGL) is a leading multi-product Petrochemicals & Specialty Chemicals Company. The Company had established a 200 KL per day Greenfield Distillery plant at Gorakhpur Industrial Development Authority (GIDA), Gorakhpur. The Project Proponent (PP) has installed an evaporator system to treat the liquid effluent (spent wash) generated from the distillery process. The liquid effluent is concentrated in the evaporator system to form concentrated spent wash (slop). The amount of concentrated spent wash (Slops) generated is around 92160 MT per annum. Project Scenario: The project activity is a biomass based cogeneration project activity consisting of two numbers of 47 TPH Slop fired boilers. The project activity utilizes slop (concentrated spentwash) in the slop fired boiler for steam generation. The boilers would be connected to a common steam header which would provide the steam to a 4.0 MW back pressure turbine and 12 MW extraction cum condensing turbine for generation of electricity. The purpose of the project activity is to utilize the Slop (concentrated spent wash) from the evaporator and other biomass as the fuel for the generation of steam and electricity. This is a novel boiler that has been developed for the first time in India for the utilization of concentrated spentwash and generation of steam there from. The PP had envisaged developing a new type of boiler during the year 2004. Due to the fact that Slop fired boiler was being implemented for the first time in India, the PP planned to implement the project activity in phases, wherein in the 1st Phase one number of Slop fired boiler was envisaged to be implemented as a pilot study along with a 4 MW turbine. The 1st Slop fired boiler got successfully demonstrated in December 2007. After this the 2nd Slop fired boiler is being implemented along with the 12 MW turbines. The excess steam due to the 2nd Slop fired boiler will be used as condenser in the 12 MW turbines and the surplus electricity will be exported to the grid after the entire project gets commissioned. The total project activity is expected to be completed in 2010. The boilers produce and will produce steam at a pressure of 42 Kg/cm2 g and at a temperature of 4400 C. Currently, the 4MW turbine use the supersaturated steam from the first boiler. After installation of second boiler the supersaturated steam from both the boilers will be utilized by the 12 MW extraction cum condensing turbine and the 4.0 MW back pressure turbine for generation of electricity.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 3 The 1st 47 TPH Slop fired boiler will generate around 39 TPH. The 2nd Slop fired boiler will generate 39 TPH. 78 TPH of Steam will be supplied to turbines through the common steam header. 60 TPH steam will be supplied to the 12 MW Turbine. Out of the 60 TPH turbine exhaust steam 40 TPH will be used for condensing and 20 TPH exhaust steam at a pressure of 3.5 Kg/cm2 and temperature of 150 0C will be used for process. 18TPH steam will be supplied to 4 MW turbine and the entire exhaust steam at a pressure of 3.5 Kg/cm2 and temperature of 150 0C will be used for process. The gross power generated by 12 MW turbine will be 11.772 MW. The gross power generated by the 4 MW turbine will be 1.575 MW. The total auxiliary electricity consumption will be 17 474 MWh. After meeting the auxiliary electricity consumption of 17 474 MWh and the distillery electricity requirement of 20 772 MWh the net electricity export to the grid will be57 857 MWh. Coal or rice husk will be used in the super heater of the boiler as the supporting fuel in the project activity. The estimated amount of coal that will be used in the project activity will be around 91 TPD (which is around 15%) and the estimated amount of rice husk that will be used in the project activity will be around 205 TPD (which is around 36%). The electricity generated from the project activity will be used for captive consumption and the surplus electricity will be sold to the Uttar Pradesh state Electricity Board (UPSEB). The nearest substation to the project activity is GIDA substation which is at a distance of 1.8 Kms from the project plant. The project activity envisages generating net electricity of around 78 629 MWh per annum of which around 20 772 MWh of electricity per annum will be used for in house consumption and around 57 857 MWh of electricity exported to the grid annually. The Project activity also envisages generating around 78 TPH of steam of which around 40 TPH steam will be used for condensing and around 38 TPH steam will be used for process requirement. The PP has also installed a 35 TPH LIPI boiler fired on rice husk as a stand by to minimize uncertainty associated with the slop fired boiler. There are also 2 numbers of 1250 kVA DG sets which will be used to provide the initial start up required after the shut down of the plant. Both the DG sets will be fired with HSD. The Plant will also import electricity from the grid during the emergency conditions. Pre Project Scenario: The project activity is a Greenfield project activity set up along with a new distillery unit of IGL in Gorakhpur. The distillery unit was commissioned in April 2006. The existing and proposed cogeneration project will meet the steam and power requirement of the distillery unit. Hence, there was no power plant operating before the implementation of the project activity. The project activity has been implemented to cater to the power and steam requirement of the new distillery unit that was set up by IGL in Gorakhpur. Current Scenario: The distillery unit has been commissioned in April2006. Presently, the source of power is from 4 MW TG set and from UPSEB. The steam requirement of 38 TPH for the distillery unit is being met using the 1st Slop fired boiler. The electricity requirement for the distillery unit is 20772 MWh and the electricity requirement for the auxiliary consumption of the Slop fired boiler is 6048 MWh making the total

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 4 electricity requirement of 26820 which corresponds to 3.725 MW of electricity. 4 MW turbine generates gross electricity of around 23 040 MWh. The steam for the 4 MW turbine to generate 3.200 MW electricity which is around 38 TPH is supplied from the 1st slop fired boiler. The remaining 3780 MWh of the electricity requirement is being procured from the grid. On an average 38TPH Steam is being generated from 47 TPH 1st Slop fired Boiler. This supersaturated steam is supplied to 4 MW turbine for power generation. The exhaust steam from the 4 MW turbine is used for process requirements. (Note: LIPI Boiler on rice husk is used as stand by boiler in case of modifications on the Slop Fired Boiler. The capacity of LIPI boiler is 35 TPH) Baseline Scenario: The PP needs to meet the demand of the steam and electricity consumption at their new distillery unit. In the absence of the project activity the steam requirement at the PP’s distillery unit would have been met by the installation of a captive fossil fired boiler and the electricity requirement would have been met by import of electricity from the grid. The surplus electricity exported by the project activity would have been produced by the operation of existing/proposed grid connected power plants. The PP’s captive requirement of 20 772 MWh would have been imported from the grid and the PP would have installed a coal based boiler to meet the captive steam requirement of 38 TPH for the distillery process. In this scenario, evaporator treatment systems will be adopted to treat the spent wash generated from the distillery unit to meet the regulatory guidance. The concentrated spent wash (slops) generated from the evaporator system would have been dumped or left to decay under mainly aerobic conditions or burned uncontrolled manner. The other biomass (rice husk) would have been left to decay or burned uncontrolled manner. In the absence of the project activity, the required process steam would have been produced from a fossil fuel fired boiler and equivalent amount of electricity would have been generated from the operational/proposed power plants connected to the grid. This baseline scenario has been identified as per the methodology ACM 0006 version 09 and has been described in detail in section B.4. How the project activity reduced the GHG emissions into the atmosphere: The project activity is a biomass based cogeneration project activity consisting of two numbers of 47 TPH Slop fired boilers. These boilers would be connected to a common steam header which would provide the steam to a 12 extraction cum condensing turbine and a 4 MW back pressure turbine for generation of electricity. In the absence of the project activity, the required process steam would have been produced from a fossil fuel fired boiler and equivalent amount of electricity would be generated from the operational/proposed power plants connected to the grid Hence the project activity reduces the fossil fuel combustion in the boilers for steam generation and its associated anthropogenic GHG emissions into the atmosphere. The project activity also reduces the anthropogenic emissions of greenhouse gases (GHGs) in to the atmosphere that would have produced from the existing/proposed fossil fuel based power plant in the grid in the absence of the project activity.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 5 As described in Section A4.3 and B.3, the main emission source of Green House Gas that the project activity primarily aims to reduce is CO2 (Carbon di-Oxide) emissions from the electricity generation by fossil fuel based grid connected power plants and CO2 emissions from the boilers that would have happened due to fuel firing for the production of steam in the boiler. It is assumed that CO2 emissions from the burning of biomass residues do not lead to changes of carbon pools in the LULUCF (Land Use Land Use Change and Forestry) sector. Hence this emission source has not been considered in the project activity for the burning of Slops (concentrated spent wash). As described in Section B.3 and B.4 the baseline scenario identified for the use of biomass residues is B1 (i.e. the biomass residues are dumped or left to decay under mainly aerobic conditions. This applies, for example, to dumping and decay of biomass residues on fields) or B3 (The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes). Thus, the CH4 emissions from uncontrolled burning or decay of biomass residues in the baseline scenario are included. As described in the Section B.3 the emission source N2O has also been excluded from consideration for simplification as mentioned in the approved methodology ACM 0006, Version 09. Contribution of the project activity to sustainable development Ministry of Environment and Forests, Govt. of India has stipulated the social well being, economic well being, environmental well being and technological well being as the four indicators for sustainable development in the host country approval eligibility criteria for Clean Development Mechanism (CDM) projects1.

• Social well being The Project activity has provided direct employment opportunities to around 64 number of people during the operation of the project activity and indirect employment opportunities to around 100 number of people during the construction of the project activity.

• Economic well being The project activity has created employment opportunities for the local people. The salary for the employer will improve the economic conditions of certain number of people. • Environmental well being The project activity is first of its kind in India. The project activity will result in reduction of anthropogenic GHG gases into the atmosphere. This is a waste to energy project, which will result in better environment in the locality.

• Technological well being

The project activity will employ the technology of Slop Fired Boiler for generation of steam and electricity for the first time in India. Successful operation of this cleaner technology would lead to replication of such projects in other places. The project proponent has taken up an important step by introducing the state-of-the-art boiler technology.

A.3. Project participants:

1 http://cdmindia.nic.in/host_approval_criteria.htm

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 6 >>

Name of Party involved (*) ((host) indicates a host Party)

Private and/or public entity(ies) project participants (*) (as applicable)

Kindly indicate if the Party involved wishes to be considered as project participant (Yes/No)

Government of India (Host)

Public entity- M/s India Glycols Limited

No

A.4. Technical description of the project activity: A.4.1. Location of the project activity: >> A.4.1.1. Host Party(ies): >> India A.4.1.2. Region/State/Province etc.: >> Uttar Pradesh A.4.1.3. City/Town/Community etc.: >> Gorakhpur Industrial Development Authority Area (GIDA), Gorakhpur A.4.1.4. Details of physical location, including information allowing the unique identification of this project activity (maximum one page): >> The Project Activity is located on the southern side of M/s India Glycols Ltd plant, located at GIDA, outer area of Gorakhpur. The proposed site is located in the Gorakhpur Industrial Development Area (GIDA). GIDA is located on national highway number 28 between Nausarh and Bhiti Rawat villages. The geographical location of Gorakhpur is placed on the eastern side of Uttar Pradesh, India. The proposed project is situated 780 km from Delhi, 280 km from Lucknow, 260 km from Patna and 100 km from Indo-Nepal border. Besides Gorakhpur Junction, Sahjanwa , the sub feeding railway station is 3 km away from the Industrial sectors 13 & 15 of GIDA. The nearest Airport is Gorakhpur Airport. It is located at 26° 46´ north latitude and 83° 22´ east longitude.


A.4.2. Category(ies) of project activity: >> Sector: Energy Category 1: Energy industries (renewable - / non-renewable sources). Sectoral Scope: 1 A.4.3. Technology to be employed by the project activity : >> The project activity is an environmentally safe and sound technology. The technology employed in the project activity, is the first time in India. The PP has invested in doing extensive research along with boiler manufacturer to develop the best available technology, meeting environment norms and achieving the highest efficiency.

Project Activity of IGL

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 8 Prior to the start of the implementation of the project activity The project activity is a green field project activity. The project activity will cater the steam and power requirement of the IGL plant. Hence, there was no equipment and system in operation prior to the start of the implementation of the project activity. Post Project Scenario: Part of the electricity generated from the project activity will be used for captive consumption and the surplus electricity will be sold to the Uttar Pradesh State Electricity Board (UPSEB). The steam extracted from the turbines and the let down steam will be used to meet the steam requirement for the in house electricity consumption. In the absence of the project activity, the required process steam would have been produced from a coal fired boiler and equivalent amount of electricity would have been generated from the operational/proposed power plants connected to the grid. Hence this is the baseline scenario as identified B.4. The project activity consists of 2 numbers of 47 TPH Slop fired boilers, one number of 4.0 MW back pressure turbine and one number of 12 MW extraction cum condensing turbine for generation of electricity and steam. The Slop fired boiler is manufactured by Cheema Boilers Limited (CBL). The 12 MW turbine is manufactured by M/s Guangzhou Guangzhog Enterprises Group Corp (GGEGC). TECHNICAL SPECIFICATION 12 MW TG SET Design Type Multistage, impulse, controlled extraction

Cum condensing Casing Split Horizontal Rotor Type Solidly forged & mechanical rotor

with integral disk Shaft Seal Labyrinth No governing values Four Bearing support Two pedestals Rated Speed Turbine/ Alternator- 6000/1500rpm TURBINE PERFORMANCE PARAMETERS.

Sl. No.

Description /Parameters Units Values

1. Stem inlet ---- Pressure Bar 42.0 Temp. Deg c 440.0 Flow MT / Hr 60.0 3. Steam Extraction


Pressure

Bar 4.5

Flow MT/Hr 20.0

4. Exhaust

Pressure Bar 0.0964

Flow MT/Hr 39.789

5. Electrical Output(MW)at Alternator Terminal

----- 11.772

TECHNICAL SPECIFICATION FOR 4 MW TG Set Turbine

Manufacturer DLF ENERGY SYSTEMS Type Back Pressure Turbine Serial No

10010/9

Description /Parameters Units Values Turbine Speed

RPM 5500

Steam inlet Pre.

ATA 42

Steam Exhaust Pre.

ATA 4.5

Steam Extraction Pre. ATA 10 Steam inlet Temp. Deg C 420

1

Lube Oil Press. BAR 2

Alternator: Manufacturer BHEL Bharat Heavy Electricals Ltd.

(Synchronous Generator)

Serial No 42074 A 261 – 11 – 01 Frame G64932

2

KVA KW RPM P.F. Phase HZ

5000 4000 1500 0.8LAG 3 50


Description /Parameters Units Value Ambient Temp. Deg C 45 Inlet Temp Deg C 50

TECHNICAL SPECIFICATION FOR SLOPS FIRED BOILER

Sl. No.

Description CBL OFFERED.

1. TYPE OF BOILER 47 TPH AFBC NATURAL CIRCULATION, SEMI-OUT DOOR

2. Fuel Main Fuel: Slops Supporting Fuel: Rice Husk & Coal.

COAL SUPPORT FUEL OVER BED FIRING.

GCV DESIGN /PERFORMANCE 3000/3500 Kcal/kg

b. RICE HUSK SUPPORT FUEL OVER BED.

GCV DESIGN/ PERFORMANCE 3100Kcal/kg C. SLOPS MAIN FUEL OVER BED FIRING.

GCV DESIGN ON WET BASIS 1750Kcal/kg

3. CAPACITY

MCR (80%slops+20% coal/Rice husk) 30 TPH minimum.

Peak Loading

110% of MCR for ½ Hrs. in a shift.

6. STEAM PARAMETERS Pressure 42 kg/cm2 g

Temp. 440+(-)5 Deg C

SH Safety V/v Set Pr. 44.5 kg/cm2 g

Drum 1st safety V/v set Pr. 48.3 kg/cm2 g

Drum2nd safety V/v set Pr. 49.3 kg/cm2 g

Steam quality pH /SiO2/TDS/PO4/N2H4 0.02/1

Sl. No.

DESCRIPTION CBL OFFERED.

7. No. of compartments Three


Fuel Feeder Nos. & type. Screw Feeders

Turn Down Ratio 1 Ratio 1.3

Fuel combination Efficiency

8. Coal/rice husk firing 70%

Combination with slops Firing 65%

Slops Firing 55%

Steam Generator The steam generator installed is having 2 furnaces. The first furnace is fired with concentrated spent wash (slops) to generate the saturated steam, with the help of support fuel coal/ rice husk. The second furnace is fired with coal to super heat the saturated steam generated in slops fired furnace. The super heated steam is supplied to TG set/ main plant to produce the power and back pressure steam from turbine is used to run the process plant. The brief description of both the furnace is given below. Slops Fired Furnace: Boiler is primarily based on fluidised bed combustion technology with over bed firing. The primary combustion air from FD fan is supplied through the air nozzles mounted on the distributor plate and is used to keep the bed material fluidised and helps to maintain the fluidised bed temperature. The furnace distributor plate surface area is kept lower than the furnace upper area so that the fuel & air requirement for maintaining the bed temperature remains low. The bed is not provided any kind of bed tubes. The start-up / supporting fuel combustion zone is further provided with refractory linings which further helps to maintain the fluidised bed temperature with minimum fuel addition. Since no bed coil tubes are provided, the erosion in this area is avoided. The start-up fuel is coal/ rice husk, which is burnt first with the help of charcoal like in conventional FBC boilers. Once the fluidised bed attains minimum bed temperature of 6000 C & adequate fluidisation, the start-up fuel coal/ rice husk is introduced. After the bed temperatures are raised to 9000 C, the concentrated spent wash firing is started with slow rate through a specially designed gun installed at about 6-7mtr. height from the bed level. The combustion of spent wash takes place in cloud form and also part of the slops (heavier particles) fall down on the red hot fluidised bed and burn in the bed and thus helping in maintaining the bed temperatures, with-out much support fuel. Then the start-up coal/ rice husk quantity can be reduced gradually on the basis of bed temperatures. The slops firing can be then increased as per requirement. The slops burns like a cloud in the furnace and the temperature is maintained about 700-750 0 C in this zone. There are total 03 compartments in the boiler and each compartment is provided with one no. support fuel feeder. Also each compartment is provided with 2nos. slops firing guns (1each at both the opposite walls). The no. of fuel feeder or no. of slops firing guns can be taken on service or withdrawn depending upon the steam load requirement or slops availability. The slops firing can be increased gradually up-to 80% of boiler MCR.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 12 The temperature of hot flue gasses leaving the combustion chamber remains about 600-7000C, the gasses then passed through the second & third chambers (convection zone) and the flue gas temperature remains about 500 0 C & 375 0 C respectively. Further, heat from flue gas is absorbed in force flow bank (economizer) through feed water preheating, to bring down the flue gas temperature to 280 0 C. Finally the heat from flue gas is absorbed in air preheater unit and flue gas temperature is brought down to 180 0 C. Since the ash carried-away with flue gas have fouling tendency, therefore the APH is provided with air & flue gas bypass arrangements, to have provision of on-line cleaning. The Flue gas is then passed through the treama cyclones (where the SPM level in the flue gasses bring down 250-300 mg/m3) and then to water wet scrubber (future), which will bring down the SPM level in the flue gasses to <100 mg/m3. This flue gas is then discharge in-to the atmosphere with the help of ID fan through the chimney to safe elevation. The furnace bed height is drained as per requirement. The potassium ash is collected at second, third & fourth chambers & below treama cyclones ash collection hoppers. The ash collected from ash hoppers remains in powder form and rich with the potash, which is used as manure. The boiler flue gas dew temperature remains between 140-145 0 C, but still the designed flue gas exit temperature is considered 180 0 C. Although the boiler is designed to run independently on Slops firing with 6nos. burners provided at both side walls of the combustion chamber, yet the provision of support fuel is kept to ensure the complete combustion of the slops even with some variation in quality. The design of slops gun is very simple and based on pressure atomizing; it is atomized at pressure 12-15kg/cm2g. However, compressed air provision is kept for atomising if required. The SA fan of suitable capacity is also installed to supply the secondary air at various levels of furnace to ensure the proper combustion of fuel takes place. In normal operating condition FD fan will supply the air to keep the bed fluidised & for primary combustion and SA fan will supply the balance combustion air to burn the slops in free board zone. There is no special material of construction is considered for pressure parts. The normal carbon steel boiler tubes are used for the boiler pressure parts. For avoiding the soot / ash deposition on pressure parts there is no convection bank & super heater arrangement provided in the boiler and the flue gas velocity is kept around 6-8mps. 37TPH steam generated in this boiler is at 42kg/cm2g & saturation temperature (due to non-availability of super heater. This saturated steam is then supplied to super heater installed in separate coal fired furnace. Super Heater Fired Furnace:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 13 This furnace is again on fluidized bed combustion technology with under bed firing. FD fan is installed to supply primary combustion air through the air nozzles mounted on the distributor plate and secondary combustion air is used to burn the un-burnt carbon in free board zone. The SH furnace is installed with one set of bed coils connected to out side located steam drum. Rest of combustion chamber is totally refractory lined and the super heater tubes are installed in convection zone. The fluidized bed is temperatures are controlled by heat absorption in bed coils. Then the hot flue gasses pass through the super heater zone then to economizer to further absorbed the heat from hot flue gas. Finally the hot flue gasses are passed through air preheater assembly where the combustion air for slop furnace is preheated and supplied to air preheater assembly installed in slop furnace. For start-up the charcoal is burnt like in conventional FBC boilers. Once the fluidized bed attains minimum 600 0C temperature & adequate fluidization, the coal/ rice husk is introduced. The bed temperatures are maintained between 700- 850 0C. The deaerated feed water (105-110 0C) is first fed to economizer installed in both slop & super heater furnaces and pre-heated to about 180-190 0C. This heated-up feed water is then fed to steam drums of respective furnaces to generate the steam in their furnaces. In slops fired furnace the steam is generate at 42kg/cm2g at saturation temperature. The saturated steam produced at slops firing furnace is then supplied to super heater inlet header where it is mixed with the saturated steam generated in separately fired super heater furnace. The total steam from slop furnace & super heater furnace is then super heated in a common super heater assembly installed super heater furnace up-to final the steam temperature up-to 440 0C. The final steam temperature is controlled by two stage desuperheater installed between primary & secondary super heater headers. The super heater furnace is designed to produce 10TPH steam at 42kg/cm2g @ 440 0C along with super heating of 37TPH saturated steam produced in slop fired furnace. The total 47TPH steam produced at 42kg/cm2g & 440 0C is then supplied to main plant steam distribution header, from where it is distributed to different STG sets & other process plants.

