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MONITORING REPORT

Grid connected Bagasse based Cogeneration project of

Ugar Sugar Works Ltd (USWL)

for the period

Jan 1, 2006 - January 31, 2007

UNFCCC NO. 0189

Version 02

Date: 15 - 03-2007.

C A R E Sustainability


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March 2007 C A R E Sustainability

2.3 Quality control (QC) and quality assurance (QA)

2.4 procedures that are being undertaken

2.5 for the data monitored 16

2.6 Calibration/Maintenance of Measuring

2.7 and Analytical Instruments 17

2.8 Environmental Impacts due to the project

2.9 activity; present status 17

8.0 GHG Calculations 18

8.1 GHG emission reductions confirming to the

methodology of AM0015

8.1.1 The Operating Margin emission factor 20

8.1.2 Build Margin emission factor 21

8.1.3 Calculations of Operating Margin

Emission Factor 22

8.1.4 Calculations of Build Margin Emission Factor 29

8.1.5 Calculations of Combined Margin

Emission Factor 32

8.2 SNM2 Turbine Power Generation and Quantityof Power Export (EG,y) 33

8.3 Emission Reduction Calculations: CERS to USWLfor the period 1, January 2006 -3, January 2007 38

9.0 Bagasse and Steam balance check for Baseline requirement 40

10.0 Appendices 43


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Tables

Table No Title Pageno

Table 6.1 Data to monitor emissions from the projectactivity, and how this data will be archived

8

Table 6.2 Relevant data necessary for determining thebaseline of anthropogenic emissions by sources ofGHGs Relevant data necessary for determining thebaseline of anthropogenic emissions by sources ofGHGs

9

Table .1 2001-02 OM Calculations : Calculations of CoEF i 22Table 8.2 2001-02 OM Calculations : Calculations of Emission

Factor24

Table 8.3 2002-03 OM Calculations: Calculations of COEFi, 26

Table 8.4 2002-03 OM Calculations: Calculations of EmissionFactor

26

Table 8.5 2003-04 OM Calculations: Calculations of COEFi, 28

Table 8.6 2003-04 OM Calculations: Calculations of EmissionFactor

29

Table 8.7 Build Margin Calculations 30Table 8.8 Build Margin Calculations 31

Table 8.9Calculations for Combined Margin Emission Factor 33

Table 8.10Meter Reading for SNM2 TurbineeNM2 34

Table 8.11 SNM2 Monthly Power Generation Report (Jan 2006-Jan 2007)

36

Table 8.12 Exported Power Vs Sales Receipt Figures (2006-2007)

37

Table 8.13

CERs to USWL during the period January 1, 2006 to

January 31, 2007

38


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List of Figures

Page no

Figure 5.1 Project Boundary 8

Figure 8.1 Bagasse balance at USWL 42

Figure 8.2 Steam balance at USWL 42


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1.0 Title of the project activity

Title: Grid connected Bagasse based Cogeneration project of Ugar Sugar Works

Limited (USWL).

Version: Version 02

UNFCCC Ref No: 0189

Date of completion of the Monitoring Report: March 15, 2007

2.0 Introduction

The purpose of this monitoring report is to calculate the Greenhouse Gas emission

reduction achieved by the USWL - CDM project for periodic verification.

This monitoring report covers the activity from 1, January 2006 till 31, January 2007.

The start date of the project activity is 23, November 2003 and of the crediting period is

1, January 2004.

3.0 Reference

The project is categorised in sectoral scope 1: Energy Industries (renewable / non-

renewable sources).Approved Baseline methodology: AM0015/ Version 1, applied to

this project, has its Sectoral Scope 1.

Project Design Document: Grid connected bagasse based cogeneration project of Ugar

Sugar Works Limited (USWL).

4.0 Definitions in the report

PDD: Project Design Document


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GHG: Greenhouse Gases

IPCC: Intergovernmental Panel on Climate Change

5.0 General description of the project

5.1 Project Activity

The project activity involves installation of a new cogeneration unit of 16 MW

capacity, next to the existing one of 28 MW (which has been upgraded from 18 MW).

As a part of the project activity USWL will established a high-pressure boiler of 80

tonnes/hour (Krupp make), 22.8MW (high pressure) turbine (Shin Nippon), switch

yard, bagasse dryer and other associated equipments. For the first time in the country

and sector, the project activity will deploy the bagasse dryer of 40 tonnes per hour,

which utilises waste heat of flue gases (180-190 C). Also, the project would be

amongst the first to deploy high-pressure boilers and turbine in the sector.

The project participants are:

1. Government of India

2. Ugar Sugar Works Ltd (USWL)

5.2 Technical description of the project

Location of the project activity

The cogeneration plant is located at Ugarkhurd in the premises of USWL. It is

approximately 50km from Belgaum district in Karnataka, India. The plant site is

located at latitude1712'N and longitude 5130'E. The nearest railway station is Miraj.

Technology employed by the project activity

Uptill the year 2003, USWL had a power producing capacity of 28MW and power

export to the grid was 70 GWH. The power has been generated mainly from two

turbines SNM1 and Siemens turbine. After establishing the new power plant the total

capacity of cogeneration power generation will become 44MW.The major equipment

additions in the project activity are:

One boiler of capacity 80TPH and 62kg/cm2

Turbine of 22.8MW capacity (manufacturer- Shin Nippon)


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Switch yard (two numbers of 16.4/20 MVA ONAN/ONAF 11 KV/110 KV step

up grid transformers and associated equipments)

Wet scrubber and ash handling systems for bottom ash,

Demineralisation water treatment systems

Bagasse dryer

And related electrical and instrumentation control and pollution control systems.

BiomassBagasse is the primary fuel used. With the expanded sugar mill capacity of

10000TCD bagasse production has become 127.4TPH. Total bagasse requirement for

the steam and power generation will be 127.5TPH. An additional 2500MT of cane

leave supplements the bagasse deficit of 0.1TPH or 0.05%.

The following are the novel practices in departure from the common and prevalent ones

in the sector and the region:

High Pressure Boiler and Turbine

Demineralisation of water with the mixed bed and condensate polishing unit

Bagasse Dryer- using waste heat in flue gases

Figure 5.1: Project Boundary

Use of cane leaves along with the bagasse

The technology applied for the project activity is shown in Figure 1.

Mill

10000 TCD Ba asse

Boiler House

Steam production

270TPH

SNM1 Siemens SNM2

Export To Grid

Cane


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6.0 Monitoring methodology and plan

Approved monitoring methodology AM0015 Bagasse based cogeneration

connected to an electricity grid -version 1 is applied to this project.

6.1 Data for monitoring the GHG reduction

In keeping with the Monitoring Methodology, the following parameters are to be

monitored in the specific project situation:

Electricity generation from the proposed project activity; - required in the specific

project situation

Data needed to recalculate the operating margin emission factor, if needed, based on

the choice of the method to determine the operating margin (OM), consistent with

Bagasse based cogeneration connected to an electricity grid (AM0015);- not required

recalculation in the specific project situation due to choice of simple OM, and ex-ante

option

Data needed to recalculate the build margin emission factor, if needed, consistent with

Bagasse based cogeneration connected to an electricity grid (AM0015) baseline

methodology;-not required recalculation in the specific project situation due to choice

of ex ante option in the BM calculation in AM 0015

Data needed to calculate baseline emissions due displacement of thermal energy at

project site (where relevant);- not required in the specific project situation as the heat

output (steam for use in the process) is same in baseline and project activity situation

Data required to calculate CO2 emissions from fossil fuels combusted due to the

project activity at the project site; - not required in the specific project situation, as

there is no such onsite stationary or mobile fossil fuel consumption


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Data required to calculate leakage effects due to fossil fuel switch from bagasse to

other fuels outside the project boundary; - not required in the specific project situation

as the leakages are zero


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USWL Monitoring Report 11

6.1.1 Data to monitor emissions from the project activity; and how it will be archived

Table 6.1

Data collected in order to monitor emissions from the project activity, and how

ID number

(Please use numbers

to ease cross-

referencing )

Data variable Source

of data

Data

unit

Measured

(m),

calculated

(c) or

estimated

(e)

Recording

frequency

Proportio

of data to

be

monitored

15 FFi,y Physical

Quantity,Confirmation

that no fossil

fuels were

combusted in

boilers for

cogeneration at

USWL

- Mass

unit/yror

volume

unit/yr

m yearly 100%


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6.1.2 Data to be monitored to determine the baseline of emission by sources of GHGs within th

archived.?