The following table gives the list of equipments that are being installed as a part of the project activity. Boiler Turbine DG sets Slop fired boiler with a capacity of 47 TPH.

4 MW back pressure turbine 1250 kVA DG set fired with HSD

Slop fired boiler with a capacity of 47 TPH

12 MW extraction cum condensing turbine.

1250 kVA DG set fired with HSD

The following table further describes the scenario after the implementation of the project activity The 1st 47 TPH Slop fired boiler will generate 39 TPH. The 2nd Slop fired boiler will generate 39 TPH. 78TPH of Steam will be supplied to turbines through the common steam header. 60TPH steam will be supplied to the 12 MW Turbine. Out of the 60TPH turbine exhaust steam 40 TPH will be used for condensing and 20 TPH exhaust steam will be used for process. The remaining 18TPH steam will be supplied to 4 MW turbine and the entire exhaust steam from the 4 MW turbine will be used for process.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 14 The Capacity utilization factor for both the boilers is considered as 83% which is on a conservative side. The steam generated with a CUF of 83% will be 39 TPH. The Plant Load Factor considering the CUF as 83% and operating for 300 days per annum will be around 68% calculated as (83%×(300/365)). The operating days is assumed as 300 as the same will be the operating days for the distillery plant of the PP. This assumption of CUF is due to the planned shutdown for annual regulatory requirements of boiler inspection, and preventive maintenance for furnace, ESP, Turbine and other critical items such as DCS and other electrical installations such as transformer etc. The capacity utilization factor for the 12 MW turbine is considered as 98%. The Plant Load Factor considering the CUF as 98% and operating for 300 days per annum will be around 81% calculated as (98%×(300/365)) The capacity utilization factor for the 12 MW turbine is considered as 39%. The Plant Load Factor considering the CUF as 39% and operating for 300 days per annum will be around 33% calculated as (39%×(300/365)) Name of the Equipment

Average lifetime of the equipment

Existing Capacity

Load Factor

Efficiency Monitoring Equipment & Location.

Boiler 1 20 years 47 TPH 68% 65% Steam flow totalizer is used to calculate the steam generation and the meter is present in the Cheema Boiler Control Panel. The signal is given by the steam flow transmitter present in the field with Tag No. FT 201. The steam temperature is measured online using the meter present in the Cheema Boiler Control pane. The signal to this meter is given by the temperature element located in the field with Tag No.TE 203. The steam pressure is also measured using the online meter installed in the Cheema Boiler control panel. The signal is given by the steam pressure transmitter present in the field with tag No. PT 202.

Boiler 2 20 years 47 TPH 68% 65% It is proposed to install an online meters in the control panel and their respective


transmitters in the field. Turbine 1 20 years 4.0 MW 33% - The gross electricity

generation is measured using the 3 phase 3 wire gross energy meter installed in the generation control panel. The steam to the process from the exhaust of the turbine is measured using the main steam flow totalizer. The signal to this meter is given by flow transmitter with tag No. FT 20011.

Turbine 2 20 years 12.0 MW 81% - It is proposed to install the required energy meters for gross electricity generation, auxiliary electricity generation and also the steam from the exhaust of the turbine.

As described in Section A4.3 and B.3, the main emission source of Green House Gas that the project activity primarily aims to reduce is CO2 (Carbon di-Oxide) emissions from the electricity generation by fossil fuel based grid connected power plants and CO2 emissions from the boilers that would have happened due to fuel firing for the production of steam in the boiler. It is assumed that CO2 emissions from the burning of biomass residues do not lead to changes of carbon pools in the LULUCF (Land Use Land Use Change and Forestry) sector. Hence this emission source has not been considered in the project activity for the burning of Slops (concentrated spent wash). As further described in Section B.3 and B.4 the CH4 emissions from uncontrolled burning or decay of biomass residues in the baseline scenario are included as the baseline scenario identified for the use of biomass residues is B1 (i.e. the biomass residues are dumped or left to decay under mainly aerobic conditions. This applies, for example, to dumping and decay of biomass residues on fields) or B3 (The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes). As described in the Section B.3 the emission source N2O has been excluded from consideration for simplification as mentioned in the approved methodology ACM 0006, Version 09. The forecasted mass flow balances of the systems and equipments that are envisaged to be installed as a part of the proposed project activity is represented by the below diagrams.


47 TPH Slop Fired Boiler 47 TPH Slop Fired Boiler

39 TPH, 42 Kg/cm2, 440 Deg

39 TPH, 42 Kg/cm2, 440

4 MW Turbine 12 MW Turbine

18 TPH, 42 Kg/cm2, 440 Deg C 60 TPH, 42 Kg/cm2, 440 Deg C

40 TPH, 0.09 bar for condensing

38 TPH, 3.5 Kg/cm2, 150 Deg C

Evaoporator

Process Grid

Rice Husk from Market

Coal from Market

11.772 MW 1.575 MW

2.885 MW 8.035 MW

91 TPD

205 TPD

92160 Tons per annum

2.427 MW (Auxiliary)

Baseline Scenario List of the equipment(s) and systems that would have been in place in the absence of the project activity The PP’s captive requirement of 20 772 MWh would have been imported from the grid and the PP would have installed a coal based boiler of 45 TPH to meet the captive steam requirement of 38 TPH for the distillery process The following table gives the list of equipments that would have been installed in the baseline scenario. Boiler DG sets

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 17 Coal Fired Boiler with a capacity of 45 TPH

Electricity would have been procured from the grid.

1250 kVA DG set fired with HSD

A.4.4. Estimated amount of emission reductions over the chosen crediting period: >> Total Chosen Crediting period is from 01/09/2010 to 31/08/2020 Years Estimation of Annual Emission

reductions in tonnes of CO2 e

Year A 110157 Year B 110157 Year C 110157 Year D 110157 Year E 110157 Year F 110157 Year G 110157 Year H 110157 Year I 110157 Year J 110157

Total estimated reductions (tonnes of CO2 e)

1101570

Total number of crediting years 10 Annual average of estimated reductions over the crediting period (tCO2 e)

110157

A.4.5. Public funding of the project activity: >> Public funding such as grants from official development funds is not involved for this project activity.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 18 SECTION B. Application of a baseline and monitoring methodology B.1. Title and reference of the approved baseline and monitoring methodology applied to the project activity : >> The approved methodology and the version of the methodology that is used The approved baseline and methodology, ACM 0006 has been used to to determine the baseline and monitoring of the project activity. The title of the methodology is “Consolidated methodology electricity generation from biomass residues” (Version 09, EB 48) Any methodologies or tools which the approved methodology draws upon and their version

ACM0002 (“Consolidated baseline methodology for grid-connected electricity generation from renewable sources”);

Version 10, EB 47.

Combined tool to identify the baseline scenario and demonstrate additionality

Version 02.2, EB 28

“Tool to determine methane emissions avoided from disposal of waste at a solid waste disposal site”;

Version 04, EB 41.

“Tool to calculate project or leakage CO2 emissions from fossil fuel combustion”

Version 02, EB 41.

“Tool to calculate baseline, project and/or leakage emissions from electricity consumption”

Version 01, EB 39

B.2. Justification of the choice of the methodology and why it is applicable to the project activity: >> The project activity consists of 2 numbers of 47 TPH Slop fired boilers, one number of 4.0 MW back pressure turbine and one number of 12 MW extraction cum extraction turbine for generation of electricity and steam. The project activity meets the applicability criteria of ACM0006, version 09 as under. This methodology is applicable to biomass residue fired electricity generation project activities, including cogeneration plants. The following is the definition for Biomass and Biomass residues as per ACM 0006. Biomass: Biomass is non-fossilized and biodegradable organic material originating from plants, animals and microorganisms. This shall also include products, by-products, residues and waste from agriculture,

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 19 forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes. Biomass also includes gases and liquids recovered from the decomposition of nonfossilized and biodegradable organic material. Biomass residues: Biomass residues are defined as biomass that is a by-product, residue or waste stream from agriculture, forestry and related industries. This shall not include municipal waste or other wastes that contain fossilized and/or non-biodegradable material (small fractions of inert inorganic material like soil or sands may be included). The Slops (concentrated spent wash) used in the project activity is non-fossilised and the biodegradable organic fractions of the industrial (i.e. the distillery) waste and hence falls under the biomass definition. Slop is a waste stream from agriculture and related industry. Hence Slops can also be defined as the biomass residue as it is the biomass that is a waste stream of the distillery facility. Hence the project activity is a biomass residue fired cogeneration plant. The project activity may include the following activities or combinations of these activities:

• The installation of a new biomass residue fired power plant at a site where currently no power generation occurs (greenfield power projects); or

• The installation of a new biomass residue fired power plant, which replaces or is operated next to existing power plants fired with either fossil fuels or the same type of biomass residue as in the project plant (power capacity expansion projects); or

• The improvement of energy efficiency of an existing power plant (energy efficiency improvement projects), e.g. by retrofitting the existing plant or by installing a more efficient plant that replaces the existing plant; or

• The replacement of fossil fuels by biomass residues in an existing or a reference power plant (fuel switch projects).

The project activity is a greenfield power project where prior to the project activity no power was being generated.

The project activity may be based on the operation of a power plant located in an agro-industrial plant generating the biomass residues or as an independent plant supplied by biomass residues coming from the nearby area or a market. The project proponent will utilize slop and rice husk for the project activity. Slop will be generated from the plant and rice husk will be sourced from the nearby area or market. The methodology will be applicable under the following conditions: S.No. Applicability Criteria Project Activity

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 20 1 No other biomass types than biomass residue,

as defined above ,are used in the project plant and these biomass residue are the predominant fuel used in the project plant(Some fossil fuel may be co-fired)

Biomass residues defined in the ACM0006 will be used in the project activity. The slop will be generated from the evaporator in the project plant. The rice husk will also be used in the project activity. These fuels are predominant fuel used in the project plant. Coal will be co-fired in the project activity.

2 For projects that use biomass residues from a production process (e.g. production of sugar or wood panel boards), the implementation of the project shall not result in an increase of the processing capacity of raw input (e.g. sugar, rice, logs, etc.) or in other substantial changes (e.g. product change) in this process

The project activity uses the concentrated effluent generated from the evaporator in the Slop fired boiler for generation of steam and electricity. As the project activity is implemented at a new facility it doesn’t result in an increase in the processing capacity of the raw materials.

3 The biomass residues used by the project facility should not be stored for more than one year

The biomass used in the project activity will not be stored for more than one year. This will be verified by the DOE during the verification process.

4 No significant energy quantities, except from transportation or mechanical treatment of the biomass residues, are required to prepare the biomass residues for fuel combustion, i.e. projects that process the biomass residues prior to combustion (e.g. esterification of waste oils).

No significant energy quantity is required to prepare the concentrated effluent taken from the evaporator before the utilisation of it in the boiler.

B.3. Description of the sources and gases included in the project boundary: >> For the purpose of determining GHG emissions of the project activity, project participants shall include the following emissions sources:

• CO2 emissions from on-site fossil fuel and electricity consumption that is attributable to the project activity. This includes fossil fuels co-fired in the project plant, fossil fuels used for on-site transportation or fossil fuels or electricity used for the preparation of the biomass residues, e.g., the operation of shredders or other equipment, as well as any other sources that are attributable to the project activity; and

• CO2 emissions from off-site transportation of biomass residues that are combusted in the project plant; and

• Where applicable, CH4 emissions from anaerobic treatment of wastes originating from the treatment of the biomass residues prior to their combustion.

For the purpose of determining baseline emissions, project participants shall include the following emission sources:

• CO2 emissions from fossil fuel fired power plants at the project site and/or connected to the electricity system; and

• CO2 emissions from fossil fuel based heat generation that is displaced through the project activity.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 21 Where the most likely baseline scenario for the biomass residue use is that the biomass residues would be dumped or left to decay under aerobic or anaerobic conditions (cases B1 or B2) or would be burnt in an uncontrolled manner without utilizing it for energy purposes (case B3), project participants may decide whether to include CH4 emissions in the project boundary. Project participants shall either include CH4 emissions from both project and baseline emissions or exclude them in both cases, and document their choice in the CDM-PDD. This has been described in the table below. As per the methodology ACM 0006 Version 09, the spatial extent of the project boundary encompasses:

• The power plant at the project site; • The means for transportation of biomass residues to the project site (e.g. vehicles); • All power plants connected physically to the electricity system that the CDM project power plant

is connected to. The spatial extent of the project electricity system, including issues related to the calculation of the build margin (BM) and operating margin (OM), is further defined in the “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (ACM0002).

• The site where the biomass residues would have been left for decay or dumped. This is applicable only to cases where the biomass residues would in the absence of the project activity be dumped or left to decay.

Hence the project boundary consists of the

• Power plant consisting of the two numbers of 47 TPH Slop Fired Boiler, 4.0 MW back pressure turbine and 12 MW extraction cum condensing turbine.

• The transportation facility for procuring the rice husk. • 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. Grid Selection This approach is based on the assumption that the renewable energy project is displacing the average electricity mix in the grid. In India, power is a concurrent subject between the state and the central governments. The perspective planning, monitoring of implementation of power projects is the responsibility of Ministry of Power, Government of India. At the state level the state utilities or state electricity boards (SEBs) are responsible for supply, transmission, and distribution of power. With power sector reforms there have been unbundling and privatization of this sector in many states. Many of the state utilities are engaged in power generation also. In addition to this there are different central / public sector organizations involved in generation like National Thermal Power Corporation (NTPC), National Hydro Power Corporation (NHPC), etc. in transmission e.g. Power Grid Corporation of India Ltd. (PGCIL) and in financing e.g. Power Finance Corporation Ltd. (PFC). There are five regional grids: Northern, Western, Southern, Eastern and North-Eastern. Different states are connected to one of the five regional grids as shown in below table. Northern Western Southern Eastern North Eastern Haryana Gujarat AP Bihar Assam HP MP Karnataka Jharkhand Manipur

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 22 JK Chhattisgarh Kerala Orissa Meghalaya Rajasthan Maharashtra TN WB Nagaland UP Goa Lakshadweep D.V.C Tripura Uttaranchal D.N.H Pondicherry A & N Arunachal

Pradesh Chandigarh Daman & Diu Sikkim Mizoram Delhi The management of generation and supply of power within these grids is undertaken by the load dispatch centres (LDC). Different states within these grids meet the demand from their own generation facilities plus generation by power plants owned by the central sector i.e. NTPC and NHPC etc. Specific quota is allocated to different states from the central sector power plants. Depending on the demand and generation there are exports and imports of power within different states in the regional grid. Thus there is trading of power between states in the grid. Similarly there is import and export of power between the above mentioned grids. Since the CDM project activity would be connected to the grid and located in the Uttar Pradesh state it is considered under the Northern grid as the project boundary. The emission factor used in this project activity has been considered from the Central Electricity Authority published data.


Effluent

AEMST1 GEM1

GEM AEM 1

ST 2

Steam

Electricity

Slops

Rice Husk

Coal

Effleunt

AEM Auxilary Energy MeterGEM Gross Energy MeterST Steam Totlaizer

47 TPH Slop Fired Boiler

47 TPH Slop Fired Boiler

4 MW Turbine

12 MW Turbine

Evaoporator

Process Grid

Rice Husk from Market

Coal from Market

CO2 Emissions

CO2 Emissions

CO2 Emissions

Sequestered

Distillery Plant

Project Boundary

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 24 The following table envisages the emissions encountered from the project activity for determination of both baseline and project emissions.

Source

Gas

Included

Justification / Explanation

CO2

Yes Main emission source

CH4

No

Excluded for simplification. This is conservative.

Grid electricity generation

N2O

No Excluded for simplification. This is conservative.

CO2

Yes

Main emission source

CH4

No


Heat generation

N2O

No


CO2

No

It is assumed that CO2 emissions from surplus biomass residues do not lead to changes of carbon pools in the LULUCF sector.

CH4

Yes B1 is baseline scenario identified by the PP for the use of

bio-solids and B3 is the baseline scenario identified by the PP for the use of rice husk.

Baseline Baseline

Uncontrolled burning or decay of surplus biomass residues

N2O

No Excluded for simplification. This is conservative. Note also that emissions from natural decay of biomass are not included in GHG inventories as anthropogenic sources.

CO2

Yes

May be an important emission source

CH4

No Excluded for simplification. This emission source is

assumed to be very small.

On-site fossil fuel and electricity consumption due to the project activity (stationary or mobile)

N2O

No

Excluded for simplification. This emission source is assumed to be very small.

Project Activity

Off-site CO2

Yes

May be an important emission source


CH4

No Excluded for simplification. This emission source is

assumed to be very small N2O

No Excluded for simplification. This emission source is assumed to be very small

CO2

No It is assumed that CO2 emissions from surplus biomass do

not lead to changes of carbon pools in the LULUCF sector.

CH4

Yes As the decay of the biomass residues is included in the

baseline scenario.

Combustion of biomass residues for electricity and / or heat generation

N2O

No

Excluded for simplification. This emission source is assumed to be small.

CO2

No It is assumed that CO2 emissions from surplus biomass

residues do not lead to changes of carbon pools in the LULUCF sector.

CH4

No Excluded for simplification. Since biomass residues are

stored for not longer than one year, this emission source is assumed to be small.

Storage of biomass residues

N2O

No Excluded for simplification. This emissions source is assumed to be very small.

B.4. Description of how the baseline scenario is identified and description of the identified baseline scenario: >> As per the methodology ACM 0006 Version 09, the most plausible baseline scenario should be determined by the PP using the latest approved version of the “Combined tool to identify the baseline scenario and demonstrate additionality”, agreed by the CDM Executive Board, In applying Step 1 of the tool, realistic and credible alternatives should be separately determined regarding:

• How power would be generated in the absence of the CDM project activity; • What would happen to the biomass residues in the absence of the project activity; and • In case of cogeneration projects: how the heat would be generated in the absence of the project

activity. The following table indicates the quantity of the biomass used in project activity and the process in which they are used. The project activity involves two different kinds of Biomass residues vis-à-vis slop or Bio Solids and rice husk. Rice Husk is used as supporting fuel in the Slop fired Boiler. The Following table describes how the biomass residues would have been used in the absence of the project activity.

Type of Biomass Quantity of dry Installation in which the Use of the Biomass in the


biomass biomass is used absence of the project activity

Bio-solids (slops) 92160 Tons per annum

2 numbers of 47 TPH Boilers

The biomass residues would have been dumped or left to decay under mainly aerobic conditions.

Type of Biomass Quantity of dry

biomass Installation in which the biomass is used

Use of the Biomass in the absence of the project activity

Rice Husk 55344 Tons per annum

2 number of 47 TPH Boilers

The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes.