Table 6.2:

Relevant data necessary for determining the baseline of anthropogenic emissions by sources

and how such data will be collected and archived:

ID number

(Please use

numbers to

ease cross-

referencing

to table

D.3)

Data variable Source of

data

Data unit Measured

(m),

calculated

,

estimated

(e),

Recording

frequency

Proportio

of data

be

monitore

1EGy Electricity

Quantity,Electricity

supplied to

the grid by

SNM2

Main

controlRoom

MWh Directly

measured

Hourly

measurementand monthly

recording

100%

2 EFy Emission Central tCO2 /MWh c yearly 100%


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factor,

CO2

emission

factor of the

Southern

Regional

grid

Electricity

Authority

(CEA),

Government

of India

General

Review

Calculations,

Ex-ante

3 EFOM, y Emission

factor,

CO2

operating

margin

emissionfactor of the

Southern

Regional

grid

CEA

General

Review

tCO2 /MWh c

Calculations,

Ex-ante

yearly 100%

4 EFBM ,y Emission

factor,

CO2 build

margin

emission

factor of theSouthern

Regional

grid

CEA

General

Review

tCO2 /MWh c

Calculations,

Ex-ante

yearly 100%


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5 Fi, y Amount of

each fossil

fuel

consumed by

each power

source

CEA

General

Review

Mass or

volume

m

Ex-ante

yearly 100%

6 COEFi Emission

factor

coefficientfor each fuel

IPCC

Default

tCO2/mass

or volume

unit

m Yearly 100%

7 GEN m ,y Electricity

generation

by each

power source

CEA

General

Review

MWh/yr m

Ex-ante

Yearly 100%


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8 Identification

of Plant

source,

Name of

source power

plant for OM

CEA

General

Review

text e

Ex-ante

Yearly 100%

9 Plant name,

Name of

source power

plant for BM

CEA

General

Review

text e

Ex-ante

Yearly 100%

11a GEN

import

Electrical

quantity

CEA

General

Review

KWh c

Ex-ante

calculations

yearly 100%


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11b COEFi

imports

CO2

emission

factor in the

connected

electricity

IPCC

Default

tCO2/

mass or

volume

unit

c

Ex-ante

calculations

yearly 100%


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7.0 Quality Control (QC) and Quality Assurance (QA)

7.1 Quality Management System

The cogeneration plant is operated by Companys operating personnel. The Chief

Engineer (Cogeneration) has assigned the responsibility of the project management as

also for monitoring, measurement and reporting to the Assistant Engineers

(Cogeneration).

The operation, data transfer and reporting procedures are incorporated into the ISO 9001

procedure with the company.

The personnel are adequately trained and highly competent enough to carry out the

necessary work.

7.2 Quality control (QC) and quality assurance (QA) procedures that are

being undertaken for the data monitored

In USWL, the QA & QC procedures are equivalent to applicable International Standards

as well as standards given by the technology supplier M/s Shin Nippon and energy meter

supplier M/s Power Care, in terms of equipment and analytical methods. The QA & QC

procedures are set and implemented in order to:

1. Secure a good consistency through planning to implementation of this CDM project

and,

2. Stipulate who has responsibility for what and,

3.Avoid any misunderstanding between people and organization involved.

4.Calibration of the export energy meter


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Quality control (QC) and quality assurance (QA) procedures are being undertaken

for data monitored

Data

(Indicate

table and ID

number e.g.

3.-1.; 3.2.)

Uncertainty level of

data

(High/Medium/Low)

Explain QA/QC procedures planned for these

data, or why such procedures are not necessary.

1 and 15 Low These data will directly be used for calculation

of emission reductions. Sales records will be

sued to ensure consistency

Others Low Default data (for emission factors) and IEA

statistics (for energy data) will be used to check

local statistics

7.3 Calibration/Maintenance of Measuring and Analytical Instruments

All measuring and analytical instruments are being calibrated as per the methodology

AM0015 and created as a protocol in USWLs Quality management system procedures.

The calibration certificates for all the export meters of SNM2 Turbine are available at the

plant for the verification.

The maintenance methods and procedures have been incorporated as part of the ISO 9000

procedures and form an integral part of the systems and procedures for the organization.

7.4 Environmental Impacts Due to the Project Activity; Present Status

The project activity is small in size and hence the emissions and discharges due to the

project activity do not have any significant environmental impacts. Internal

Environmental Audit Reports are available at the project site. The cogeneration activity

uses bagasse as fuel, which is a carbon neutral fuel.


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There are no transboundary impacts.

The host party does not consider the environmental impacts of such activities as

significant and hence excluded such activities from the Environmental Impact

Assessment Notification (1991) under Environment Protection Act (1984)

However, the USWL diligently identified the possible environmental impacts and

mitigated these to the extent feasible after an environmental impact assessment of the

project activity.

USWL has obtained an environmental clearance from the state government in addition to

consent to establish and operate from the Karnataka State pollution Control Board. The

factory has ISO 14000 accreditation and therefore any environmental impacts are

recorded.

The periodic (annual) audits as a part of ISO 14000 based management systems would

take care of any undesirable environmental impacts.