The various alternatives to the project activity are being identified in this section separately for power, heat and biomass for Slops and rice husk separately. It should be noted that rice husk is the supporting fuel in the project activity and hence the alternative scenario for the power and steam generation will be the same for Slops and rice husk. Rice husk is mainly used in the super heater furnace of the Slop fired boiler. The main criteria for identifying the alternatives are that they should be able to deliver services and output equivalent to that of the project activity. The alternative scenarios would involve how IGL would have dealt with its power and steam requirements and the waste generated as a result of the new distillery unit. The total power requirement for the distillery is 2.885 MW corresponding to the electricity requirement of 20 772 MWh and the total steam requirement is around 38 TPH at a temperature of 150 0 C and 3.5 Kg/cm2 pressure. The following table illustrates the alternative power generation scenario for determining the baseline scenario for bio-solids.

Baseline Scenario for Power Generation

Description Comments

P1 The proposed project activity not undertaken as a CDM project activity.

The proposed project activity as explained in section B5 faces barrier, hence it cannot be a baseline scenario.

P2 The continuation of power generation in an existing biomass residue fired power plant at the project site, in the same configuration, without retrofitting and fired with the same type of

This is not an alternative scenario as the project activity is a Greenfield project activity.


biomass residues as (co-)fired in the project activity.

P3 The generation of power in an existing captive power plant, using only fossil fuels.

This is not an alternative as there are no existing captive power plants at the project site prior to the implementation of the project activity.

P4 The generation of power in the grid.

In the absence of the project activity equivalent amount of electricity would have been generated from the operational/proposed power plants connected to the grid. Hence this is a possible alternative scenario.

P5 The installation of a new biomass residue fired power plant, fired with the same type and with the same annual amount of biomass residues as the project activity, but with a lower efficiency of electricity generation (e.g. an efficiency that is common practice in the relevant industry sector) than the project plant and therefore with a lower power output than in the project case.

This is not an alternative scenario as the installation of the Slop Fired Boilers fired with bio-solids/biomass/coal is the first of its kind in India.

P6 The installation of a new biomass residue fired power plant that is fired with the same type but with a higher annual amount of biomass residues as the project activity and that has a lower efficiency of electricity generation (e.g. an efficiency that is common practice in the relevant industry sector) than the project activity. Therefore, the power output is the same as in the project case.

This is not an alternative scenario as the installation of the Slop Fired Boilers fired with bio-solids/biomass/coal is the first of its kind in India.

P7 The retrofitting of an existing biomass residue fired power, fired with the same type and with the same annual amount of biomass residues as the project activity, but with a lower



efficiency of electricity generation (e.g. an efficiency that is common practice in the relevant industry sector) than the project plant and therefore with a lower power output than in the project case.

P8 The retrofitting of an existing biomass residue fired power that is fired with the same type but with a higher annual amount of biomass residues as the project activity and that has a lower efficiency of electricity generation (e.g. an efficiency that is common practice in the relevant industry sector) than the project activity.


P9 The installation of a new fossil fuel fired captive power plant at the project site.

As per the UPERC/Secy/Regulation/06-1288, dated 23rd March 2006, captive power generation should have 51% of the energy generated supplied for the captive use2. This is not the scenario with the project activity, where 57 857 MWh will be exported to the grid and only 20 772 MWh will be used for internal consumption. Thus, PP needs to establish a power plant that would generate gross electricity of maximum 40 730 MWh to qualify as a captive power plant. Therefore, a fossil fuel based power plant similar to the proposed project activity installed capacity will not qualify under the captive power plant definition. Hence this option is not an alternative for the project proponent.

P10 The installation of a new single-(using only biomass residues) or

The common practice in the

2 Page 9 of http://uperc.org/UPERC%20(TERMS%20AND%20CONDITIONS%20FOR%20SUPPLY%20OF%20POWER%20AND%20FIXATION%20OF%20TARIFF%20)%20Regulations,%202005.pdf


co-fired (using a mix of biomass residues and fossil fuels) cogeneration plant with the same rated power capacity as the project activity power plant, but that is fired with a different type and/or quantity of fuels (biomass residues and/or fossil fuels). The annual amount of biomass residue used in the baseline scenario is lower than that used in the project activity.

distillery sector in the state of Uttar Pradesh3 is to generate heat using boilers and procurement of electricity from the grid. In the region, the project activity will be the only power plant which will generate 96 103 MWh electricity out of which around 57 857 MWh electricity will be exported to the grid.

The P10 scenario requires use of different type of biomass. The PP analyzed the other biomass fuel availability option in the region and does not see any feasibility of these options due to limited availability of other type of biomass. Thus, this is not a realistic baseline option.

Moreover, P10 scenario also requires use of different quantity of biomass. The installation of the novel boiler in the IGL Gorakhpur facility which uses slop as fuel is the first in India. Hence, use of slop and rice husk of different quantity other than that being used in the project activity is not a plausible scenario.

Hence, this is not a possible alternative scenario to the project activity.

P11 The generation of power in an existing fossil fuel fired cogeneration plant co-fired with biomass residues, at the project site.

This is a green field project activity. Thus, there is no existing fossil fuel fired cogeneration plant at the project site. Hence this is not a possible alternative scenario.

The following table illustrates the alternative heat generation scenario for determining the baseline scenario for bio-solids. 3 Analysis of the distilleries in U.P. by IGL, the same is submitted to the DOE for verification.


Baseline Scenario for Heat Generation


H1 The proposed project activity not undertaken as a CDM project activity.

The proposed project activity as explained in section B5 faces barrier, hence it cannot be a baseline scenario.

H2 The proposed project activity (installation of a cogeneration power plant), fired with the same type of biomass residues but with a different efficiency of heat generation (e.g. an efficiency that is common practice in the relevant industry sector)

This is not an alternative scenario as the project activity is a Greenfield project activity. The project activity is the first technology demonstration project activity in India for combustion of slops; hence before to the project implementation the technology of any efficiency was not available in India. Thus, installation of a cogeneration power plant with a different efficiency of heat generation is not a possible alternative scenario.

H3 The generation of heat in an existing captive cogeneration plant, using only fossil fuels

This is not an alternative as there are no existing captive cogeneration plants at the project site prior to the implementation of the project activity.

H4 The generation of heat in boilers using the same type of biomass residues

This is not an alternative scenario as the installation of the Slop Fired Boilers fired with bio-solids/biomass is the first of its kind in India. Thus, generation of heat in the boilers using the same type of biomass residues is not a realistic alternative scenario.

H5 The continuation of heat generation in an existing biomass residue fired cogeneration plant at the project site, in the same configuration, without retrofitting and fired with the same type of biomass residues as in the project activity

This is not an alternative scenario as the project activity is a Greenfield project and there were no existing biomass residue fired cogeneration plant at the project site.

H6 The generation of heat in boilers using fossil fuels

Coal is the cheap source of energy in the region. Thus, most of the industries in India from all the sectors utilises the coal as the energy sources at their site. Coal


mines are also easily accessible for the plant site. Thus, utilisation of coal in the boilers is a plausible scenario. Natural gas infrastructure is not available in the region. Thus, it has been ruled out as a fuel option. Other fossil fuels options are ruled out considering the high cost of petroleum fuels. The cheap coal cost incites to maximise the percentage of coal in the fuel mix and take it to 100 %.

H7 The use of heat from external sources, such as district heat

There is no district heating system in the region and this is beyond the scope of the project proponent and hence it can’t be taken as the alternative scenario.

H8 Other heat generation technologies (e.g. heat pumps or solar energy)

The common practice in the industry sector in India is to generate heat from the boiler. Hence this is not a realistic and credible alternative scenario.

H9 The installation of a new single- (using only biomass residues) or co-fired (using a mix of biomass residues and fossil fuels) cogeneration plant with the same rated power capacity as the project activity power plant, but that is fired with a different type and/or quantity of fuels (biomass residues and/or fossil fuels). The annual amount of biomass residue used in the baseline scenario is lower than that used in the project activity.

The common practice in the distillery sector in the state of Uttar Pradesh4 is to generate heat using boilers and procurement of electricity from the grid. In the region, the project activity will be the only power plant which will generate 96 103 MWh electricity out of which around 57 857 MWh electricity will be exported to the grid.

The H9 scenario requires use of different type of biomass. The PP analyzed the other biomass fuel availability option in the region and does not see any feasibility of these option due to limited availability of other type of biomass. Thus, this is not a realistic baseline option.

4 Analysis of the distilleries in U.P. by IGL, the same is submitted to the DOE for verification.


Moreover, H9 scenario also requires use of different quantity of biomass. The installation of the novel boiler in the IGL Gorakhpur facility which uses slop as fuel is the first in India. Hence, use of slop and rice husk of different quantity other than that being used in the project activity is not a plausible scenario.

Hence, this is not a possible alternative scenario to the project activity.

H10 The generation of power in an existing fossil fuel fired cogeneration plant co-fired with biomass residues, at the project site.

The project activity is a green field project activity. Thus, there is no exiting fossil fuel fired cogeneration plant at the project site. Hence this is not a possible alternative scenario.

The following table illustrates the alternative scenarios for the use of biomass residues for determining the baseline scenario for bio-solids.

Baseline Scenario for use of biomass residues


B1 The biomass residues are dumped or left to decay under mainly aerobic conditions. This applies, for example, to dumping and decay of biomass residues on fields.

The slop will be left to decay under mainly aerobic condition on fields. This is a plausible alternative scenario.

B2 The biomass residues are dumped or left to decay under clearly anaerobic conditions. This applies, for example, to deep landfills with more than 5 meters. This does not apply to biomass residues that are stock-piled or left to decay on fields.

This is not an alternative scenario, as the biomass residues would have been dumped or left to decay on fields/lands.

B3 The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes.

The plant may burn it in an uncontrolled manner in the absence of the project activity. Thus, this is an plausible scenario.

B4 The biomass residues are used for The use of slop for heat/and/or


heat and/or electricity generation at the project site

electricity has been taken up first time in India by the project proponent. Thus, the biomass residues are used for heat and/or electricity generation at the project site without CDM benefits is not a plausible scenario.

B5 The biomass residues are used for power generation, including cogeneration, in other existing or new grid-connected power plants

The installation of the Slop Fired boilers using mostly slop/bio-solids as fuel at the IGL unit at Gorakhpur site is the first of its kind in India, hence the use of the biomass residues for heat and/or electricity generation at other existing power plants is not an alternative scenario to the project activity due to unavailability of the technology.

B6 The biomass residues are used for heat generation in other existing or new boilers at other sites4

The technology demonstration for combustion of slops in the boiler has been done at IGL for the first time in India. Thus, the use of the biomass residues for heat and/or electricity generation at other new or existing boilers is not an alternative scenario to the project activity.

B7 The biomass residues are used for other energy purposes, such as the generation of biofuels

This is the first project activity of this kind where slops is used for energy purposes. In the absence of the project activity Slops would have been left in open in mainly aerobic conditions on fields which is the common practice in distillery sector.

B8 The biomass residues are used for non-energy purposes, e.g. as fertilizer or as feedstock in processes (e.g. in the pulp and paper industry)

The utilization of slop in the boiler is taken up for the first time in India by the project proponent. In the absence of the project activity the slop would have been dumped in an aerobic condition. The slop does not have quality of fertilizers for application on farm land. There is no technology which is


available which can make use of slop as a feedstock in any of the processes. The adaptation of this option is beyond the scope of the PP. Hence this can’t be an alternative scenario.

The following table illustrates the alternative scenarios for the use of biomass residues for determining the baseline scenario for rice husk.

Baseline Scenario for the use of biomass residues


B1 The biomass residues are dumped or left to decay under mainly aerobic conditions. This applies, for example, to dumping and decay of biomass residues on fields.

It is a common practice in the region that surplus biomass residue (rice husk) to be dumped or left to decay. So without this project part of the surplus biomass that is available in the market will be left unused (dumped or left to decay under mainly aerobic conditions or uncontrolled burning). Therefore, B1 is a realistic baseline alternative for rice husk biomass.

B2 The biomass residues are dumped or left to decay under clearly anaerobic conditions. This applies, for example, to deep landfills with more than 5 meters. This does not apply to biomass residues that are stock-piled or left to decay on fields.

The rice husk that will be used in the project activity would be either burnt in an uncontrolled manner or dumped outside in the absence of the project activity. Thus, this is not a plausible scenario.

B3 The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes.

The rice husk that will be used in the project activity would be either burnt in an uncontrolled manner or dumped outside in the absence of the project activity. Thus, this is a possible alternative scenario.

B4 The biomass residues are used for heat and/or electricity generation at the project site

In the absence of project activity biomass residues (rice husk) will not be utilized at the project site for heat and/or electricity generation purposes because of


high cost of rice husk. The preferred fuel option for the project proponent will be coal considering cheap price of coal in the region, Therefore, B4 is not a plausible baseline scenario for the rice husk biomass residue.

B5 The biomass residues are used for power generation, including cogeneration, in other existing or new grid-connected power plants

It has been observed that there is 35% surplus availability of the biomass in the region. Thus, the rice husk which will be used in the project activity does not displace utilisation of the same from other plant. In addition , other existing or new biomass fired grid-connected power plants at other sites will not use the surplus biomass residues on their project site considering high cost of biomass in comparison to coal in the absence of additional benefits associated with biomass consumption. Therefore, alternative B5 is not a realistic baseline alternative for rice husk biomass.

B6 The biomass residues are used for heat generation in other existing or new boilers at other sites4

It has been observed that there is 35% surplus availability of the biomass in the region. Thus, the rice husk which will be used in the project activity does not displace utilisation of the same from other boiler. In addition, other existing or new biomass fired heat generation site will not use the surplus biomass residues on their project site considering high cost of biomass in comparison to coal in the absence of additional benefits associated with biomass consumption. Therefore, alternative B6 is not a realistic baseline alternative for rice husk biomass.

B7 The biomass residues are used for other energy purposes, such as the generation of biofuels

As there is no project that uses biomass for other energy purposes at the project site, therefore, this is not a realistic baseline alternative


for rice husk biomass. B8 The biomass residues are used for

non-energy purposes, e.g. as fertilizer or as feedstock in processes (e.g. in the pulp and paper industry)

The biomass residues dumped to decay or burned uncontrolled, so, the biomass consumption of this project is from the local surplus biomass residues in the project region and will not use the residues utilizing for non-energy purposes in absence of this project. Hence this can’t be an alternative scenario.

As defined in ACM 0006 Version 09, in cases where realistic and credible alternative(s) include the installation of new power and/or heat generation facilities at the project site – other than the proposed project activity – the economically most attractive technology and fuel type should be identified among those which provide the same service (i.e. the same heat quantity), technologically that are available and that are in compliance with relevant regulations. The different fuel type options that are in compliance with relevant regulations and which provide with the same service of heat output are:

1. Coal: this is a possible option for the PP. The nearest coal mine is at Bokaro and the cost of coal at pit head is 517 INR/Ton (Source: “Report of the expert committee of fuels on power generation” Executive Summary published by Planning Wing of Central Electricity Authority, Government of India, New Delhi in February 2004). The distance between the coal mine of Bokaro and Gorakhpur is 420 Kms5. the cost of transportation is considered as 394.4 Rs/Ton for a distance of 500 Km (Source: “Report of the expert committee of fuels on power generation” Executive Summary published by Planning Wing of Central Electricity Authority, Government of India, New Delhi in February 2004). Hence the total cost comes to 911.40 INR/MT. With the calorific value of Coal to be 3750 kcal/kg the cost of heat generation comes out to be 92 INR/MJ

2. Furnace Oil: Heat Generation using Furnace Oil is not a possible option for the PP due to the high cost of F.O. the cost of Furnace Oil in the state of U.P. in the year 2004 is 10.593 Rs/Lit6. With the calorific value of Furnace Oil to be 9500 kcal/kg the cost of heat generation comes out to be 368 INR/MJ.

3. Natural Gas: Natural Gas is not available in the Gorakhpur region. Hence this is not an available option with the PP.

4. Rice Husk: This is a possible option for the PP. However the cost of heat generation is 174 INR/MJ

5 http://distancecalculator.globefeed.com/India_Distance_Result.asp?fromplace=Bokaro%20Coalfield%20(Jharkhand)&toplace=Gorakhpur%20(Uttar%20Pradesh)&fromlat=23.8166667&tolat=26.755&fromlng=86&tolng=83.3738889 6 http://www.energymanagertraining.com/eca2004/awardbooklet2004/019-028HINDALCO.pdf

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 37 Hence the economically most attractive option of fuel for heat generation is coal. The analysis justifies B1 and B3 baseline scenario for both the biomass residues i.e slop (biosolids) and rice husk. Hence the alternative A2 is the most possible baseline scenario.

Baseline Scenario Scenario Power Baseline Heat baseline Biomass baseline

(bio solid and rice husk)

Project Type

As per ACM0006/ Version 9.0: Scenario 2

P4:The generation of power in the grid.

H6: The generation of heat in boilers using fossil fuels

B1: The biomass residues are dumped or left to decay under mainly aerobic conditions. This applies, for example, to dumping and decay of biomass residues on fields. B3:The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes.

The project activity involves the installation of a new biomass residue fired power plant at a site where no power was generated prior to the implementation of the project activity. The power generated by the project plant is fed into the grid or would in the absence of the project activity be purchased from the grid. The biomass residues would in the absence of the project activity be dumped or left to decay or burnt in an uncontrolled manner without utilizing it for energy purposes. In case of cogeneration plants, The heat would in the absence of the project activity be generated in


boilers fired with fossil fuels, or by other means not involving the biomass residues.

The baseline scenario identified in concurrence to the scenarios mentioned in the Table 2 of the methodology ACM 0006 Version 09 is scenario 2. The description of the baseline scenario and how the baseline alternative falls under this scenario is described in the below table. Definition of the Baseline Scenario Applicability to the project activity The project activity involves the installation of a new biomass residue fired power plant at a site where no power was generated prior to the implementation of the project activity

The project activity is a green field project activity involving two numbers of 47 TPH Slop fired boiler along with 4.0 MW and 12 MW turbine. No power was generated before the implementation of the project activity.

The power generated by the project plant is fed into the grid or would in the absence of the project activity be purchased from the grid. The biomass residues would in the absence of the project activity be dumped or left to decay or burnt in an uncontrolled manner without utilizing it for energy purposes.

The electricity generated by the project activity is used for meeting the captive requirement at the PP’s plant facility and the surplus power is fed into the grid. In the absence of the project activity the electricity demand at the PP’s distillery unit would have purchased from the grid. The biomass residues would in the absence of the project activity be dumped or left to decay or burnt in an uncontrolled manner without utilizing it for energy purposes.

In case of cogeneration plants, the heat would in the absence of the project activity be generated in boilers fired with fossil fuels, or by other means not involving the biomass residues. This may apply, for example, where prior to the project implementation heat has been generated in boilers using fossil fuel

The steam requirement at the PP’s facility would have been generated using coal based boilers.

Variable Data Source EGy,4.0 – Electricity Generated from 4.0 MW Turbine (kWh)

Records maintained by project proponent

EGy,12 – Electricity generated from 12 MW turbine

Records maintained by the project proponent.

STy,4.0 – Steam to the process from the exhaust of 4.0 MW turbine


STy,12 – Steam to the process from the exhaust of Records maintained by the project proponent.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 39 4.0 MW turbine STy,LD1 – Steam to the process from the Let Down Station 1.


STy,LD2 – Steam to the process from the Let Down Station 2.


Py,process – Pressure of the steam to the process, Records maintained by project proponent Ty,process – Temperature of the steam to the process.


EGy,AUX,B1 - Auxiliary Electricity consumption 1.


EGy,AUX,B1 - Auxiliary Electricity consumption -2.