8.0 GHG Calculations

8.1 GHG emission reduction, confirming to the approved methodology of AM0015)

The project activity mainly reduces the CO2 emissions from fossil fuels by energy

generation with bagasse. The emission reduction ER y by the project activity during a

year y is the difference between the baseline emissions through substitution of the

electricity generation with fossil fuels (BEelectricity, y), the baseline emissions through thesubstitution of the thermal energy generation with fossil fuels (BEthermal, y), andproject

emissions(PEy), emissions due to leakage (Ly) as follows:

ER y = BE electricity, y + BE thermal, y PE y Ly

Where,


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ER y is the emission reductions of the project activity during year y in t CO2

BE electricity, y is the baseline emissions through substitution of the electricity

generation with fossil fuels during year y in t CO2

BE thermal, y are the baseline emissions due to displacement of thermal energy

during the year y in t CO2

PEy is the project emissions during the year y in t CO2

LEy is the leakage emissions during the year y in t CO2

In the specific project case, BE thermal, y, PE y and Ly are zero or not applicable.

BEelectricity, y = EG, y EFelectricity, y

Where,

BEelectricity, y is the baseline emissions due to displacement of electricity during the

yeary in tons of CO2,

EG, y is the net quantity of increased electricity generated as a result of the project

activity during the yeary in MWh, and

EFelectricity, y is the CO2 baseline emission factor for the electricity displaced due to

the project activity during the yeary in tons CO2/MWh.

The emission factor EF y (= EFelectricity, y) of the grid is represented as a combination of

the Operating Margin(EFOM, y) and the Build Margin(EFBM, y). The emission factor EF y

,in terms of EF OM, yand EF BM, y , is given by:

EFelectricity, y

= wOM

EFOM , y

+ wBM

EFBM ,y

..(1)

wOM and wBM are respective weight factors (where wOM + wBM = 1), and by default are

weighted equally (wOM = wBM = 0.5).


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8.1.1 The Operating Margin emission factor

The Operating Margin emission factorEFOM,simple,y is defined as the generation-

weighted average emissions per electricity unit of all generating sources serving the

system, including zero- or low-operating cost power plants (hydro, geothermal, wind,

low-cost biomass, nuclear and solar generation), based on the latest year statistics data

and are derived from the following equation:

EFOM,simple,y= [i Fi,j,y*COEFi,y] / [j GENj,y] .(2)

Fi,j,yand COEFi,j,yare the fuel consumption and associated carbon coefficient of the fossil

fuel i consumed in the grid in the yeary. GENj,y is the electricity generation at the plantj

connected to the grid excluding zero- or low-operating cost sources. (EMy and GENy are

the total GHG emissions and electricity generation supplied to the grid by the power

plants connected to the grid excluding zero- or low-operating cost sources in the year y )

The CO2 emission coefficient COEFiis obtained as:

COEFi, =NCVi, * EFCO2,i * OXIDi.(3)

Where:

NCVi,jis the net calorific value per mass or volume unit of a fuel i,

OXIDiis the oxidation factor of the fuel (see page 1.29 in the 1996 Revised IPCC

Guidelines for default values),

EFCO2,iis the CO2 emission factor per unit of energy of the fuel i.

As per the approved methodology AM0015, the methodology used for the registeredCDM activity (The relevant portion in AM0015 says as given below in italics),


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The Simple OM emission factor can be calculated using either of the two following

data vintages for years(s) y:

A 3-year average, based on the most recent statistics available at the time of PDD

submission, or

The year in which project generation occurs, if EF OM, y is updated based on ex post

monitoring.

In the registered PDD, from the above options given in AM0015 for using data vintages,

a 3-year average, based on the most recent statistics available at the time of PDD

submission was used. Hence the Simple OM, as used in the registered PDD, has been

used for the present calculations for this monitoring period. The Simple OM calculations,

as used in the registered PDD, are shown in the Tables 8.1- 8.6

8.1.2 Build margin emission factor

The Build Margin emission factor EFBM,y is given as the generation-weighted average

emission factor of the selected representative set of recent power plants represented by

the 5 most recent plants or the most 20% of the generating units built (summation is over

such plants specified by k):

EFBM,y= [,m Fi,m,y*COEFi,m] / [m GENm,y]..(4)

As per the approved methodology AM0015, the Build Margin emission factor has been

calculated in the registered PDD using Option 1:

The relevant portion in AM0015 says as given below in italics:

Option 1: Calculate the Build Margin emission factor EF BM, y ex ante based on the

most recent

Information available on plants already built for sample group m at the time of PDD

submission. The sample group m consists of either:

The five power plants that have been built most recently, or


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The power plants capacity additions in the electricity system that comprise 20% of the

system

Generation (in MWh) and that have been built most recently.