Qy-Quantity of net heat generation in the project plant that displaces heat generation in fossil fuel fired boilers during the year y (GJ/yr). As per the methodology ACM0006, Version 09, Qy = Qproject

plant, y

Calculated

Parameter Data Source EFOM , y - Build Margin Emission Factor (tCO2/MWh)

Central Electricity Authority CO2 Baseline Database, version 3 dated 15/12/2007

EFBM , y = Operating Margin Emission Factor (tCO2/MWh)


EFgrid,CMy – Grid Emission Factor Calculated as the weighted average of the operating margin and build margin

EFCO2,BL,heat -CO2 emission factor of the fossil fuel type used for heat generation in the absence the project activity (tCO2/GJ)

IPCC Default Value, Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National Greenhouse Gas Inventories

εboiler- Energy efficiency of the boiler that would be used in the absence of the project activity

Manufacturer Specifications

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 CDM project activity (assessment and demonstration of additionality): >> The project activity involves installation of 2 numbers of Slop Fired boilers with a capacity of 47 TPH one number of 4.0 MW back pressure turbine and one number of 12 MW extraction cum condensing turbine and for meeting the captive power and steam requirement at the facility. After meeting the captive power requirement, the plant will export the surplus electricity to the grid. In the absence of the project activity, the bio solids and rice husk that are used in the project activity would have dumped or left to decay under clearly aerobic conditions on fields are burnt in an uncontrolled manner and the PP would have produced steam from the fossil fuel fired boiler and the equivalent amount of electricity would have been generated from the operational/proposed power plants connected to the grid.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 40 As per the selected methodology ACM0006 version 9, the project proponent is required to establish that the project activity is additional and therefore not the baseline scenario, for which the “Combined tool to identify the baseline scenario and demonstrate additionality”, agreed by the CDM Executive Board, available at the UNFCCC CDM web site has been used. Additionality as described in the selected methodology (ACM0006) is discussed further. As per the “Combined tool to identify the baseline scenario and demonstrate additionality” (Version 02.2), the PP needs to follow the following steps to identify the baseline and demonstrate additionality: STEP 1: Identification of alternative scenarios STEP 2: Barrier analysis STEP 3: Investment analysis (if applicable) STEP 4: Common practice analysis. STEP 1: Identification of alternative scenarios This step serves to identify all alternative scenarios to the proposed CDM project activity(s) that can be the baseline scenario through the following sub-steps: Step 1a. Define alternative scenarios to the proposed CDM project activity Identify all alternative scenarios that are available to the project participants and that provide outputs or services with comparable quality, properties and application areas as the proposed CDM project activity. The following alternatives are identified as the realistic and credible alternatives to the project activity for power, heat and biomass. For power generation, the realistic and credible alternative: a) P4: The generation of power in the grid. For heat generation, realistic and credible alternative a) H6: The generation of heat in boilers using fossil fuels. For the use of Biomass residues (slop (bio solids), realistic and credible alternative: a) B1: The biomass residues are dumped or left to decay under mainly aerobic conditions. b) B3: The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes. For the use of Biomass residues (rice husk), realistic and credible alternative: a) B1: The biomass residues are dumped or left to decay under mainly aerobic conditions. b) B3: The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes. Outcome of step 1a: The identified realistic and credible alternative to the project activity is “the generation of power from the grid”, (P4) “the generation of heat in the boilers using fossil fuels that is coal” (H6) and “The biomass residues are dumped or left to decay under mainly aerobic conditions” (B1) and” The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes” (B3). Therefore, the project activity passes Step 1a. Sub-step 1b. Consistency with mandatory applicable laws and regulations:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 41 The alternative(s) shall be in compliance with all mandatory applicable legal and regulatory requirements, even if these laws and regulations have objectives other than GHG reductions, e.g. to mitigate local air pollution.5 (This sub-step does not consider national and local policies that do not have legally-binding status.). All the above alternatives are in compliance with all mandatory applicable legal and regulatory requirements. Thus step 1 is passed. STEP 2: Barrier analysis This step serves to identify barriers and to assess which alternatives are prevented by these barriers. Apply the following sub-steps: Sub-step 2a. Identify barriers that would prevent the implementation of alternative scenarios: The following barriers have been identified that would prevent the implementation of the project activity. Technological barrier: Implementation of the Slop fired boiler is the first of its kind in India. The PP envisaged utilizing concentrated spentwash (Slop) in the boiler for power and steam generation. However, the technology of utilizing the Slop in the boiler for power and steam generation was not available in India before the project activity and had posed technological risk for the project. It was envisaged that the use of concentrated spentwash could result in disrepair, malfunctioning and other underperformance for the equipments in the project activity. The PP studied all the available boiler technology and found out that concentrated spent wash/slops can’t be fired in the existing boiler because it contains around 50% moisture and burns between 500-7000 temperatures. It certainly required modification in the boiler bed area. It is also having high dirts and contains higher percentage of potassium which is having different impact on burner gun and flue gas path. The PP discussed the technological options of utilising the concentrated spentwash/slops/bio-solids and other fuels in the boiler with many boiler manufacturers and found out that the particular technology used in the proposed project activity was not available in India. After long consultation with many boiler manufacturers the PP finally agreed with M/s Cheema Boilers Limited to undertake a demonstration project for the development of the Slop Fired Boiler technology at the Gorakhpur unit. This had led to a Memorandum of Understanding (MOU) with Cheema boiler for a joint effort for the development of the technology to combust the slops. As per the agreed terms and conditions IGL agreed to bear all the risks associated with the non-performance of the boiler and its associated losses during the pilot study. The PP further formulated a special project team that was responsible for the continuous vigilance on the boiler parameters and analyse any operational defectives arising during the operation of the boiler. The PP envisaged the following problems during the conceptualisation stage of the project through their visit to the Guangxi Luzhou Thermal Power Equipments Co. Ltd, Nanning Guangxi, China and discussion with the boiler manufacturers.

• Associating the right boiler manufacturer to develop the specially designed boiler which could fire concentrated spentwash


• Non-availability of skilled and/or properly trained personnel to develop, operate and maintain the technology

• Designing a proper boiler which will meet the requirement for slop firing o The design of boiler need to be changed as two furnaces are required, one to fire

concentrated spentwash and the other to fire supporting fuel. Coherent design of the 2 furnaces in a single boiler will be a problem.

o The PP envisaged increase in the cost of the boiler due to presence of 2 furnaces. o High ash content due to the firing of coherent spentwash. o The nature of firing of biomass in the second furnace i.e. whether it should be fired from

centre or from the end. o The PP envisaged choking problems due to the high moisture content in Slop

• Delay in sourcing the equipment and ancillaries required for operation of the boiler. • The PP envisaged that a failure in getting satisfactory outcomes will result in loss of revenue and

resources. • The boiler will have higher O & M expenses in comparison to conventional boiler which is

around 10-15%.

These apprehensions were faced by the PP and boiler manufacturer during the development of the specially designed boiler. Lack of prevailing practice: The project activity is the first of its kind in India. All the relevant documentation for the new slop fired technology indicates that the technology demonstrated in the project activity is the most current and first in India. M/s Cheema Boiler Limited has received a patent bearing certificate number:223082, Dated 03rd September 2008 issued by The Patent Office ,Govt of India, for the invention of this “Novel Boiler and Process thereof for disposal of distillery waste” in the Gorakhpur site. The above mentioned barriers do not exist for the other alternative vis-à-vis procurement of electricity from the grid and use of fossil fuels in the boiler for steam generation. From the above analysis of barrier for the project activity, we can conclude that the project activity is not a baseline scenario and the project activity is beyond the business as usual scenario. Hence, the project activity would not have occurred in the absence of effort to mitigate the climate change impact and expected CDM contributions. Outcome of Step 2a: List of barriers that may prevent one or more alternative scenarios to occur. Technological Barrier Lack of prevailing Practice Sub-step 2b. Eliminate alternative scenarios which are prevented by the identified barriers: As discussed and observed in the above paragraph, there are significant barriers for Alternative (P1 and H1) – Proposed project activity not undertaken as a CDM project activity for power and heat generation.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 43 Outcome of Step 2b: List of alternative scenarios to the project activity that are not prevented by any barrier. The remaining credible alternative to the proposed project that are not prevented by any barrier is:- For power generation, the realistic and credible alternative: a) P4: The generation of power in the grid. Hence, alternative P4 represents most likely baseline scenario. For heat generation, realistic and credible alternative a) H6: The generation of heat in boilers using fossil fuels. For the use of Biomass residues (slop (bio solids), realistic and credible alternative: a) B1: The biomass residues are dumped or left to decay under mainly aerobic conditions. b) B3: The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes. For the use of Biomass residues (rice husk), realistic and credible alternative: a) B1: The biomass residues are dumped or left to decay under mainly aerobic conditions. b) B3: The biomass residues are burnt in an uncontrolled manner without utilizing it for energy purposes. Following Sub-step 2a and Sub-step 2b, there is one remaining alternative scenario, Alternative 3 (i.e. P4, H6, B1 or B3 ) and this alternative is not the proposed project activity undertaken without being registered as a CDM project activity; thus explanations using qualitative and quantitative arguments on how the registration of the CDM project activity will alleviate the barriers that prevent the proposed project activity from occurring in the absence of the CDM are set out below. This is in line with the Combined Additionality Tool which reads: → If there is only one alternative scenario that is not prevented by any barrier, and if this alternative is not the proposed project activity undertaken without being registered as a CDM project activity, then this alternative scenario is identified as the baseline scenario. Explain – using qualitative or quantitative arguments – how the registration of the CDM project activity will alleviate the barriers that prevent the proposed project activity from occurring in the absence of the CDM. If the CDM alleviates the identified barriers that prevent the proposed project activity from occurring, proceed to Step 4, otherwise the project activity is not additional. Qualitative arguments As set out briefly in Step 2, the project activity experiences technological barriers and Lack of prevailing practice. The registration of the project activity as a CDM project activity allows the project proponent to accept the inherent risks of the power plant arising from technological risks of utilisation slop (bio solids) as a primary biomass fuel. The project activity boiler has been modified several times for the desired quality and quantity steam output. It also have regular operation and maintenance problem which impacts the operability and profitability of the plant. The carbon revenue may assist in overcoming the barriers posed by employment of new technology to ensure the project activity is reasonably viable from commercial perspective. CDM revenue will help to overcome the higher amount of recurring operation and maintenance cost associated with the project activity in comparison to conventional fossil fuel based power plant or boiler. The income from sale of CERs per unit of energy is calculated as 0.13 INR/kWh. This can be compared

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 44 with the value of the energy generation cost of 1.50 INR/kWh. Thus, the CDM revenue compensates for the 8.76 % cost of generation. This additional income from carbon revenue will assist to overcome investment barriers for the project activity. Such additional revenue also enables the project proponent to accept risks associated with low availability of the power plant due to the inherent technological risks arising from use of slop as biomass fuel. Finally, this extra incentive also assists to overcome perceived barriers posed by the new technology employed in the project activity. Quantitative arguments From the quantitative viewpoint, the financial indicators set out below have been identified as most suitable for the project type and decision making context: Investment Benchmark Analysis has been used to ascertain that the proposed project activity is not eeconomically or financially feasible, without the revenue from the sale of certified emission reductions (CERs). For the investment analysis of the project activity the financial indicator namely Net Present Value (NPV) of the cash flows has been considered and calculated. In demonstrating how registration of the project activity as a CDM project activity will alleviate the barriers that prevent the proposed project activity from occurring in the absence of the CDM, the Project NPV has been demonstrated in the Step 3 , Investment analysis. In view of the above, the project activity passes step 2. STEP 3. Investment analysis Investment Benchmark Analysis has been used to ascertain that the proposed project activity is not eeconomically or financially feasible, without the revenue from the sale of certified emission reductions (CERs). For the investment analysis of the project activity the financial indicator namely Net Present Value (NPV) of the cash flows has been considered and calculated. Several financial indicators like IRR, NPV, Cost Benefit Analysis and Levelized unit cost of electricity are available to demonstrate the additionality. Invariably, the choice is between NPV and IRR. NPV, as opposed to IRR is a direct measure of the rupee economic value (or loss) expected on a project and thus facilitates quick decision making. Both NPV and IRR methods involve discounted cash flow analysis, the mathematics of which affects the rate that a project’s cash flows can be reinvested during the life of the project. The reinvestment rate embedded in NPV is the project’s cost of capital which in this case is considered as the interest rate. The reinvestment rate assumed under IRR is the IRR rate itself. Reinvestment at the cost of capital is a better and correct assumption. These features render NPV as a superior financial indicator as compared to IRR for this project activity. The project activity is partly funded by bank and partly by internal accruals. The Interest Rate Structure of Scheduled Commercial Banks as per the Annual Report of Reserve Bank of India dated 29/08/2005 was at 10.25%7 during the year 2004 - 2005. Hence the discount rate for NPV calculation is taken as 10.25% which is equal to the interest on loan. It is imperative that the net cash flows discounted at the

7 http://www.rbi.org.in/Scripts/AnnualReportPublications.aspx?Id=577

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 45 benchmark – being the interest rate on loan – should be at least zero if not positive. A negative NPV is an indicative of the financial unattractiveness of the project activity. All the relevant expenses and revenues associated with the alternatives have been computed to calculate the Project activity cash flow In the current investment benchmark analysis, a period of 20 years has been taken into consideration. Depreciation, and other non-cash items related to the project activity, which have been deducted in estimating gross profits on which tax is calculated, has been added back to net profits for the purpose of calculating the cash flow for the project activity. The major repair and maintenance costs associated with the rehabilitation of the boiler and the turbine are taken as the expenses to be incurred. PP will also incur costs for the purchase of Rice Husk and Coal that will be used in the project activity. The PP will also be paying certain amount to the bank as the interest along with the principle repayment for a particular year. These costs are considered as the cash outflow for the project activity. The Gorakhpur plant requires 20 772 MWh for distillery plant captive electricity requirement. In the absence of the project activity the same would have been procured from the Uttar Pradesh Power Corporation Ltd (UPPCL) The cost for the procurement of electricity to meet the distillery load requirement of 20 772 MWh from the Uttar Pradesh Power Corporation Ltd (UPPCL) is taken as the notional revenue in the project activity and is considered as cash inflow. In the second stage (i.e. after commissioning of 12 MW TG set which is expected to happen in 2010) the Power plant will supply 20 772 MWh for distillery plant requirement and 17 474 MWh for the auxiliary electricity consumption of the 2 Slop fired boilers and the 12 MW turbine and will export 57 857 MWh to grid. The PP will be selling 57 857 MWh of electricity per annum. The revenue from the sale of the electricity is considered as the cash inflow. From the 5th year of operation, i.e. after the commissioning of the 12 MW turbine, both the Slop fired boilers will be commissioned and it is estimated that around 39 TPH of steam will be generated from each boiler vis-à-vis 78 TPH from both the boilers. 60TPH will be supplied to 12 MW turbine and 18TPH will be supplied to 4 MW turbine. As per the power sheet provided by the 12 MW turbine manufacturer the guaranteed scenario will be having a steam inlet flow of 60 TPH out of which around 40 TPH steam will be used for condensing and 20 TPH steam will be extracted to the process. The power output in this scenario is 11.772 MW corresponding to the gross electricity generation of 84 758 MWh. PP has a contract demand from the Uttar Pradesh Power Corporation Limited (UPPCL) for its distillery plant premises. Whilst the project activity would have displaced grid imports, the factory will require to have continued connection to the grid to meet its electricity demand during full operation of the distillery unit and shut down period of the power plants. Hence, the project proponent will continue to pay for the demand charges even in the project activtiy. Since there is no saving in the demand charges, they are not considered as revenues for the project activity.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 46 The Performance Guarantee (PG) test was conducted on the 4 MW turbine indicating an average specific consumption of 11.423 Tons of steam per MWh of generation. The steam to the 4 MW turbine will be around 18 TPH thereby the power generation will be 1.575 MW corresponding to the gross electricity generation of 11 345 MWh. Hence the total gross electricity generation from the project activity is 96 103 MWh. The auxiliary electricity consumption will be 17 474 MWh and hence the net electricity generation will be 78 629 MWh. In order to compute the cash flows, the PP has made certain assumptions, which together with the basis for making such assumptions are as follows: Description Quantity Source Cost of 1st Cheema Boiler and other accessories (INR Millions) 93.01

The actual P.O. cost has been considered.

Cost of 2nd Cheema Boiler (INR Millions) 125.50

Capex

Cost of 12 MW Turbine (INR Millions) 195.00

Capex

Cost of 4 MW turbine (INR Millions) 30.38

The actual P.O. cost has been considered

Project Cost (INR Millions) 443.89

Equity (INR Millions) 133.17 Estimate

Term Loan (INR Millions) 310.73 Estimate

Net Electricity Generation (MWh) 78 629 Calculated based on Performance guarantee test of turbines

Distillery plant Electricity Consumption (MWh) 20 772 Calculated

Power for the sale to Grid (MWh) 57 857 Plant Estimate

Price of Electricity (INR/kWh) 3.5875 UTTAR PRADESH ELECTRICITY REGULATORY COMMISSION ORDER8

Base tariff for electricity imported from grid (year 2005-2006) (INR/kWh) 2.50 Third Party document9 Rice Husk Requirement per annum (tonnes) 61486 Estimate

Quantity of coal requirement per annum (tonnes) 27282 Estimate

Price of Rice Husk (INR/tonne) 1500.00 Supplier Quotation

8 http://www.uperc.org/Tariff%20Order%20UPPCL%20-%2004-05.zip 9 Document from U.P. Sugar Mills Cogen Association dated 18/10/2004


Price of coal from market (INR/tonne) 911.40

Source: “Report of the expert committee of fuels on power generation” Executive Summary published by Planning Wing of Central Electricity Authority, Government of India, New Delhi in February 2004

Escalation on cost of fuel (%) 4%

Uttar Pradesh Electricity Regulatory Commission (UPERC) Order on suo moto proceedings in the matter of Terms and Conditions of Supply and Tariff for Captive Generating Plants and Renewable and NCE source based plants10

Escalation in Tariff (%) 4% Third Party document11

Operating days per annum(days) 300 Plant Estimate

Operating Hours (hours) 24 Plant Estimate

O&M Expenses (10% of capital Cost) 10.00%

Project note submitted to the management during the project conceptualization stage

Increase in O&M Expenditure (%) 4%

UPERC Order on suo moto proceedings in the matter of Terms and Conditions of Supply and Tariff for Captive Generating Plants and Renewable and NCE source based plants12

Salaries & Wages ( INR Millions) 20.00 Project note submitted to the management during the project conceptualization stage

Administrative Expenses (INR Millions) 20.00

Salary Hike (%) 10% HR Statement

Loan Repayment (yrs) 10 Estimate

10 http://uperc.org/Copy%20of%20Order%20-UPERC%20NCE%20Policy%20FINAL%20DT.18-7-2005.pdf, Page No. 17 11 Document from U.P. Sugar Mills Cogen Association dated 18/10/2004 12 http://uperc.org/Copy%20of%20Order%20-UPERC%20NCE%20Policy%20FINAL%20DT.18-7-2005.pdf, Page No. 17

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 48 Moratorium (years) 0 Number of Quarterly Instalments (number) 40 Estimate

Interest Rate (%) 10.25%

Interest Rate Structure of Scheduled Commercial Banks as per the Annual Report of Reserve Bank of India dated 29/08/200513

CER's (tCO2e) 110157 Based on ER calculation

Price of CER (EURO) 10

Exchange Rate (INR) 58

http://www.exchangerate.com/past_rates.html?letter=I&cont=&cid=109&year=2004&month=10&currency=266&action=Submit

Rate of Depreciation as per company's law

Plant and Machinery (%) 5.28% Company’s Law

Maximum Depreciation (%) 90.00% Company’s Law

Rate of Depreciation for IT (Electricity Supply's Act)

Plant and Machinery (%) 7.84% Electricity Supply Act

MAT (%) 10.00% I.T. Rules

Normal Income Tax (%) 30.00% I.T. Rules

Surcharge (%) 10.00% I.T. Rules

Educational Cess (%) 2.00% I.T. Rules The financial analysis made, based on the above assumptions, reveals that the project activity is not financially attractive as the NPV (of net cash flows discounted at 10.25%) without CDM revenues is INR−.103.60 million (negative 103.60 million). However, when the benefits from CDM revenues are taken into account (considering CERs at Euro 10/tCO2 and an exchange rate of INR58 per Euro), the NPV becomes positive at INR 54.59 million. Therefore, it is only with carbon credits the PP would achieve a positive NPV. The NPV becomes 0 when the project cost is decreased by 19.07 % which is not a realistic scenario as the project cost is based on Capex, The actual costs incurred till date is INR 411.86 Million, which is 92.79% of the project cost considered in the Investment analysis. The cost of INR 411.86 Million doesn’t include the Pending civil works (Control Room, MCC Room, Building column, flooring, Drainage,

13 http://www.rbi.org.in/Scripts/AnnualReportPublications.aspx?Id=577

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 49 Auxiliary Foundation Etc. with materials) Mechanical OSBL Piping, Building structure, canopy etc with materials and Electrical & Instrumentation works. The NPV becomes 0 when the O&M costs are decreased by 42. 41% which is not a realistic scenario as the actual O&M costs are around 12% of the project costs for the year 2006-2007 and 15% for the year 2007-2008. The NPV becomes INR 0.00 million when the fuel costs are decreased by 27. 53% which is highly unrealistic scenario. The trend is normally increase in price of fuel cost. The Uttar Pradesh Electricity Regulatory Commission (UPERC) Order on suo moto proceedings in the matter of Terms and Conditions of Supply and Tariff for Captive Generating Plants and Renewable and NCE source based plants considers an annual increase of 4% in the price of fuel which substantiates the fact that the decrease in fuel cost is a highly unrealistic scenario. The actual increase in the cost of rice husk is 15% for the year 2009 to 2010. The base cost for the rice is considered as INR 1500.00 per ton for the rice husk which has been considered from the quotation from the supplier. The base cost for the coal is considered as INR 911.00/Ton of coal as the supporting document for the same is Report of the expert committee of fuels on power generation” Executive Summary published by Planning Wing of Central Electricity Authority, Government of India, New Delhi in February 2004. These prices for the rice husk and coal were considered in the Chartered engineer audit report on comparison of cost of steam generation for different types of fuels. The NPV becomes INR 0.00 millions when the tariff for the sale of electricity is increased by 14.54% which is unrealistic as the tariff considered for the investment analysis is from the UPERC tariff order and the same rates are still prevailing. The NPV becomes INR 0.00 millions when the tariff for the purchase of electricity is increased by 18.17% which is unrealistic as the tariff considered for the investment analysis is from the UPERC tariff order for the FY 2005 which is applicable for the FY 2005 and FY 2006, in the subsequent tariff order for the purchase of electricity issued by UPERC dated 10/05/200714 for the FY 2007 there has been a decrease of the weighted purchase price of electricity by 1.83%. Thus from the above discussion it can be concluded that the project activity faces the investment barrier and is not a business as usual scenario. Sensitivity analysis has been conducted to assess whether the conclusion regarding the financial attractiveness is robust to reasonable variations in the critical assumptions. Sensitivity analysis has been performed varying the critical assumption i.e. the Project Cost, the Operation and Maintenance Expenses, the fuel cost, the tariff of purchase of electricity, the tariff for the sale of electricity to the grid and change in Net Electricity Generation. All these assumptions have been decreased and increased by 10% The investment analysis is also subjected to sensitivity by considering a scenario where electricity generation can be increased. The electricity generation has been increased by 21% which reflects that NPV at 21% variation is still negative. This is the scenario where out of the 60 TPH inlet flow into the 12 MW turbine 10 TPH will be extracted to the process and the remaining 50 TPH will be used for condensing. In this scenario around 44 TPH steam is expected to be generated from each boiler and 28 14 http://www.uperc.org/TARIFF%20ORDER%20FY%202006-07.zip

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 50 TPH steam will be used in the 4 MW turbine. This scenario will generate the maximum power output from the project activity as per the turbine performance parameters from the 12 MW turbine manufacturers. The net electricity generation from the 12 MW turbine and 4 MW turbine in this scenario will be 94 904 MWh in comparison to the originally estimated figure of net electricity generation of 78 629 MWh. In this scenario the NPV (of net cash flows discounted at 10.25%) without CDM revenues is (− INR 59.26 million). However this scenario is not possible as theoretically and practically the slop fired boiler can generate a maximum of 39 TPH steam.

VARIATION FACTOR -10% 0% 10%

Project cost -49.42 -103.60 -158.86 O&M Expenses -79.28 -103.60 -128.82 Fuel Cost -65.68 -103.60 -143.28 Tariff (purchase) -163.10 -103.60 -45.99 Tariff (sale) -181.67 -103.60 -32.15 Change in Electricity Generation -123.24 -103.60 -85.55 Benchmark 0.00

Hence sensitivity analysis confirms that conclusion regarding the financial attractiveness is robust to reasonable variations in the critical assumptions The above investment analysis further substantiates that the project activity will not be financially viable without the CDM revenue. Thus, CDM revenue is required to overcome the risks associated with the project activity and also partially compensate for the additional investment that was done developing the Slop Fired Boiler for the first time in India. STEP 4. Common practice analysis It is common among distillery unit to utilise coal or biomass in low efficient boilers to supply steam for their own needs. However, the fuel option is totally dependent on generation cost from coal and biomass. It varies depending on the location and incentive receives by the project proponent for the use of biomass. Moreover, the project activity involves cogeneration with sale of surplus electricity to the grid. Moreover, there is no distillery in the state of Uttar Pradesh which exports electricity to the grid. The IGL Project clearly goes beyond the business as usual scenario in the distillery sector which are opted for evaporation treatment option through its investment in a novel boiler technology development, dedicated to supplying electricity directly to transmission grid. The IGL Project was the first of its kind in India which uses Slop in the boiler and will sell renewable energy from cogeneration unit to State Electricity Board (SEB).

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 51 Thus, similar kind of project activities has not been implemented. Slop is a semi-solid biomass residue (i.e. it is of both liquid state and solid state). The cogeneration technologies that have been implemented in India are capable of burning either solid biomass residues or gaseous biomass. This kind of technology of burning Slops which is a semi solid biomass residue is being implemented for the first time in India through this demonstration project. The differences between a normal biomass fired boiler and a slop fired boiler is detailed in the below table: Sl. No.

Conventional Biomass Fired Boiler Slop Fired Boiler

1 In conventional boilers the biomass is fired through proven method thus easy to burn & higher efficiency of the boilers

Slop with 50% moisture is fired directly in the boilers, which often disturbs the boiler furnace and also higher loss in the efficiency

2 Boiler pressure parts do not get frequent fouling due to ash in flue gas, thus no frequent shut downs are required for flue gas path cleaning

Boiler flue gas path get frequently choked with ash carried-in flue gas, thus require frequent shut down for flue gas path cleaning

3 Normal soot deposition requires normal pressure steam soot blowing

Higher deposition of soot / ash needs high pressure pneumatic (ash is of hygroscopic nature) soot blowing

4 Boiler feed water inlet temperature is designed at 105 0C, just to ensure proper deaeration of feed water, economizer is installed to recover the heat from flue gas

Due to about 4% sulphur content in slop, possibility of cold end corrosion is much higher, to eliminate this the feed water is fed at around 220 0C directly to steam drum, no economizer is installed

5 Ordinary MOC for deaerator & feed pump to handle feed water at 105 0C

Special MOC for deaerator & feed pump to handle feed water at higher temperatures

6 Boiler exhaust flue gas temperature is designed at 140 0C, based on flue gas dew point temperature, the boiler exit flue gas heat is recovered in air pre-heater to achieve this temperature

Due to higher sulphur content in the fuel, the flue gas dew point temperature is increased, to avoid cold end corrosion, the flue gas exit temperature is maintained at 280 0C.

7 The height of the boiler is relatively lower than the slop fired boiler at same generation capacity

The height of the boiler is much higher than the similar capacity of other biomass fired boilers. The slop is introduced above 7mtrs. (approx.) height, so that it could get sufficient resident time to burn in the furnace.

8 Flue gas velocity is maintained 5-7mps The flue gas velocity is maintained 8-10mps, which further increases as the fouling of flue gas path in the boiler, this also leads to higher erosion of pressure parts

9 Lesser heating surface of the boiler and one furnace design, the cost of boiler is lower

Higher heating surface and two furnace design makes the boilers costlier

10 The boiler is used to generate the super heated steam, the super heater is placed in same furnace

Due to high fouling tendency of fuel, the parts like super heater & economizer are installed in separately fired furnace

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 52 11 Due to compact one furnace design operation of

boiler is easy Due to two furnace design the boiler operation is complex

12 Because of one furnace design, all mountings, accessories, instruments & controls are installed for one boiler

Because of two furnace design, all mountings, accessories, instruments & controls are installed for two separate boilers

As per, paragraph 117, Annex 3, EB51, “Clean Development Mechanism Validation and Verification manual Version 01.1”, first of its kind project activity does not require to demonstrate common practice analysis. Thus, Sub-step 4 is satisfied, i.e. (i) similar activities cannot be observed then the proposed project activity is additional. As per the EB’s Guidance on Demonstration and assessment of the prior consideration of the CDM the following table indicates the events taken up by the PP to indicate that continuing and real actions were taken to secure CDM status for the project in parallel with its implementation. The PP decided implement the project activity considering CDM Revenue on 21st October 2004 Activity

Date Evidences

CDM Consideration by the audit committee of IGL 21st October 2004 Copy of the audit committee report

Continuing and Real Actions to secure CDM status

Project Progress Date of Implementation

Evidences

Negotiation with M/s Quality Growth Services (QGS) for undertaking CDM Consultancy Services

6th March 2005

Offer from PWC for undertaking CDM Consultancy Services

25th March 2005

Issuance of the P.O. of the 1st Slop fired Boiler for the start of pilot study to Cheema Boilers Limited

3rd May 2005 P.O. Copy with P.O. No. G06070012

Signing of Contract with M/s QGS for undertaking the CDM Consultancy Services

5th August 2005

Start of the Construction work for the project activity

16th August 2005. Work Order with Ref No. IGL/CIVIL/GKP/05-06/027

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 53 Issuance of the P.O. of

the 4.0 MW turbine of DLF make with alternator of BHEL make

3rd September 2005

P.O. Copy with P.O. No.G05070278

Issuance of P.O. of Second Slop fired Boiler to Cheema Boilers Limited

25th October 2006 P.O. Copy with P.O. No.G06070861

Date of 1st major modification on the Slop fired boiler

26th November 2006

Communication related to the sale of Potential CER’s

21st June 2007, 26th June 2007

Signing of Term Sheet for the sale of CER’s

16th July 2007

Date of 2nd major modification on the Slop fired boiler

28th July 2007

Date of 3rd major modification on the Slop fired boiler

30th August 2007

Date of 4th major modification on the Slop fired boiler

29th October 2007

Issuance of the P.O. of the 12 MW turbine to Guangzhou Guangzhong Enterprises Corp

29th October 2007. P.O. Copy with Ref: PO/IGL/IMP/07070002

Successful stabilization of the boiler and date of completion of the pilot study

1st December 2007.

Start of the construction work for the 2nd Slop fired boiler

25th June 2007 Work Order with Ref No. IGL/CIVIL/GKP/07-08/233

Start of construction work for the 12 MW turbine

18th August 2008 Work Order No. 46000000227

Appointment of Core CarbonX Solutions Pvt Ltd as additional consultant for undertaking the consultancy services for the project activity

02nd April 2008 Agreement Copy between Core CarbonX Solutions Pvt Ltd and India Glycols Limited

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 54 Proposal received from DNV for the validation of the project activity

05th July 2008

Appointment of DNV for undertaking the validation services for the project activity

13th August 2008.

Hosting of the PDD for Global Stakeholder Comments

10th September 2008

Meeting with Indian DNA for Host Country Approval

16th October 2008 Host Country Approval received from Indian DNA

Host Country Approval Letter

17th April 2009 Host Country Approval received from Indian DNA

Expected Commissioning date of the 2nd Slop fired boiler.

June 2010

Expected Commissioning date of the12 MW turbine.

June 2010

Expected Date of Start-Up of the project activity

June 2010

Quality Growth Services (QGS) was appointed as the CDM consultant for the project activity on 5th August 2005. The PDD was under development by QGS and was updated regularly based on the modifications associated with the development of the Slop fired boiler. As this was a demonstration project activity many inputs associated with the technology of the boiler to be described in the PDD were continuously changing during the development stage of the project activity. As there was an uncertainty on the final output capacity of the boiler and other technological parameters of the boiler which was dependent on the final outcome of the pilot study, the PDD for this project activity couldn’t be concluded during the initial years of development of the project due to the above reasons. The PP had approached DNV on 06/12/2006 and appointed them as the DOE to start the process of validation for another project for the Kashipur unit. However, DNV was not appointed for the present project activity during that time due to delay in finalisation of the PDD because of continuous change in the parameters of the boiler. In addition, the project proponent also envisaged to complete the implementation of the present project activity during the year 2010. Hence all the steps for the CDM validation were taken up accordingly. The contract signed with QGS was valid for 30 months from 5th August 2005 and expired on 5th January 2008. QGS has started its association with another CDM consultant Core CarbonX during the early 2008 for the development of its CDM projects. Accordingly, the PP had signed another contract with Core CarbonX Solutions Pvt Ltd during April 2008 for the development of the CDM projects. The intention of QGS and PP were to expedite the CDM validation process and smooth registration of the present project by seeking the help from Core CarbonX who had good expertise in the development of CDM projects. After involvement of Core CarbonX the PDD was finally freezed and submitted to DOE and for HCA during August 2008. B.6. Emission reductions:


B.6.1. Explanation of methodological choices: >> The project activity mainly reduces CO2 emissions through substitution of power and heat generation with fossil fuels by energy generation with biomass residues. The emission reduction ERy by the project activity during a given year y is the difference between the emission reductions through substitution of electricity generation with fossil fuels (ERelectricity,y), the emission reductions through substitution of heat generation with fossil fuels (ERheat,y), project emissions (PEy), emissions due to leakage (Ly) and baseline emissions due to the natural decay of biomass residues (BEbiomass,y), as follows:

Where: ERy = Emissions reductions of the project activity during the year y (tCO2/yr) ERelectricity,y = Emission reductions due to displacement of electricity during the year y (tCO2/yr) ERheat,y = Emission reductions due to displacement of heat during the year y (tCO2/yr) BEbiomass,y = Baseline emissions due to natural decay or burning of anthropogenic sources of biomass residues during the year y (tCO2e/yr) PEy = Project emissions during the year y (tCO2/yr) Ly = Leakage emissions during the year y (tCO2/yr) Project emissions Project emissions include • CO2 emissions from transportation of biomass residues to the project site (PETy), • CO2 emissions from on-site consumption of fossil fuels due to the project activity (PEFFy), • CO2 emissions from consumption of electricity (PEEC,y), • CH4 emissions from the combustion of biomass residues (PEBiomass,CH4,y) Project Emissions are calculated as follows:

PETy = CO2 emissions during the year y due to transport of the biomass residues to the project plant (tCO2/yr) PEFF,y = CO2 emissions during the year y due to fossil fuels co-fired by the generation facility or other fossil fuel consumption at the project site that is attributable to the project activity (tCO2/yr) PEEC,y = CO2 emissions during the year y due to electricity consumption at the project site that is attributable to the project activity (tCO2/yr) The project emissions associated with the electricity consumption is being calculated using the Tool to calculate baseline, project and/or leakage emissions from electricity consumption, Version 01. As described the sources for the electricity consumption is grid. Hence, Scenario A: Electricity consumption from the grid as per the tool is applicable to the project activity. GWPCH4 = Global Warming Potential for methane valid for the relevant commitment period

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 56 PEBiomass,CH4,y = CH4 emissions from the combustion of biomass residues during the year y (tCH4/yr) PEWW,CH4,y = CH4 emissions from waste water generated from the treatment of biomass residues in year y (tCH4/yr)

Parameter Description Value Source

ACM 0006 Version 09

PETy CO2 emissions during the year y due to transport of the biomass residues to the project plant (tCO2/yr)

Calculated

Ny Number of truck trips during the year y 6150 Rice husk which is used as supporting fuel will be transported from the near by areas.

AVD y Average round trip distance (from and to) between the biomass residue fuel supply sites and the site of the project plant during the year y (km)

100 Rice Husk will be transported within a radius of 100 Kms

EFkm,CO2,y Average CO2 emission factor for the trucks measured during the year y (tCO2/km)

0.000768 The Emission factor of diesel is taken as 77.4 tCO2e/TJ and the calorific value of the diesel is considered as 10000 Kcal/Kg. The density is considered as 0.83 Kg/lit. The NCV and density value have been calculated from The Central Electricity Authority (CEA): CO2 baseline database Version 3.0 dated 15th December 2007. It has been assumed that he mileage of the vehicle used for rice husk transportation is considered as 3.5 Km/lit


PEFFy = PEFCj,y

“Tool to calculate project or leakage CO2 emissions from fossil fuel combustion” Version 02/ ACM 0006 Version 09

PE FC,j,y the CO2 emissions from fossil fuel combustion in process j during the year y (tCO2 / yr); FCi,j,y is the quantity of fuel type i combusted in process j during the year y (mass or volume unit / yr); COEFi,y is the CO2 emission coefficient of fuel type i in year y (tCO2 / mass or volume unit); i are the fuel types combusted in process j during the year y.

Calculated

FFprojectplant,coal,y Fossil fuels (Coal) combusted in the project plant during the year y(tones)

27284 Coal will be co-fired in the project plant

FFproject

plant,HSD,y Fossil fuels (HSD) combusted at the project site for other purposes that are attributable to the project activity during year y(KL

1000 Diesel will be consumed in the DG sets that have been installed to provide the start-up for the Project Plant in case of shut down. In such circumstances the quantity of diesel consumed will be monitored by IGL and will be used to calculate the project emissions. However for ex-ante calculation this value is assumed to be 1000 litres.

COEFcoal,y CO2 emission coefficient of coal in year y (tCO2 / tonne)

1.407 Calculated from NCVcoal,y and EFCO2,coal,y

NCVcoal,y NCVi,y is the weighted average net calorific value of the coal in year y (GJ/mass or volume unit)

3500 On site measurement systems will be adopted to test the calorific value of coal once in 6


months EFCO2,coal,y weighted average CO2 emission factor of

coal in year y (tCO2/GJ) 96.1 IPCC Default

Value COEFHSD,y CO2 emission coefficient of HSD in year y

(tCO2 / KL) 3.101 Calculated from

NCVHSD,y and EFCO2,HSD,y

NCVHSD,y NCVi,y is the weighted average net calorific value of the HSD in year y (GJ/mass or volume unit)

10000 CENTRAL ELECTRICITY AUTHORITY: CO2 BASELINE DATABASE, Version 3.0 dated 15th December 2007

EFCO2,HSD,y weighted average CO2 emission factor of coal in year y (tCO2/GJ)

74.1 IPCC Default Value

Tool to calculate baseline, project and/or leakage emissions from electricity consumption, Version 01.

PEEC,y Project emissions from electricity consumption in year y (tCO2/yr)

Calculated

ECPJ,j,y Quantity of electricity consumed by the project electricity consumption source j in year y (MWh/yr)

1000 Plant Data

EFEL,j,y Emission factor for electricity generation for source j in year y (tCO2/MWh)

0.8105 Tool to calculate baseline, project and/or leakage emissions from electricity consumption, Version 01. The Emission factor applied is the combined margin emission factor of the applicable electricity system, using the procedures in the latest approved version of the “Tool to calculate


the emission factor for an electricity system” (EFEL,j/k/l,y = EFgrid,CM,y

=EFelectricity,y) This is in accordance with option A.1 in the Tool to calculate baseline, project and/or leakage emissions from electricity consumption, Version 01. The value has been calculated from The Central Electricity Authority (CEA): CO2 baseline database Version 3.0 dated 15th December 2007

TDL j,y Average technical transmission and distribution losses for providing electricity to source j in year y

29.1% The T&D losses for Lucknow Discom as reported by Uttar Pradesh Electricity Regulatory Commission for the FY year 2007-2008 & 2008-2009 in the Tariff Order for FY 2007-2008 & FY 2008-2009 for Discom and Transco has been considered

J Sources of electricity consumption in the project

UPSEB Plant Data

ACM 0006 Version 09

PEBiomass,CH4,y CH4 emissions from the combustion of biomass residues during Calculated


the year y (tCH4/yr). BFk,y

Quantity of biomass residue type k combusted in the project plant during the year y (Tonnes)

92160 Plant Data

NCVSlops Net calorific value of the biomass residue type k (Slops) (GJ/tonne)

14.91 On site Laboratory tests will be performed to assess the Calorific Value of Slops once every 6 months

EFCH4,BF CH4 emission factor for the combustion of biomass residues in the project plant (tCH4/GJ)

0.0000411 CH4 emission factor for the combustion of biomass residues in the project plant (tCH4/GJ) As per ACM 0006 Version 09 Table 4 with conservativeness factor as per table 5 of the methodology ACM 0006 Version 09. Default value from the methodology is chosen as there are no local reliable values and there are no measurement procedures that the PP can adopt for calculation of CH4 emission factor.

PEWW,CH4,y = CH4 emissions from waste water generated from the treatment of biomass residues in year y (tCH4/yr). As the project activity doesn’t generate any wastewater from the treatment of the biomass residues hence the estimation of these emissions is excluded. Emission reduction calculations Emission reductions due to the displacement of electricity are calculated by multiplying the net quantity of increased electricity generated with biomass residues as a result of the project activity (EGy) with the CO2 baseline emission factor for the electricity displaced due to the project (EFelectricity,y), as follows: Input values and data sources for emission reductions associated with electricity displacement



Equation (8) version 09,

ACM0006 ER,electricity,y Emission reductions due to displacement of electricity during

the year y (tCO2/yr) Calculated

EGy, Net quantity of increased electricity generation as a result of the project activity (incremental to baseline generation) during the year y (MWh)

78629 Calculated

EFelectricity.,y CO2 emission factor for the electricity displaced due to the project activity during the year y (tCO2/MWh)

0.8105 Calculated

Determination of EFelectricity,y For Scenario 2, EFelectricity,y is calculated as follows: The emission factor for the displacement of electricity should correspond to the grid emission factor (EFelectricity,y = EFgrid,CM,,y) and EFgrid,grid,CMy shall be determined as follows:

• If the power generation capacity of the project plant is of more than 15 MW, EFgrid,CM,y should be calculated as a combined margin (CM), following the guidance in the section “Baselines” in the “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (ACM0002).