Project participants should use from these two options that sample group that

comprises the larger annual generation.

In the registered PDD, Build Margin emission factor EF BM,, y has been calculated, with

the option of ex-ante, based on the most recent information available on plants already

built for sample group m at the time of PDD submission. The sample group m has been

power plants capacity additions in the electricity system that comprise 20% of the system

generation (in MWh) and that have been built most recently, and has comprised larger

annual generation. The Build Margin Calculations as used in the registered PDD are

presented in the Tables 8.7 and 8.8

8.1.3 Calculations of Operating Margin Emission Factor

Operating Margin Emission Factor

EFOM,simple,y= [i Fi,j,y*COEFi,y] / [j GENj,y] .(2)

Calculations of COEFi,y

COEFi, =NCVi, * EFCO2,i * OXIDi.(3)

Where:

NCVi,jis the net calorific value per mass or volume unit of a fuel i,

OXIDiis the oxidation factor of the fuel (see page 1.29 in the 1996 Revised IPCC

Guidelines for default values

EFCO2,iis the CO2 emission factor per unit of energy of the fuel i.


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OM Calculations - 2001-02

Table 8.1: Calculations of COEFi, usingquation (3)

Type of FUEL

Net Calorific Value*(TJ/ 10

3tonnes or

TJ/Mcum)(NCVi),

Carbon EmissionFactor* (t C/ TJ )

(EFCO2,I)

Fraction of CarbonOxidised - Oxidation

Factor**(OXIDi)

Steam Stations ** * ***

****Coal 20.284077 26.2 0.980

**Furnace diesel 43.9467402 21.1 0.990

**Light Oil 43.7792762 20.0 0.990

**LSHS/HHS/ oil/HSD 43.7792762 20.2 0.990

Gas

****Lignite 10.989825 27.6 0.980

Gas Stations

*****Natural Gas (TJ/Mcum) 34.6 15.3 0.995

**HSD 43.0926738 20.2 0.990

**Naphtha 45.01 20.0 0.990

Diesel Stations

**LSHS 43.7813676 20.2 0.990

**Diesel Oil 43.0947324 20.2 0.990

COEFi, =NCVi, * EFCO2,i * OXIDiSample Calculation for Coal = COEF = 20.284077 * 26.2 * 0.98 = 1909.7 tCO 2/ 10

3tonnes


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Sample Calculations

Sample Calculations for Coal given in the above Table

Gross Emissions (tCO2) = Fi, y*COEF i,y

= 52607.0*1909.7=100461020.2 tCO2

Net Electricity Gnration = Gross Electricity Auxiliary Consumption

= 84031 (84031*8.44/100)= 76938.78 GWh

Operating Margin Calculations

EFOM, simple, 2001-02 = Gross Emission/Net Generation

= 125802369/90994.03

= 1382.534 tCO2/GWh


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2002-03

Table 8.3: Calculations of COEFi, usingequation (3)

Type of FUEL

Net Calorific Value*

(TJ/ 103 tonnes orTJ/Mcum)

(NCVi),


(EFCO2,I)

Fraction of Carbon Oxid- Oxidation Factor**

(OXIDi)


****Coal 17.4623086 26.2 0.980

**Furnace diesel 44.9054716 21.1 0.990

**Light Oil 44.0597784 20.0 0.990

**LSHS/HHS/ oil/HSD 44.0597784 20.2 0.990

Gas

****Lignite 11.2452076 27.6 0.980

Gas Stations

*****Natural Gas (TJ/Mcum) 34.6 15.3 0.995

**HSD 40.861216 20.2 0.990

**Naphtha 45.01 20.0 0.990

Diesel Stations

**LSHS 44.0618832 20.2 0.990

**Diesel Oil 40.863168 20.2 0.990


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Table 8.4 : Calculations of Operating Margin Emission Factor using equati

Fuel Units ConsumptionDensity(kg/Lt)

103

MT(Fi,j,y)

Emissionfactor(tCO

2/10

3

tonnes)*NG=TCO2/MCu.m)(COEFi,y)

GrossEmissions(tCO2)