• If the power generation capacity of the project plant is less or equal to 15 MW, project participants may alternatively use the average CO2 emission factor of the electricity system, as referred to in option (d) in step 1 of the baseline determination in ACM0002.

As the power generation in the project plant is greater than 15 MW, hence EFgrid,CM,y is calculated as a combined margin (CM), following the guidance in the section “Baselines” in the “Consolidated baseline methodology for grid-connected electricity generation from renewable sources” (ACM0002) which prescribes “Tool to calculate the emission factor for an electricity system” to calculate the combined margin (CM) Step 1. Identify the relevant electric power system Grid Selection This approach is based on the assumption that the renewable energy project is displacing the average electricity mix in the grid. In India, power is a concurrent subject between the state and the central governments. The perspective planning, monitoring of implementation of power projects is the responsibility of Ministry of Power, Government of India. At the state level the state utilities or state electricity boards (SEBs) are responsible for supply, transmission, and distribution of power. With power sector reforms there have been unbundling and privatization of this sector in many states. Many of the state utilities are engaged in power generation also. In addition to this there are different central / public sector organizations involved in generation like National Thermal Power Corporation (NTPC), National Hydro Power Corporation (NHPC), etc. in transmission e.g. Power Grid Corporation of India Ltd.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 62 (PGCIL) and in financing e.g. Power Finance Corporation Ltd. (PFC). There are five regional grids: Northern, Western, Southern, Eastern and North-Eastern. Different states are connected to one of the five regional grids as shown in below table. Northern Western Southern Eastern North Eastern Haryana Gujarat AP Bihar Assam HP MP Karnataka Jharkhand Manipur JK Chhattisgarh Kerala Orissa Meghalaya Rajasthan Maharashtra TN WB Nagaland UP Goa Lakshadweep D.V.C Tripura Uttaranchal D.N.H Pondicherry A & N Arunachal

Pradesh Chandigarh Daman & Diu Sikkim Mizoram Delhi The management of generation and supply of power within these grids is undertaken by the load dispatch centres (LDC). Different states within the regional grids meet the demand from their own generation facilities plus generation by power plants owned by the central sector i.e. NTPC and NHPC etc. Specific quota is allocated to different states from the central sector power plants. Depending on the demand and generation there are exports and imports of power within different states in the grids. Thus there is trading of power between states in the grid. Similarly there is import and export of power between grids. Since the CDM project is connected to the Northern grid it is also preferred to take the Northern grid as project boundary than the state boundary. It also minimizes the effect of inter state power transactions, which are dynamic and vary widely. Step 2. Select an operating margin (OM) method The calculation of the operating margin emission factor (EFgrid,OM,y) is based on one of the following methods: (a) Simple OM, (b), Simple adjusted OM, (c) Dispatch Data Analysis, or (d) Average OM. The two variants “Simple adjusted operating margin” and “Dispatch data analysis operating margin” cannot currently be applied in India due to lack of necessary data. In India, hydro and nuclear stations qualify as low-cost / must-run sources and are excluded. The operating margin, therefore, can be calculated by dividing the region’s total CO2 emissions by the net generation of all thermal stations. Thus, Simple OM has been chosen. The Central Electricity Authority (CEA): CO2 baseline database Version 3.0 dated 15th December 2007 have been publicised and the simple OM has been referred for the OM calculation. The ex-ante option has been selected for the Project. Step 3. Calculate the operating margin emission factor according to the selected method (OM)

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 63 The Operating Margin is calculated considering of the average of Operating Margin date for the NEWNE as published by CEA during the years 2004-2005, 2005-2006, 2006-2007 . The average value for the Northern Grid is 0.9925 tCO2/MWh. Operating Margin (2004-2005) (tCO2e)

Operating Margin (2004-2005) (tCO2e)

Operating Margin (2004-2005) (tCO2e)

Average (tCO2e)

0.9801 0.9991 0.9984 0.9925 Step 4. Identify the cohort of power units to be included in the build margin (BM) The build margin is calculated as the generation-weighted average emission factor of a sample of power plants. As per the Tool, the sample group to calculate BM consists of either: (a) The set of five power units that have been built most recently, or (b) The set of power capacity additions in the electricity system that comprise 20% of the system

generation (in MWh) and that have been built most recently. The option (b) has been chosen for the BM calculation. As per the annex 12, EB 35 “Tool to calculate the emission factor for an electricity system” In terms of vintage of data, project participants can choose between one of the following two options: Option 1. For the first crediting period, calculate the build margin emission factor ex-ante based on the most recent information available on units already built for sample group m at the time of CDM-PDD submission to the DOE for validation. For the second crediting period, the build margin emission factor should be updated based on the most recent information available on units already built at the time of submission of the request for renewal of the crediting period to the DOE. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. This option does not require monitoring the emission factor during the crediting period. Option 2. For the first crediting period, the build margin emission factor shall be updated annually, ex-post, including those units built up to the year of registration of the project activity or, if information up to the year of registration is not yet available, including those units built up to the latest year for which information is available. For the second crediting period, the build margin emissions factor shall be calculated ex-ante, as described in option 1 above. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. The option (1) ex-ante calculation option has been chosen. This has been established by CEA. Step 5. Calculate the build margin emission factor The build margin considered is for the year 2006-2007 for the Northern grid and the value is 0.6283 tCO2/MWh. The data for the build margin and the operating margin is taken from the Central Electricity Authority CO2 Baseline Data base Version 03. Step 6. Calculate the combined margin emission factor The combined margin emission factor is calculated as follows:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 64 Input values and data sources for the calculation of EFy,grid

Parameter Description Unit Source

“Tool to calculate the emission factor for an electricity system” version 0.1.1, equation 13

EFgrid,CM,,y Combined margin CO2 emission factor in year y. This equals to EFy,grid.

tCO2/MWh Calculated

EFgrid,OM,y Simple operating margin CO2 emission factor in year y.

tCO2/MWh Calculated

EFgrid,BM,y Build margin CO2 emission factor in year y

tCO2/MWh Calculated

wOM Weighting of operating margin emission factor

% “Tool to calculate the emission factor for an electricity system” version 0.1.1, equation 13

wBM Weighting of build margin emission factor

% “Tool to calculate the emission factor for an electricity system” version 0.1.1, equation 13

Baseline Emission Factor: Average OM & BM = 0.8105 tCO2e/MWh. The Grid emission factor is fixed ex-ante for the entire crediting period. Determination of EGy

For Scenario 2, EGy corresponds to the net quantity of electricity generation in the project plant (EGy = EGproject plant,y). EGprojectplant,y equals the net electricity generation from the 4.0 MW turbine and the 12 MW turbine. EGproject plant,y = EGy,4.0 + EGy,12 – EGy,AUX,B1 - EGy,AUX,B2 Emission reductions or increases due to displacement of heat For Scenario 2 which is applicable to the project activity the Emission Reductions due to the displacement of heat is as follows:


ACM 0006 Version 09

ER,heat,y Emission reductions due to displacement of heat during the Calculated


year y (tCO2e/yr) Qy, Quantity of net heat generation in the

project plant that displaces heat generation in fossil fuel fired boilers during the year y (GJ/yr). As per the methodology ACM0006, Version 09, Qy = Qproject plant, y

754432.848 Calculated

EFCO2,BL,heat CO2 emission factor of the coal type used for heat generation in the absence the project activity (tCO2/GJ)

0.0961 IPCC Default Value, Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National Greenhouse Gas Inventories

εboiler Energy efficiency of the boiler that would be used in the absence of the project activity (%)

84% Manufacturer Specifications

Baseline emissions due to natural decay or uncontrolled burning of anthropogenic sources of biomass residues As per the methodology ACM 0006 Version 09, the baseline emissions due to natural decay of anthropogenic sources of biomass residues are calculated as below for Scenario 2:


ACM 0006 Version 09

BEbiomass,y Baseline emissions due to natural decay or burning of anthropogenic sources of biomass residues during the year y (tCO2e/yr)

Calculated

GWPCH4 =Global Warming Potential of methane valid for the commitment period (tCO2e/tCH4)

21 Climate Change 1995: The Science of Climate Change, Table 4, p. 22, 1996

BFPJ,k,y Incremental quantity of biomass residue type k used as a result of the project activity in the project plant during the year y (tons of dry matter or litre). For Scenario 2, which is applicable to the project activity, the total quantity of biomass residues used in the project plant (Σ BFk,y) is attributable to the project activity and hence BFPJ,k,y = BFk,y.

92160 Plant Data

NCVk Net calorific value of the biomass residue


type k (GJ/Ton) EFburning,CH4,k,y CH4 emission factor for uncontrolled

burning of the biomass residue type k during the year y (tCH4/GJ)

As it is not possible for the PP to estimate the CH4 Emission factor and also as there is no local country data available for the same, Hence the default value for the NCVk and EFburning,CH4,k,y has been used as per the methodology ACM 0006 Version 09

As per the methodology ACM 0006, Version 09, it is recommended to use 0.0027 t CH4 per ton of biomass as default value for the product of NCVslops and EFburning,CH4,slops,y.

• In order to reflect the high uncertainty of the CH4 emission factor and for the purpose of providing conservative estimates of emission reductions, a conservativeness factor is be applied to the CH4 emission factor. • As the default CH4 emission factor of 0.0027 tCH4/t biomass is used, the uncertainty can be deemed to be greater than 100%, resulting in a conservativeness factor of 0.73. Thus, in this case an emission factor of 0.001971 t CH/t biomass is used.

Leakage Where the most likely baseline scenario is that the biomass residues are dumped or left to decay or burnt in an uncontrolled manner without utilizing it for energy purposes (scenarios 2, 3, 5, 7, 10, 15, 16, 17 and 20), project participants shall demonstrate that the use of the biomass residues does not result in increased fossil fuel consumption elsewhere. For this purpose, project participants shall assess as part of the monitoring the supply situation for the types of biomass residues used in the project plant. The following options may be used to demonstrate that the biomass residues used in the plant did not increase fossil fuel consumption elsewhere: L1 Demonstrate that at the sites where the project activity is supplied from with biomass residues, the biomass residues have not been collected or utilized (e.g. as fuel, fertilizer or feedstock) but have been dumped and left to decay, land-filled or burnt without energy generation (e.g. field burning) prior to the implementation of the project activity. Demonstrate that this practice would continue in the absence of the CDM project activity, e.g. by showing that in the monitored period no market has emerged for the biomass residues considered or by showing that it would still not be feasible to utilize the biomass residues for any purposes (e.g. due to the remote location where the biomass residue is generated). This approach is applicable to situations where project participants use only biomass residues from specific sites and do not purchase biomass residues from or sell biomass residues to a market. The project activity which is the utilization of Slops in the boiler for steam generation is being implemented for the first time in India. Hence in the absence of the project activity the Slops would have

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 67 been left to decay on fields in mainly aerobic conditions. In addition to this, no market has been developed for the Slops. L2 Demonstrate that there is an abundant surplus of the biomass residue in the region of the project activity which is not utilized. For this purpose, demonstrate that the quantity of available biomass residue of type k in the region is at least 25% larger than the quantity of biomass residues of type k that are utilized (e.g. for energy generation or as feedstock), including the project plant. Slops is mainly used in the slop fired boiler. In addition to the slop, rice husk is being used as a supporting fuel to slop for the combustion in the slop fired boiler. Biomass assessment survey, May 2009 has been conducted by Mantras Resources and it has been assessed that there is an abundant supply of rice husk in the region of the project activity which is not utilized and the quantity of the available rice husk is more than 25% larger than the quantity of rice husk available in the region. The geographical boundary of the biomass assessment study is a radius of 100 Kms from the project activity site. The geographical boundary of the biomass assessment study of radius 100 Kms is fixed ex-ante for the entire crediting. The total surplus biomass available in the region for the year 2007 – 2008 is 35% Hence, Leakage (Ly = 0)

B.6.2. Data and parameters that are available at validation: (Copy this table for each data and parameter)

Data / Parameter: EFOM , y

Data unit: tCO2/MWh Description: The Operating Margin emission factor of Northern grid Source of data used: Central Electricity Authority CO2 Baseline Database version 3.0 dated 15th

December 2007. Value applied: 0.9925 Justification of the choice of data or description of measurement methods and procedures actually applied :

The value is calculated as average of the last three years of the Operating margin provided by CEA

Any comment:

Data / Parameter: EFBM , y

Data unit: tCO2/MWh Description: The Build Margin emission factor of Northern grid Source of data used: Central Electricity Authority CO2 Baseline Database version 3.0 dated 15th

December 2007 Value applied: 0.6283 Justification of the The data has been provided by Central Electricity Authority


choice of data or description of measurement methods and procedures actually applied : Any comment:

Data / Parameter: EF,grid,CM,y =EFelectricity.,y Data unit: tCO2e/MWh Description: The Northern grid CO2 emission factor in year y Source of data used: Calculated Value applied: 0.8105 Justification of the choice of data or description of measurement methods and procedures actually applied :

This has been calculated by using OM and BM.

Any comment: Used for emission reduction calculation

Data / Parameter: EFCoal= EFCO2,coal,y=EFCO2,BL,heat Data unit: Kg CO2e/TJ or tCO2e/TJ

Description: Emission Factor of Coal Source of data used: IPCC Default Value, Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines

for National Greenhouse Gas Inventories Value applied: 96100 or 96.1 Justification of the choice of data or description of measurement methods and procedures actually applied :

Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National Greenhouse Gas Inventories

Any comment: IPCC Default Value and the same will be updated as per the latest IPCC default value

Data / Parameter: EFHSD=EFCO2,HSD,y Data unit: Kg CO2e/TJ or tCO2e/TJ

Description: Emission Factor of HSD Source of data used: IPCC Default Value, Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines

for National Greenhouse Gas Inventories Value applied: 74100 or 74.1 Justification of the choice of data or description of measurement methods and procedures

Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National Greenhouse Gas Inventories

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 69 actually applied : Any comment: IPCC Default Value and the same will be updated as per the latest IPCC default

value Data / Parameter: EFCH4,BF

Data unit: tCH4/GJ Description: CH4 emission factor for the combustion of biomass residues in the project plant

(tCH4/GJ) Source of data used: ACM0006 Version09, Table 4 and Table 5. Value applied: 0.0000411 Justification of the choice of data or description of measurement methods and procedures actually applied :

CH4 emission factor for the combustion of biomass residues in the project plant (tCH4/GJ) As per ACM 0006 Version 09 Table 4 with conservativeness factor as per table 5 of the methodology ACM 0006 Version 09. Default value from the methodology is chosen as there are no local reliable values and there are no measurement procedures that the PP can adopt for calculation of CH4 emission factor.

Any comment: Default Value Data / Parameter: η

Data unit: Percentage points Description: The energy efficiency of boiler in the most likely baseline scenario.

Source of data used: Highest Efficiency figure of boilers with similar specifications as provided by

the Manufacturers Value applied: 84% Justification of the choice of data or description of measurement methods and procedures actually applied :

Any comment: Data / Parameter: Mileage

Data unit: Km/lit Description: Mileage of the trucks used for the transportation of biomass Source of data used: Supplier Information

Value applied: 3.5 Justification of the choice of data or

The data is estimated on the basis of the supplier information. This value is fixed ex-ante for the entire 10 years crediting period.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 70 description of measurement methods and procedures actually applied : Any comment:

Data / Parameter: Truck Load Data unit: Tons/vehicle Description: Truck Load for the biomass transportation Source of data used: Supplier Information

Value applied: 10 Justification of the choice of data or description of measurement methods and procedures actually applied :

The data is estimated on the basis of the supplier information. This value is used for ex-ante determination of the number of trucks used for the transportation of the biomass to estimate the ex-ante emission reductions. However for the ex-post Emission reduction calculation the actual number of trucks used will be monitored and the same will be used for the calculation of emission reductions.

Any comment: Data / Parameter: NCVHSD

Data unit: Kcal/Kg Description: Net calorific value of HSD Source of data used: Central Electricity Authority: CO2 Baseline Database, Version 03, 15th

December 2008 Value applied: 10000 Justification of the choice of data or description of measurement methods and procedures actually applied :

The calorific value as mentioned in the CEA CO2 Baseline Data base Version 4 is 10,500 Kcal/lit and considering the Delta GCV NCV as 5% as mentioned in CEA CO2 Baseline Data base Version 4 the NCV comes out to be 10000 Kcal/Kg. The data is considered from the available authentic national data source due to absence of the authentic measurement procedures by PP. This is fixed ex-ante for the entire crediting period.

Any comment:

Data / Parameter: DHSD

Data unit: Kg/lt Description: Density of HSD Source of data used: Central Electricity Authority: CO2 Baseline Database, Version 03, 15th

December 2008

Value applied: 0.83 Justification of the choice of data or description of measurement methods and procedures actually

The data is considered from the available authentic national data source due to absence of the authentic measurement procedures by PP. This is fixed ex-ante for the entire crediting period.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 71 applied : Any comment: Data / Parameter: TDL j,y Data unit: % Description: Average technical transmission and distribution losses for providing electricity

to source j Source of data used: Tariff Order for FY 2007-2008 & FY 2008-2009 for Discom and Transco has

been considered by Uttar Pradesh Electricity Regulatory Commission Value applied: 29.1 Justification of the choice of data or description of measurement methods and procedures actually applied :

The T&D losses for Lucknow Discom as reported by Uttar Pradesh Electricity Regulatory Commission for the FY year 2007-2008 & 2008-2009 in the Tariff Order for FY 2007-2008 & FY 2008-2009 for Discom and Transco has been considered

Any comment:

B.6.3. Ex-ante calculation of emission reductions: >>

The project activity mainly reduces CO2 emissions through substitution of power and heat generation with fossil fuels by energy generation with biomass residues. The emission reduction ERy by the project activity during a given year y is the difference between the emission reductions through substitution of electricity generation with fossil fuels (ERelectricity,y), the emission reductions through substitution of heat generation with fossil fuels (ERheat,y), project emissions (PEy), emissions due to leakage (Ly) and baseline emissions due to the natural decay of biomass residues (BEbiomass,y), as follows:

Project emissions Project emissions include

• CO2 emissions from transportation of biomass residues to the project site (PETy), • CO2 emissions from on-site consumption of fossil fuels due to the project activity (PEFFy), • CO2 emissions from consumption of electricity (PEEC,y), • CH4 emissions from the combustion of biomass residues (PEBiomass,CH4,y)

Project Emissions are calculated as follows:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 72 Carbon dioxide emissions from combustion of fossil fuels for transportation of biomass residues to the project plant (PETy) In cases where the biomass residues are not generated directly at the project site, project participants shall determine CO2 emissions resulting from transportation of the biomass residues to the project plant.

PETy = 6150*100*0.000768 = 472 tCO2e Carbon dioxide emissions from on-site consumption of fossil fuels (PEFFy) PEFFy = (FFproject plant,i,y × COEFFFproject plant,y + FFproject site,i,y × COEFFFproject site,y ) COEFFFproject plant,y = NCVFFproject plant,y × (4.186/10^9 )× EFCO2,FFProject plant,y/1000 COEFFFproject site,y = NCVFFproject site,y × (4.186/10^9 )× EFCO2,FFProject site,y/1000 PEFC,y = 27284 * 1000 * 3500 * (4.186 /10^9) * 96100/1000 + 1000 * 0.83 * 10000 * (4.186 /10^9) * 74100/1000= 40989tCO2e. Carbon dioxide emissions from consumption of electricity (PEEC,y),

PEEC,y = 1000 * 0.8105 * (1+29.1%) PEEC,y = 1046 tCO2e. Methane emissions from combustion of biomass residues (PEBiomass,CH4,y) If this source has been included in the project boundary, emissions are calculated as follows:

PEBiomass,CH4,y = 92160 * 3564* 4.186*10^(-9)* 1000* 0.04 = 57 tCH4,y. PEy = 472 + 40989 + 1046 + 21*57 = 43694 tCO2e. Emission Reductions Emission reductions due to the displacement of electricity Emission reductions due to the displacement of electricity are calculated by multiplying the net quantity of increased electricity generated with biomass residues as a result of the project activity (EGy) with the CO2 baseline emission factor for the electricity displaced due to the project (EFelectricity,y), as follows:


ERElectricity, y = 78629 * 0.8105 = 63726 tCO2e. Emission reductions or increases due to displacement of heat For Scenario 2 which is applicable to the project activity the Emission Reductions due to the displacement of heat is as follows:

ERheat,y = 754433 * 0.0961/0.84 = 86310 tCO2e Baseline emissions due to natural decay or uncontrolled burning of anthropogenic sources of biomass residues As per the methodology ACM 0006 Version 09, the baseline emissions due to natural decay of anthropogenic sources of biomass residues are calculated as below for Scenario 2: BEy,biomass = 21 * 92160 * 0.001971 = 3815tCO2e. ERy =86310+63726+3815−43694 = 110157 tCO2e Leakage Ly = 0

B.6.4 Summary of the ex-ante estimation of emission reductions: >>

Year Estimation of Project activity emissions (tCO2e)

Estimation of baseline emissions (tCO2e)

Estimation of leakage (tCO2e)

Estimation of overall emission reductions (tCO2e)

t CO2 t CO2 t CO2

Year A 43694 153851 0 110157

Year B 43694 153851 0 110157

Year C 43694 153851 0 110157

Year D 43694 153851 0 110157

Year E 43694 153851 0 110157

Year F 43694 153851 0 110157

Year G 43694 153851 0 110157

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 74 Year H 43694 153851 0 110157

Year I 43694 153851 0 110157

Year J 43694 153851 0 110157

Total (tonnes of CO2e)

436940 1538510 0 1101570

B.7. Application of the monitoring methodology and description of the monitoring plan:

B.7.1 Data and parameters monitored: (Copy this table for each data and parameter) Data / Parameter: EGy,4.0 Data unit: kWh Description: Gross Electricity generation from 4.0 MW turbine Source of data to be used:

HT & LT equipments parameter log book

Value of data applied for the purpose of calculating expected emission reductions in section B.5

11345000

Description of measurement methods and procedures to be applied:

The gross electricity generation is measured from the gross electricity meter installed in the Generation Control Panel. The meter is a 3 phase 3 wire energy meter with accuracy class 0.5. The readings are taken every 2 hrs by the Shift In-Charge and are recorded in the HT & LT Equipments Log Book. At 6:00 A.M every day the Shift In charge “A” calculates the gross energy generation for the previous day and records in the HT & LT Log Book. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total electricity generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The electricity generated during the operation of the 35 TPH LIPI boiler will be calculated by considering the initial reading and final reading of the meter during the operation. This will be calculated by the Shift In charge and communicated to the Manager Utility. This electricity will be deducted from the total electricity generation. kWh readings will be converted to MWh.

QA/QC procedures to be applied:

The readings taken by Shift In-charge are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total electricity generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The PP will be going for ISO Quality Management System and all the


QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment:

Data / Parameter: EGy,AUX,B1. Data unit: kWh Description: Auxiliary Electricity Consumption of 1st Slop Fired Boiler and 4 MW turbine Source of data to be used:

HT & LT Equipments Log Book.

Value of data 6048000 Description of measurement methods and procedures to be applied:

The Auxiliary consumption of the 1st Slop fired boiler and 4 MW turbine is calculated as the summation of the readings taken from kWh totalizer meter installed in the PCC-1 (Main Panel) and Cheema Boiler 10B sub panel and the readings taken from the kWh totalizer meter installed in PCC-2 (Main Panel) and Cheema Boiler 10 A Sub panel. The accuracy class of both the meters will be 0.5 class. The readings are taken every 2 hrs by the Shift In-Charge and are recorded in the HT & LT Equipments Log Book. At 6:00 A.M every day the Shift In charge “A” calculates the Auxiliary Electricity Consumption for the previous day and records in the HT & LT Log Book. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total auxiliary electricity consumption in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). kWh readings will be converted to MWh.


The readings taken by Shift In-charge are checked by the Manager Utility every day at 10:00 A.M. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment:

Data / Parameter: EGy,12 Data unit: kWh Description: Gross Electricity generation from 12.0 MW turbine Source of data to be used:

HT & LT equipments parameter log book

Value of data 84758000 Description of measurement methods

The gross electricity generation will be measured from the gross electricity meter installed in the Generation Control Panel. The accuracy class of the meter will be

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 76 and procedures to be applied:

0.5 class. The readings will be taken every 2 hrs by the Shift In-Charge and will be recorded in the HT & LT Equipments Log Book. At 6:00 A.M every day the Shift In charge “A” will calculate the gross energy generation for the previous day and will record it in the HT & LT Log Book. The readings will be further checked by the Manager Utility every day at 10:00 A.M. The Manager Utility will also calculate the total electricity generation in the month from the daily readings and enters them in the computer. The daily readings will be further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The electricity generated during the operation of the 35 TPH LIPI boiler will be calculated by considering the initial reading and final reading of the meter during the operation. This will be calculated by the Shift In charge and communicated to the Manager Utility. This electricity will be deducted from the total electricity generation. Readings in kWh will be converted to


The readings taken by Shift In-charge are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total electricity generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment: Data / Parameter: EGy,AUX,B2. Data unit: kWh Description: Auxiliary Electricity Consumption of 2nd Slop fired boiler and 12 MW Turbine Source of data to be used:



A meter will be installed to calculate the Auxiliary Consumption of the 2nd Slop Fired boiler and 12 MW turbine. The accuracy class of the meter will be 0.5 class. The readings will be taken every 2 hrs by the Shift In-Charge and will be recorded in the HT & LT Equipments Log Book. At 6:00 A.M every day the Shift In charge “A” calculates the Auxiliary Electricity Consumption for the previous day and records in the HT & LT Log Book. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total auxiliary electricity consumption in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). Readings in kWh will be converted to MWh.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 77 QA/QC procedures to be applied:


Any comment:

Data / Parameter: EGprojectplant,y Data unit: kWh Description: Net Electricity generation from the project plant (4 MW turbine and 12 MW

turbine) Source of data to be used:

Calculated


The Net Electricity Generation of the project plant is calculated as EGprojectplant,y = EGy,4.0 – EGy,AUXB1 + EGy,12 – EGy,AUXB2. kWh will be converted to MWh.


Any comment:

Data / Parameter: STy,4.0 Data unit: Tons Description: Steam to the process from the 4.0 MW Turbine. Source of data to be used:

4.0 MW TG SET Log Sheet


The steam to the process from the exhaust of the 4.0 MW Turbine is measured using the Main Steam Flow (Turbine Exhaust) Meter which is totalizer digital meter installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter is from the Steam Flow Transmitter with the Tag No. FT 20011 this is located in the field. The readings from the totalizer are taken every hour by the Turbine Operator and are entered in the 4.0 MW TG SET Log Sheet. These readings are checked by the Shift In charge at the end of every shift. Every Day Morning at 6:00 A.M. the Shift In charge “A” calculates the steam to the process from the Exhaust of 4.0 MW turbine for the previous day as the difference between the reading at 6:00 A.M. on the current day and 6:00 A.M. of the previous day. This is entered in the TG SET Log sheet. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total steam generation in the month from the daily readings and enters them in the computer. The daily readings are further


cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).



Any comment: Data / Parameter: STy,12 Data unit: Tons Description: Steam to the process from the 12.0 MW Turbine. Source of data to be used:

12 MW TG SET Log Sheet


The steam to the process from the exhaust of the 12 MW Turbine will be measured using the Main Steam Flow (Turbine Exhaust) Meter which is totalizer digital meter that will be installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter will be from the Steam Flow Transmitter that will be located in the field. The readings from the totalizer will be taken every hour by the Turbine Operator and will be entered in the 12 MW TG SET Log Sheet. These readings will be checked by the Shift In charge at the end of every shift. Every Day Morning at 6:00 A.M. the Shift In charge “A” will calculate the steam to the process from the Exhaust of 12.0 MW turbine for the previous day as the difference between the reading at 6:00 A.M. on the current day and 6:00 A.M. of the previous day. This will be entered in the TG SET Log sheet. The readings will be checked by the Manager Utility every day at 10:00 A.M. The Manager Utility will also calculate the total steam generation in the month from the daily readings and enters them in the computer. The daily readings will be further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).


The readings taken by Shift In-charge will be checked by the Manager Utility every day at 10:00 A.M. The daily readings will be further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 79 Data / Parameter: ST,y,LD1 Data unit: Tons Description: Steam to the process from the 1st Let Down Station Source of data to be used:



The steam to the process from the 1st Let Down Station is measured using the By Pass Flow Totalizer – I (LD I) Meter which is totalizer digital meter installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter is from the Steam Flow Transmitter with the Tag No. FT 20000 which is located in the field. The readings from the totalizer are taken every hour by the Turbine Operator and are entered in the 4.0 MW TG SET Log Sheet under the column LD I. These readings are checked by the Shift In charge at the end of every shift. Every Day Morning at 6:00 A.M. the Shift In charge “A” calculates the steam to the process from LDI station for the previous day as the difference between the reading at 6:00 A.M. on the current day and 6:00 A.M. of the previous day. This is entered in the TG SET Log sheet. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total steam generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).



Any comment: Data / Parameter: STy,LD2 Data unit: Tons Description: Steam to the process from the 2nd Let Down Station Source of data to be used:



The steam to the process from the 2nd Let Down Station is measured using the By Pass Flow Totalizer – II (LD II) Meter which is totalizer digital meter installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter is from the Steam Flow Transmitter with the Tag No. FT 20000B which is located in the field. The readings from the totalizer are taken every hour by the Turbine Operator and


are entered in the 4.0 MW TG SET Log Sheet under the column LD II. These readings are checked by the Shift In charge at the end of every shift. Every Day Morning at 6:00 A.M. the Shift In charge “A” calculates the steam to the process from LD II station for the previous day as the difference between the reading at 6:00 A.M. on the current day and 6:00 A.M. of the previous day. This is entered in the TG SET Log sheet. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total steam generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).


The readings taken by Shift In-charge are checked by the Manager Utility every day at 10:00 A.M. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The QA/QC procedures will be as per ISO Quality Management System standard.

Any comment: Data / Parameter: STy,LIPI Data unit: Tons Description: Steam generated by LIPI boiler Source of data to be used:

Boiler Log Book


The steam generated by LIPI boiler is measured by the steam totalizer meter and entered in the log book. These readings are checked by the Shift In charge at the end of every shift. Every Day Morning at 6:00 A.M. the Shift In charge “A” calculates the steam generated by LIPI boiler for the previous day as the difference between the reading at 6:00 A.M. on the current day and 6:00 A.M. of the previous day. This is entered in the TG SET Log sheet. The readings are checked by the Manager Utility every day at 10:00 A.M. The Manager Utility also calculates the total steam generation in the month from the daily readings and enters them in the computer. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).


The readings taken by Shift In-charge are checked by the Manager Utility every day at 10:00 A.M. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities). The QA/QC procedures will be as per ISO Quality Management System standard.

Any comment:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 81 Data / Parameter: ST,y,total Data unit: Tons per annum Description: Total steam to the process by the project activity Source of data to be used:

Plant. It will be calculated.


Calculated as STy,12 + STy,4 + STy,LD1+ STy,LD2 – STy,LIPI


Any comment: Data / Parameter: P,y,process. Data unit: Kg/cm2 Description: Pressure of the Steam to the process Source of data to be used:

Steam Let Down Station Log Book.

Value of data 3.5 Description of measurement methods and procedures to be applied:

The pressure of the steam to the process from the Exhaust of turbine, 1st Let Down Station and 2nd Let Down Station is measured using the totalizer digital meter with Tag No. PIC 21002B installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter is from the Pressure Transmitter with the Tag No. PT 20012 which is located in the field. The readings from the totalizer are taken every hour by the Turbine Operator and are entered in the steam let down station Log Book. These readings are checked by the Shift In charge at the end of every shift. The readings are checked by the Manager Utility every day at 10:00 A.M. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).



Any comment:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 82 Data / Parameter: T,y,process. Data unit: 0C Description: Temperature of the Steam to the process Source of data to be used:

Steam Let Down Station Log Book.


The temperature of the steam to the process from the Exhaust of turbine, 1st Let Down Station and 2nd Let Down Station is measured using the LP Steam Controller totalizer digital meter with Tag No. TIC 30013 installed in the turbine control panel present in the Turbine Control Room. The signal to the digital meter is from the Temperature element which is located in the field. The readings from the totalizer are taken every hour by the Turbine Operator and are entered in the Steam Let Down Station Log Book. These readings are checked by the Shift In charge at the end of every shift. The readings are checked by the Manager Utility every day at 10:00 A.M. The daily readings are further cross checked by the Asst. General Manager (Engineering). In case of any discrepancies the Asst. General Manager (Engineering) will correct the readings in consultation with the Manager (Utilities).



Any comment: Data / Parameter: Qy Data unit: GJ Description: Net quantity of heat generated

Net quantity of heat to the process from the 4.0 MW turbine, 12 MW turbine and from LDI station and LD II station.

Source of data to be used:

On site measurements.


Net heat generation is determined as the enthalpy of the steam to the process from the project activity plants minus the enthalpy of the feed-water and any condensate return. The enthalpies are determined based on the steam to the process by the project activity (STy,total) the temperatures of the steam flow (Ty,process) and Pressure of the steam Flow (Py,process). Steam tables are used to calculate the enthalpy as a function of temperature and pressure.


The consistency of net heat generation is cross-checked with the quantity of biomass fired. The PP will be going for ISO Quality Management System and all


the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment: Data / Parameter: NCVslops,y

Data unit: GJ/ton of Slops Description: Net calorific value of the dry Slops combusted in the project activity during the

year ‘y’ Source of data to be used:

Power Plant Log Book


External Government approved laboratory once every 6 months will be used to monitor the calorific value of Slops.


The consistency of the measurements shall be carried out by comparing the measurement results with measurements from previous years. If the measurement results differ significantly from previous measurements conduct additional measurements.

Any comment:

Data / Parameter: NCVricehusky

Data unit: GJ/ton of rice husk Description: Net calorific value of the rice husk combusted in the project activity during the

year ‘y’ Source of data to be used:



External Government approved laboratory once every 6 months will be used to monitor the calorific value of biosolids.


The consistency of the measurements shall be carried out by comparing the measurement results with measurements from previous years. If the measurement results differ significantly from previous measurements conduct additional measurements.

Any comment:

Data / Parameter: NCVcoaly

Data unit: GJ/ton of Coal Description: Net calorific value of the coal combusted in the project activity during the year

‘y’ Source of data to be used:


PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 84 Value of data 14.651 Description of measurement methods and procedures to be applied:

Gross Calorific Values (GCV) are taken from Coal test reports conducted at the internal laboratory as and when the coal is purchased taking at least 3 samples for each measurement. NCV is calculated from GCV according to American Society for Testing and Materials standard ASTM-D 5865. As per the standard the NCV is calculated as: Q

P (net) = Q

var (gross) – 215.5 j/g x H

ar …………………(1)

where

QP (net) = Net calorific value

Qvar

(gross) = Gross calorific value

Har

= Total Hydrogen, %, as received basis (where hydrogen includes

hydrogen in the sample moisture) The GCV will also be measured at an external approved laboratory once in every 6 months taking at least 3 samples for each measurement


As per the standard ASTM-D 5865

Any comment:

Data / Parameter: QHSD1

Data unit: KL Description: Quantity of HSD consumed in 1250 KVA DG Set No.1 in the project activity Source of data to be used:



The measurement is done by dip stick. The 1250 KVA DG set will have a separate fuel tank. The level indicators give the consumption of HSD in lts. After each usage the tank is again filled to maximum level.


Any comment:

Data / Parameter: QHSD2

Data unit: KL Description: Quantity of HSD consumed in 1250 KVA DG Set No.2 in the project activity Source of data to be used:



The measurement is done by dip stick. The 1250 KVA DG set has a separate fuel tank. The level indicators give the consumption of HSD in lts. After each usage the tank is again filled to maximum level.

QA/QC procedures to

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 85 be applied: Any comment:

Data / Parameter: NCVHSD

Data unit: kcal/kg Description: Net Calorific Value of HSD Source of data to be used:

CENTRAL ELECTRICITY AUTHORITY: CO2 BASELINE DATABASE, Version 3,Date 15/12/2007


The CEA in its report gives the national level average of the Gross Calorific Value (GCV) and also the delta (GCV/NCV). The net calorific value is calculated by dividing the GCV with (1+ (delta (GCV/NCV)))


Any comment: Data / Parameter: BFSlop,y

Data unit: Tons per annum of dry Slop Description: Quantity of Slops combusted in the Slop fired boiler per annum Source of data to be used:

Plant Data


The Quantity of Slops combusted in the boiler is calculated as the bunker volume × Number of Bunkers × Density of Slops × (1-Moisture content of Slop). Density of the Slops will be measured once in a day in the internal plant laboratory. The density of the slops will also be measured once in 6 months by a third party laboratory. The volume of the bunker used will be calculated once every year during the month of January and will be the same for the entire year. The number of bunkers used will be recorded in the log book at the plant site on daily basis.


Cross-check the measurements with an annual energy balance is done to verify the annual quantity of Slops used. The cross check of the energy balance will be based on the heat output from the boiler, the efficiency of the boiler and the heat input into the boiler from slops and rice husk. The heat output from the boiler will be calculated based on the quantity of slops and the enthalpy of steam from the steam table using the temperature and pressure parameters. The quantity of heat input is calculated based on the quantity of slop, the calorific value of slop, the quantity of rice husk, the calorific value of rice husk, the quantity of coal and the calorific value of coal. The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment: Data / Parameter: Moisture Content of Slop

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 86 Data unit: % Water Content Description: Moisture Content of Slop combusted in the project activity Source of data to be used:

Plant Data

Value of data 50% Description of measurement methods and procedures to be applied:

Measurement of moisture content in Slop: 1 time in every day Sampling: Slop is randomly sampled from the entire breadth and depth of the Slop carrier once every day. About 10 kg thus sampled is subsampled immediately to 2 kg and sent to plant laboratory in a covered sample can for analysis. Analysis: 100 gm sample of Slop is taken in a weighed tray perforated on sides and dried in an oven maintained at 110 deg C for one hour. The loss in weight of the sample in gm gives moisture content in Slop


The value can be checked for consistency by getting one sample analysed at an authorised laboratory (at Indian Institute of Technology (IIT) Roorkee) once in six months.

Any comment: Data / Parameter: FFprojectplant,coal,y

Data unit: Tons Description: Quantity of coal combusted in the project plant year y Source of data to be used:

Plant Data


Electronic belt weigher no. 1 shall be installed on the coal carrier carrying coal to the boiler. Coal required for steam generation is fed into the boiler and surplus coal is returned to the coal stock yard by another coal carrier. Electronic belt weigher no.2 shall be installed on this coal carrier carrying surplus coal to the coal stock yard. Both these electronic belt weighers have load cells in which weight is measured with strain gauge type precision load sensors with LED display for both the actual time flow also called local flow as well as totalized flow. The difference in flow reading of weigher no.1 and weigher no.2 will give the quantity of coal fed to the boiler. Both the readings will be recorded in the log book at the end of every day. The meters will be calibrated at the time of installation and will be recalibrated annually.


Cross-check the measurements with an annual energy balance that is based on purchased quantities and stock changes. The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment:

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 87 Data / Parameter: FFprojectsite,HSD,y

Data unit: KL Description: Quantity of HSD combusted in the project site purposes that are attributable to the

project activity during the year y Source of data to be used:

Calculated


Calculated as summation of QHSD1 and QHSD2 (FFprojectsite,HSD,y = QHSD1 + QHSD2)


Any comment: Data / Parameter: BFricehusk,y

Data unit: Tons per annum of dry rice husk Description: Quantity of dry rice husk combusted in the Slop fired boiler per annum Source of data to be used:

Plant Data


The Quantity of Rice Husk combusted in the boiler is calculated as the bunker volume × Number of Bunkers × Density of rice Husk× (1-Moisture content of Rice Husk). Density of the Rice Husk will be measured once in a day in the internal plant laboratory.


Cross-check the measurements with an annual energy balance is done to verify the annual quantity of rice husk used. The cross check for the amount of rice husk used in the project activity is done on the basis of the receipts of the purchased quantity and the changes in the stock of the rice husk at the end of every year. The difference between the purchase receipts and the quantity of stock in the yard at the end of the year will give the amount of rice husk consumed in the project activity. The PP will be going for ISO Quality Management System and all the QA/QC will be as per the procedures defined in the ISO Quality Management System.