GrossElectrictygeneration

Ac

Steam Stations * * * *

Coal 000 MT 65997 1.0 65997.0 1644.0108498729.0 92053.1

Furnace Oil KL 115914 0.9 107.8 3439.4 370772.2

Light Oil KL 8407 0.8 7.0 3198.7 22239.5

LSHS/HHS/HSDKL 6093 0.8 5.0 3230.7 16279.3

Gas KL 0.0 0.0 Lignite 000 MT 17738 1.0 17738.0 1115.3 19782388.0

Gas Stations

Natural Gas M Cu M 3130 1.0 3130.0 1931.4 6045140.2 13950.1

HSD KL 275122 0.8 227.5 2996.2 681710.7

Naphtha KL 485496 0.8 369.0 3267.7 1205715.6

Diesel Stations 0.0 0.0

LSHS KL 0 0.8 0.0 3230.9 0.0 4379.4

Diesel KL 865938 0.8 716.1 2996.3 2145765.9

138768741

O* Source ;table 6.1, CEA general Review

** Table 5.5, CEA general review

Note: Values in Column 6 (blue highlights) have been taken from Table


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EFOM,simple,2002-03 = 138768741/102201.3 = 1357.798 tCO2/GWh

2003-04

Table 8.5: Calculations of COEFi, usingequation (3)

Type of FUEL

Net Calorific Value*(TJ/ 10

3tonnes or

TJ/Mcum)(NCVi),


(EFCO2,I)

Fraction of Carbon Oxid- Oxidation Factor**

(OXIDi)


****Coal 15.992812 26.2 0.980

**Furnace diesel 43.394109 21.1 0.990

**Light Oil 43.1303532 20.0 0.990

**LSHS/HHS/ oil/HSD 43.1303532 20.2 0.990

Gas****Lignite 11.4587242 27.6 0.980

Gas Stations

*****Natural Gas

(TJ/Mcum) 34.6 15.3 0.995

**HSD 42.6447076 20.2 0.990

**Naphtha 45.01 20.0 0.990

Diesel Stations

**LSHS 43.1324136 20.2 0.990

**Diesel Oil 42.6467448 20.2 0.990


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Table 8.6 : Calculations of Operating Margin Emission Factor using equati

Fuel Units ConsumptionDensity(kg/Lt)

103

MT(Fi,j,y)

Emissionfactor(tCO

2/10

3

tonnes)*NG=TCO2/MCu.m)(COEFi,y)

GrossEmissions(tCO2)

GrossElectrictygeneration

Ac

Steam stations * * * *

Coal 000 MT 52985 1.0 52985.0 1505.6 79776792.0 98434.6

Furnace Oil KL 56498 0.9 52.5 3323.7 174636.8

Light Oil KL 33031 0.8 27.3 3131.3 85535.6

LSHS/HHS/HSDKL 5310 0.8 4.4 3162.6 13888.0

GAS KL 0.0 0.0 Lignite 000 MT 20755 1.0 20755.0 1136.4 23586613.6

Gas Stations

Natural Gas M Cu M 2010 1.0 2010.0 1931.4 3882022.9 14214

HSD KL 226981 0.8 187.7 3127.0 586973.0

Naphtha KL 719694 0.8 547.0 3267.7 1787339.7


LSHS KL 647451 0.8 535.4 3162.7 1693457.0 3294.75

Diesel KL 14903 0.8 12.3 3127.1 38541.0

111625800

ONote: Values in Column 6 (blue highlights) have been taken from Table

EFOM ,simple,2003-04 = 111625800/107156.2

= 1041.711 tCO2/GWh


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8.1.4 Calculations of Build Margin Emission Factor

Table 8.7: Build Margin Calculations using Equation (3)

Fuel Units Consumption

Density

(kg/Lt) 103

MT

Emission

factor(tCO2/10

3

tonnes)*

NG=TCO2/M

Cu.m)

GrossEmissions

(tCO2)

GrossElectricty

generation

Auxiliar

consumpti

Steam stations * * * **

Coal 000 MT 52985 1.0 52985.0 1505.6 79776792.0 98434.6 8.46

Furnace Oil KL 56498 0.9 52.5 3323.7 174636.8 8.46

Light Oil KL 33031 0.8 27.3 3131.3 85535.6 8.46

LSHS/HHS/HSD KL 5310 0.8 4.4 3162.6 13888.0 8.46

GAS KL 0.0 0.0 8.46

Lignite 000 MT 20755 1.0 20755.0 1136.4 23586613.6 8.46

Gas Stations 103637466.0

Natural Gas M Cu M 2010 1.0 2010.0 1931.4 3882022.9 14214 2.83

HSD KL 226981 0.8 187.7 3127.0 586973.0 2.83

Naphtha KL 719694 0.8 547.0 3267.7 1787339.7 2.83


LSHS KL 647451 0.8 535.4 3162.7 1693457.0 3294.75 1.74

Diesel KL 14903 0.8 12.3 3127.1 38541.0 1.74

1731998


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Table 8.8: Build Margin Calculations using equation (4)

Type of Power Gen State Date of additionInstalledCapacity PLF

GrossGen

MW GWhAuxilaryConsm

* * * * ** **

Hydro

Srisailam LBPH (Unit6) AP 4-Sep-04 150 0.5 657

Almatti Dam Karnataka 26-Mar-04 15 0.5 65.7

Sirsailam Left bank(5) AP 28-Mar-03 150 0.5 657

Sri Sailam LBPH AP 26-Nov-02 150 0.5 657

Sirsailam Left bank(2,3) AP 12-Nov-01,29-Mar-02 300 0.5 1314

Sirsailam Left bank(1) AP 30-Mar-01 150 0.5 657

Sharavathy Tail Race (2,3,4) Karnataka15-May-01,25-Oct-01,30-Mar-02 180 0.5 788.4

Madhva Mantri Karnataka Mar-02 3 0.5 13.14 Madhva Mantri Karnataka Mar-02 6.6 0.5 28.908

Steam **

Neyveli FST TN 22-Jul-03 210 0.77 1416.49

Simadhri AP 24-Aug-02 500 0.88 3854.4

Raichur Karnataka 11-Dec-02 210 0.88 1618.85

Neyvelli TPS (1,2) TN 21-Oct-02 210 0.77 1416.49

Neyvelli TPS (Zero unit) TN 11-Oct-02 250 0.77 1686.3

Simhadri TPS AP 22-Feb-02 500 0.88 3854.4

Diesel **

Kasargode DG Kar Mar-02 21.84 0.88 168.36

Belgaum DG Kar Mar-02 81.3 0.88 626.725 Samayanallue DGPP TN 22-Sep-01 106 0.77 714.991

LVS DGPP AP 18-Oct-01 36.8 0.86 277.236

Sampalpatti DG (1-7) TN 1-Mar-01 105.66 0.77 712.698

Wind 0


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Private AP 31-Mar-04 6.2 0.25 13.578

Private TN 31-Mar-04 504.06 0.25 1103.89

State TN 31-Mar-04 0.07 0.25 0.1533

State Karnataka 31-Mar-04 2.02 0.25 4.4238

Private Karnataka 31-Mar-04 138.58 0.25 303.49 Wind (state) AP 1-Jun-01 2.35 0.25 5.1465

Wind (pvt) AP 1-Jun-01 0.69 0.25 1.5111

Wind (pvt) TN 1-Jun-01 69.38 0.25 151.942

Wind (pvt) Kar 1-Jun-01 30.78 0.25 67.4082

Gas **

Kuttalam CCPPGT TN 26-Nov-03 63 0.78 430.466

Kuttalam CCPP TN 24-Mar-04 37 0.78 252.814

Valthur GTPP TN 24-Dec-02 60 0.78 409.968

Valthur (ST )GTPP TN 13-Mar-03 34 0.78 232.315

Peddapuram CCGT AP 12-Sep-02 78 0.86 587.621

Peddapuram CCGT AP 26-Jan-02 142 0.86 1069.77

Pillaiperumalanallur CCGT (stU-1) TN 5-Apr-01 105.5 0.78 720.86

Tanir Bavi CCGT (Unit1,2,3,4) Karanataak 8-May-01 170 0.88 1310.5

Tanir Bavi CCGT (St-10 Kar 21-Nov-01 50 0.88 385.44

Kovikalappal GT (Unit-ST-1) TN 30-Mar-01 38 0.78 259.646

28496

BM=

Total Gross Electrical Ene Gen for WR grid (2003-2004) = 139451.1 Percent

Total Gross Ele Gen from the power plant which is added to the ele system = 28496.03 20.4344

Note: Values in Column 9 (blue highlights) have been taken from Table


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EFBM,y= [,m Fi,m,y*COEFi,m] / [m GENm,y]..(4)

=19827215/27046

= 733.0994 tCO2/GWh

8.1.5 Calculations of Combined Margin Emission Factor

Table 8.9: Calculations for Combined Margin Emission Factor

Simple OM TCO2/GWh

2001-2002 1382.53 tCO2/GWh

2002-2003 1357.80 tCO2/GWh

2003-2004 1041.71 tCO2/GWh

Total 3782.04

Simple OM EFOM,y 1260.68 tCO2/GWh

BM EFBM,y 733.10 tCO2/GWh

CM EFy 996.89 tCO2/GWh


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8.2 SNM2 Turbine Generation and Power Export (EG,y)