Any comment: Data / Parameter: EGy,import . Data unit: kWh Description: Electricity imported from the grid Source of data to be used:


Value of data 1000000 Description of measurement methods

A meter will be installed to calculate the electricity imported from the grid for the project activity. The accuracy class of the meter will be 0.5 class.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 88 and procedures to be applied:

The readings will be taken once every day by the Shift In-Charge and will be recorded in the HT & LT Equipments Log Book. At 6:00 A.M every day the Shift In charge “A” calculates the electricity imported from the grid for the previous day and records in the HT & LT Log Book. The readings are checked by the Manager Utility every day at 10:00 A.M.



Any comment: Data / Parameter: TDL j,y

Data unit: % Description: Average technical transmission and distribution losses for providing electricity to

source j in year y Source of data to be used:

Accurate and reliable data available within the host country for Lucknow Discom as reported by Uttar Pradesh Electricity Regulatory Commission for the FY year 2007-2008 & 2008-2009 in the Tariff Order for FY 2007-2008 & FY 2008-2009 for Discom and Transco


The value of the parameter is based on references from official documentation available within the host country during the verification period. The most recent figures will be used which will not be older than 5 years.


Any comment: Data / Parameter: Moisture Content of Rice Husk

Data unit: % Water Content Description: Moisture Content of Rice Husk combusted in the project activity Source of data to be used:

Plant Data


Measurement of moisture content in Slop: 1 time in every day Sampling: Rice Husk is randomly sampled from the entire breadth and depth of the Rice Husk carrier once every day. About 10 kg thus sampled is subsampled immediately to 2 kg and sent to plant laboratory in a covered sample can for analysis.


Analysis: 100 gm sample of Rice Husk is taken in a weighed tray perforated on sides and dried in an oven maintained at 110 deg C for one hour. The loss in weight of the sample in gm gives moisture content in Slop. For exante calculation a value of 10% is used. (Source: http://www.scribd.com/doc/3085035/Chemical-Analysis-of-Rice-Husk-Ash, which states that the moisture is usually in the range of 8 – 10%)


The value can be checked for consistency by getting one sample analysed at an authorised laboratory (at Indian Institute of Technology (IIT) Roorkee) once in six months.

Any comment: Data / Parameter: AVDy Data unit: Km Description: Average round trip distance (from and to) between biomass fuel supply sites and

the project site Source of data to be used:

Records by project participants on the origin of the biomass


Each time a truck comes with a load of biomass to the factory, the distance from the origin of the biomass is provided by the truckers and the distance is recorded in the log book.


Consistency of distance records provided by the truckers is checked by comparing recorded distances with other information from other sources (e.g. maps).

Any comment: Data / Parameter: Ny Data unit: - Description: Number of truck trips for the transportation of biomass. Source of data to be used:

Records by project participants on the origin of the biomass


Each time a truck comes with a load of biomass to the factory, the vehicle number of the truck and the Serial Number is noted in the log book. The total number of trucks entered in the log book determines the total number of truck trips


Consistency of the number of truck trips is checked with the quantity of biomass transported.

Any comment:

Data / Parameter: Quantity ricehusk,y Data unit: Kgs Description: Quantity of rice husk transported

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 90 Source of data to be used:

Records by PP.


Biomass used for power generation in the project activity is weighed by weighing bridge. When the truck comes with the load of biomass the truck is stationed on the weigh bridge and the weight is recorded as the gross weight in the computer by pressing 1 in the Main Menu and also entering the vehicle number, Material Code and the Supply code. This generates a key number. After the truck unloads the biomass the same truck is again stationed on the weigh bridge and the tier weight is recorded in the computer by pressing 2 and the key number generated previously. The difference in the Gross Weight and the Net Weight gives the quantity of Biomass Procured. The readings are recorded in the log book and stored in the weighing room located at the entrance of the power plant.


Cross-check the measurements with an annual energy balance that is based on purchased quantities and stock changes.

Any comment:

Data / Parameter: Emission Factor for truck

Data unit: tCO2e/KL Description: Emission factor for the truck used for the transportation of the rice husk to the

plant site Source of data to be used:

Calculated


Calculated as MileageHSD* NCVHSD * DHSD * 4.186 * 10^(-9) * EFHSD / MileageHSD


Any comment:

Data / Parameter: - Data unit: - Description: Demonstration that the biomass residue slop from the plant would continue not to

be collected or utilized, e.g. by an assessment whether a market has emerged for the slop or by showing that it would still not be feasible to utilize the biomass residues for any purposes.

Source of data to be used:

Plant

Value of data Description of measurement methods and procedures to be

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 91 applied: QA/QC procedures to be applied:

Every year this will be analysed.

Any comment:

Data / Parameter: - Data unit: - Description: Quantity of available biomass residues of type k in the region Source of data to be used:

Plant

Value of data Description of measurement methods and procedures to be applied:


Every this will be analysed.

Any comment:

It will be demonstrated every year through biomass assessment studies that the quantity of available rice husk in the region with in a radius of 100 kms is 25% larger than the quantity of rice husk that is utilised including the project activity. It will be demonstrated that the Slops would still not be feasible to utilize the biomass residue (slop)for any purposes during the monitoring period.

B.7.2. Description of the monitoring plan:

>> The PP will be going for ISO Quality Management System (ISO 9001) and all the QA/QC for the project will be as per the procedures defined in the ISO Quality Management System after certification. The Project activity will follow internal QA/QC procedures before to the certification under ISO. Accordingly, the monitoring plan proposed herein, the emergency preparedness plan will become an integral part of the project Management Programmes and would be constituent of operational and management structure of this Quality Management System (QMS). The project activity is operated and managed by the project proponent. The individual plant department record data related to their respective parameters. In order to monitor and control the project performance, IGL has placed a project management team. They are coordinated by Project Executor and Head (Asst. General Manger - Utilities) who is responsible for checking the information consistency. IGL has well diversified procedure for collection of data and analysis of data at different levels and for subsequent corrective actions as when required in line with these policies.

• The project team has been entrusted with the responsibility of storing, recording the data related to the project activity. The project team is also responsible for calculation of actual emission reduction in the most transparent and relevant manner.


• Inspection and record of daily checklist of critical parameters of project activity is maintained. The maintenance staff’s accesses the condition of all the power plant equipment and measuring equipment and any action required is taken.

• Installed meters are calibrated according to the calibration schedule programmed at the start of

the operation and recalibrated annually before the due date.

• All the monitoring data is stored /will be recorded and kept under safe custody of the Project Executor and Head (Asst. General Manager, Utilities) for a period of crediting period (10 years fixed crediting period) + 2 years.

• The Instrumentation and the control system for the project activity are designed with adequate

instruments to control and monitoring the various operating parameters for safe and efficient operations. All the instruments are of reputed make and are calibrated at regular intervals.

Training Protocol: Training will be imparted by the manufacturer at the time of the commissioning of the 12 MW cogeneration power plant for the Shift In charge, Turbine Operator, Manager (Utilities) and the Asst. General Manager (Engineering). Internal audits will be performed every 6 months by the audit team comprising of the Manager (Utilities) and the Shift In-charge. The audit will be performed with respect to the following points:

• Are the monitoring of the parameters done in line with the CDM PDD. • Is the recording done properly? • Are the equipments calibrated and maintained as per the schedule. • Are any corrective actions to be taken?

The audit team will submit the audit report to the Assistant General Manager (Engineering) every 6 months. The findings of the audit report will be discussed by the Assistant General Manager (Engineering) at the CDM review meeting which will be conducted every month. Whenever a new employee is inducted in the CDM team the Manager (Utilities) will provide the training in regard to the CDM procedures. The Slop fired Cogeneration project abides and will abide by all regulatory and statutory requirements as prescribed under the state and central laws and regulations. Also any change within the project boundary, such as change in equipments will be recorded and any change in the emission reduction due to such alteration will also be studied and recorded. Operational and Management Structure All relevant functions and tasks are sufficiently described in the manual and the standard operating procedures of the quality management system.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 93 PROJECT TEAM

Designation Responsibilities Project Head

Registration Project Execution

Asst.G. M. – Engineering

Operation Verification of data Inspection of data whenever necessary to independently check the authenticity of data and take corrective actions wherever required. Storage of data

Utility Manager

Operation, Monitoring and Verification of Data Storage of data in MIS

Shift In charge

Operation and Maintenance Storage of data in Log Book Data Recording

Turbine and Boiler Operators Operation and Maintenance Data Recording Data Collection Archiving of data

Asst. General Manager (Engineering)

Manager Utilities

Shift In charge

Turbine Operators Boiler Operators

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 94 B.8. Date of completion of the application of the baseline study and monitoring methodology and the name of the responsible person(s)/entity(ies): >> Date of completing the final draft of this baseline section (DD/MM/YYYY): 16/03/2010 The name of the responsible person(s)/entity(ies): Core CarbonX Solutions Pvt Ltd. 6-3-903/A/4/1,Vani Nilayam Surya Nagar Colony Somajiguda, Rajbhavan Road, Hyderabad –500082, Andhra Pradesh, India, Phone: +91-40-23410367 Mobile-+91-9963047666, +91-9908387772 Email:[email protected] www.corecarbonx.com

Quality Growth Services Private Limited H-13, IInd Floor, Kirti Nagar, New Delhi – 110 015, India Telefax: +91-11-25438598 / 25431737 / 25918332

Core CarbonX Solutions Private Limited is not a project participant.

Quality Growth Services Private Limited is not a project participant.

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: >> 03/05/2005. (PO date of first boiler)

C.1.2. Expected operational lifetime of the project activity: >> 20 years 0 months C.2. Choice of the crediting period and related information: Fixed Crediting Period C.2.1. Renewable crediting period: C.2.1.1. Starting date of the first crediting period: >> N.A C.2.1.2. Length of the first crediting period: >> N.A. C.2.2. Fixed crediting period: C.2.2.1. Starting date: >>

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 95 01/09/2010 or a date not earlier than the date of registration C.2.2.2. Length: >> 10 years 0 Months SECTION D. Environmental impacts >> D.1. Documentation on the analysis of the environmental impacts, including transboundary impacts: >> The PP engaged the services of M/s EST Consultants (P) Ltd, New Delhi to carry out a Rapid Environmental Impact Assessment for the project activity to understand impacts and mitigate any additional impacts that may arise due to the proposed project activity. The environmental Impact Assessment study showed that overall environmental impacts are not significant. A summary of impacts is presented below:

• Impact on Meteorology: No such emissions are likely, which are known to alter the meteorology of the local or regional area.

• Impact on Air environment The SO2 emissions from the boilers are negligible. The Suspended Particulate Matter (SPM) emissions shall be less than 150 mg/Nm3 as stipulated by the Pollution Control Board (PCB). The stack heights are provided as per the formula for Adequate Stack heights of CPCB or more i.e. 45 m. sufficient green belt will be developed inside the IGL plant complex to abate air emissions from the plant, mitigate stack emissions & to attenuate the noise generated from the plant machinery.

• Impact on Land use and quality The project activity is located in industrial area. Some cut and fill operations might disturb the soil but the effect will be insignificant and temporary. There will not be any adverse impact on the soil quality.

• Impact on fresh water ecology and wild life As the project activity is not implemented in an ecologically sensitive area, there will be no impacts on the wild life. There will be no effluent discharge from the project activity; hence there will also be no major impacts on the fresh water ecology.

• Impacts on Noise: The project activity will have no major noise producing sources hence noise pollution is not seen as a problem for the project activity. The major noise generating sources will be the DG sets. Proper arrangements will be made for the protection of workers.

• Impact on terrestrial Flora and Fauna. The existing ambient air quality of the study area is well within the National Ambient Air quality standards for the primary pollutants. Even the Noise measurements show that the standards are adequately met. Hence there is no observed impact on the terrestrial flora and fauna in the surrounding area of the plant. Environmental Management Plan: In order to further minimize the impacts of the project activity on the environment and to keep the air quality and water quality within the prescribed limits a comprehensive environmental management plant is in vogue at IGL.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 96 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: >> The Environmental Impact Assessment study showed that overall environmental impacts are not significant SECTION E. Stakeholders’ comments >> E.1. Brief description how comments by local stakeholders have been invited and compiled: >> The PP organized the Local Stakeholder Consultation meeting on 30th January 2006 at the IGL Plant site, GIDA, Gorakhpur for the project activity. IGL identified Pradhan of the local village, local villagers, local NGO, employees of IGL Gorakhpur plant, contract labor and various government officials as the most important stakeholders, with an interest in the CDM activities. All the stakeholders were communicated regarding the meeting at least 15 days prior to the start of the meeting Comments of stakeholders were recorded during the stakeholder meeting. The stake holder meeting process was conducted in the following sequence.

• Welcome Address • Election of the Chair of the meeting and approval of the proposed Agenda • Presentation of the CDM-Kyoto Protocol and role of local stake holder • Presentation of the Projects undertaken by PP. • Discussion and Articulation of concerns • Chair summarizing the local stake holder concerns • Vote of Thanks followed by Tea

At the start of the meeting Mr. D.S. Srivastava (plant head, IGL Gorakhpur) welcomed all the guests for the meeting. He then asked the audience to elect the chairman of the meeting. Mr. Sanjay Kumar (Senior Manager, Engineering) proposed the name of Mr. Ajay Yadav (Pradhan, Bhabsa Village) as the chairman of the meeting. The audience was unanimous in electing Mr. Ajay Yadav as the chairman of the meeting. Mr. Srivastava then explained about the proposed project activity of installing Slop fired boilers and turbine for the generation of steam and electricity in Hindi. He told the stakeholders that the installation of the Slop fired boilers is the first time in India. He further explained that IGL project & technical team is taking extra efforts for the designing and installation of the Slop Fired Boiler. Mr. Srivastava explained that the boiler is ordered with specifications of capacity of 47 TPH. He said that the final output and the operating parameters will be determined only after the operation starts as no one has an experience in operating the same. Mr. Srivastava then requested Mr. R.K. Sharma to aware the stakeholders about the purpose of the meeting.

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 97 Mr. R.K. Sharma told the stakeholders about the impacts of global warming, greenhouse gas effect, the Kyoto Protocol and the CDM process. He also briefed about the importance of the Local Stakeholder Consultation meeting and also the contribution towards the sustainable development by the project. After the discussion the chairman opened the session for stakeholders to ask any questions and provide their suggestions. The participants sought clarifications on Kyoto Protocol and Clean Development Mechanisms process and the same was further explained in length. The specific questions raised by the participants are given in section E.2 along with the answers provided. Chairman once again requested the stakeholders to raise any clarifications that they wished to be sought. After ensuring that all the queries of the stakeholders were satisfactory answered and there weren’t any furthers queries by the stakeholders, the chairman closed the Question and Answer session. Chairman said that he is very happy that company is doing such kind of new initiatives having high level of risks for reducing the Green House Gases. Finally, Mr. Srivastava proposed the vote of thanks and the meeting concluded with thanks to the chair. The photographs of the event were taken and the attendance as well as the minutes of the meeting was also recorded. E.2. Summary of the comments received: >> The specific questions raised by the participants are given below along with answers provided

• Question: It has been explained that the project activity is first of its kind in India, is there any country in the world which is operating the same technology? If yes then why didn't IGL import the technology?

Answer: The operation of Slop fired boiler is existing in China but importing the technology is not a viable option due to the barriers. • Question: Are there any dangerous gases that would be emitted from the boiler? Answer: there will not be any dangerous gases from the boiler. The use of Slops in the boiler will reduce the emissions of Greenhouse Gases into the atmosphere. • Question : What is the total investment for the project activity?

Answer : Each Slop fired boiler costs around INR 7 Crores. • Question : Will there be any new employment opportunities?

Answer : there will around 50 direct employment opportunities that will be created due to project activity and around 100 indirect employment opportunities will also be created. • Question : What will be the contribution of IGL towards the society?

Answer : it was performed that IGL will provide free health camps, free of cost hand pumps for drinking water. It was also informed that as Gorakhpur is severely prone to flood IGL will take active steps in providing basic amenities like food, medicines and clothes to the victims affected by flood.

E.3. Report on how due account was taken of any comments received: >>

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 98 The stakeholders were provided clarifications on the issues raised as above to their satisfaction. None of the concerns expressed by the stakeholders required an action to be taken by the Project Proponent during the project operation and at any other stage.


Annex 1

CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY Organization: M/s INDIA GLYCOLS LTD. Street/P.O.Box: GIDA Building: M/s INDIA GLYCOLS LTD. City: Gorakhpur State/Region: Uttar Pradesh Postcode/ZIP: Country: India Telephone: +91-5947-275320 FAX: +91-5947-275315 E-Mail: [email protected] URL: - Represented by: - Title: Joint GM (HSE) Salutation: Mr. Last name: Sharma Middle name: Kumar First name: Rajeev Department: HSE Mobile: +91-9837056451 Direct FAX: +91-5947-275315 Direct tel: +91-5947-275320 (111) Personal e-mail: [email protected]


Annex 2

INFORMATION REGARDING PUBLIC FUNDING Public funding from Annex I and diversion of Official Development Assistance (ODA), is not involved in this project

PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 03 CDM – Executive Board page 101 Annex 3

BASELINE INFORMATION

Variable Data Source EGy,4.0 – Electricity Generated from 4.0 MW Turbine (kWh)


EGy,12 – Electricity generated from 12 MW turbine


STy,4.0 – Steam to the process from the exhaust of 4.0 MW turbine


STy,12 – Steam to the process from the exhaust of 4.0 MW turbine






Py,process – Pressure of the steam to the process, Records maintained by project proponent Ty,process – Temperature of the steam to the process.


EGy,AUX,B1 - Auxiliary Electricity consumption 1.


EGy,AUX,B1 - Auxiliary Electricity consumption -2.


Qy-Quantity of net heat generation in the project plant that displaces heat generation in fossil fuel fired boilers during the year y (GJ/yr). As per the methodology ACM0006, Version 09, Qy = Qproject

plant, y

Calculated

Parameter Data Source EFOM , y - Build Margin Emission Factor (tCO2/MWh)


EFBM , y = Operating Margin Emission Factor (tCO2/MWh)


EFgrid,CM,y – Grid Emission Factor Calculated as the weighted average of the operating margin and build margin

EFCO2,BL,heat -CO2 emission factor of the fossil fuel type used for heat generation in the absence the project activity (tCO2/GJ)

IPCC Default Value, Table 1.4, Chapter 1, Volume 2, 2006 IPCC Guidelines for National Greenhouse Gas Inventories

εboiler- Energy efficiency of the boiler that would be used in the absence of the project activity

Manufacturer Specifications


Annex 4

MONITORING INFORMATION Please refer Section B7.2

- - - - -


Appendix A

Details of measuring equipment associated with steam

TAG NO. SERVICE INSTRUMENT TYPE

AREA UNIT OF RANGE

CAL. FREQ. ACCURACY (+/-) OF SPAN

FT201 H.P ST. FLOW DP TRANSMITTER

CHEEMA BOILER MMWC YEARLY 0.065%

PT201 H.P. ST. PRESS. PRESS. TRANSMITTER

CHEEMA BOILER KG/CM2 YEARLY 0.065%

TT203 H.P. ST. TEMP TEMP TRANSMITTER

CHEEMA BOILER DEG C YEARLY 0.530%

SFT101 H.P. ST. FLOW DP TRANSMITTER LIPI BOILER TON/HR YEARLY 0.075%

PT101 H.P. ST. PRESS. PRESS. TRANSMITTER LIPI BOILER KG/CM2 YEARLY 0.070%

TT101

H.P. ST. TEMP TRANSMITTER

TEMP TRANSMITTER LIPI BOILER DEG C YEARLY 0.100%

FT-20011 H.P. ST. FLOW DP TRANSMITTER TURBINE MMWC YEARLY 0.065%

FIT20000A

LETDOWN (H.P.)-1 ST. FLOW

DP TRANSMITTER TURBINE TON/HR YEARLY 0.065%

FIT20000B LETDOWN-2 (H.P.)ST. FLOW

DP TRANSMITTER TURBINE TON/HR YEARLY 0.065%

PT20012 LP STEAM PRESSURE

PRESS. TRANSMITTER TURBINE KG/CM2 YEARLY 0.065%

TT30013

LP ST. TEMP TRANSMITTER

TEMP TRANSMITTER TURBINE DEG C YEARLY 0.100%

PT20003 H.P. STEAM PRESSURE

PRESS. TRANSMITTER TURBINE KG/CM2 YEARLY 0.065%

TI20017 H.P. STEAM TEMP INDICATOR TURBINE DEG C YEARLY 0.250%

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