Table 8.10: Meter Reading for SNM2

Note: 52 G3 is total generation meter for SNM2 and 52 F3, 52 F4 are Expo

The values given in column (a), (d) and (g) in the above table are cumu

SNM2 Meter READINGS

52G3

(a)

K.W.H

(b)

M.W.H

( c)

52F3

(d)

K.W.H

(e)

M.W.H

(f)

52F4

(g)

K.W.H

(h)

M

(

31/01/2006 89324 10045000 10045 22527 4940000 4940 51793 4384000 4

28/02/2006 98864 9540000 9540 25779 3252000 3252 56307 4514000 4

31/03/2006 107588 8724000 8724 26725 946000 946 60757 4450000 4

30/04/2006 113033 5445000 5445 28176 1451000 1451 62932 2175000 2

31/05/2006 113033 0 0 28176 0 0 62932 0 0

30/06/2006 113033 0 0 28176 0 0 62932 0 0

31/07/2006 113033 0 0 28176 0 0 62932 0 0

31/08/2006 113033 0 0 28176 0 0 62932 0 0

30/09/2006 113033 0 0 28176 0 0 62932 0 0

31/10/2006 113033 0 0 28176 0 0 62932 0 0

30/11/2006113494 461000

461 28421 245000 245 62932 0 0

31/12/2006124751 11257000

11257 35203 6782000 6782 63198 266000 2

31/01/2007

135275 10524000 10524 40990 5787000 5787 63230 32000 3


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Sample calculation for 28/02/2006

(1) Total generation recorded by 52G3 feeder from SNM2

(b) i = (a)i- (a)i-1 1000

(b) 28/02/2006 = (98864- 89324) 1000 = 9540000 KWh

(2) Total generation in MWh

(c) i = (b)i / 1000

(c) 28/02/2006 = 9540000/1000 = 9540 MWh

(3) Units recorded by 52F3 Feeder for SNM2

(e) i = (d)i (d)i-1 1000

(e) 28/02/2006 = (25779- 22527) 1000= 3252000 KWh

(4) Export recorded by 52F3 Feeder for SNM2 in MWh

(f) i=(e)i/1000

(f) 28/02/2006= 3252000/1000 = 3252 MWh

(5) Units recorded by 52F4 Feeder for SNM2

(h) i= (g)i-(g)i-1 1000

(h) 28/02/2006= (56307-51793) = 4514000 KWh

(6) Export recorded by 52F4 Feeder for SNM2 in MWh

(i) i= (h)i/1000

(i) 28/02/2006 = (4514000)/1000 = 4514 MWh

(7) Total export from SNM2 in MWh

(j) i= (f)i + (i)i

(j) 28/02/2006= 3252+4514= 7766 MWh


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Table 8.11: SNM2 Monthly Report (2006-2007) of power generation and ex

S .N. M 2

2006

MON

GENERATION

MON

EXPORT

K.W.H. M.W.H K.W.H. M.W.H

JANUARY 10045000 10045 9324000 9324

FEBRUARY 9540000 9540 7766000 7766

MARCH 8724000 8724 5396000 5396

APRIL 5445000 5445 3626000 3626

MAY 0 0 0 0

JUNE 0 0 0 0

JULY 0 0 0 0

AUGUST 0 0 0 0

SEPTEMBER 0 0 0 0

OCTOBER 0 0 0 0

NOVEMBER 461000 461 245000 245

DECEMBER 11257000 11257 7048000 7048

JANUARY 10524000 10524 5819000 5819

TOTAL

55996000 55996 39224000 39224


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Table 8.12: Exported Power vs Sales Receipt Figures for the turbines SNM1, SNM2 & SIE

1, Jan 2006 to

31, Jan 2007

Total Gen From

(SNM1, SNM2 &

SIEMENS) Mwh

Total Exp From

(SNM1,SNM2&SIEMENS)

BILLING EXP

(SNM1,SNM2&SIE

JANUARY 22149.72 12190 12177

FEBRUARY 22263.88 12203 12202

MARCH 21813.36 11051 11076

APRIL 11083.49 5193 5255

MAY 1536.4 996 968

JUNE 3665.65 2542 2564

JULY 4490.63 3120 3126

AUGUST 0 0 0

SEPTEMBER 0 0 0

OCTOBER 0 0 0

NOVEMBER 711.68 234 212

DECEMBER 22315.76 11992 11948

JANUARY,

200720800 11178 11172

130830.57 7069970700

Note: The variation between Export Figures vs Sales Receipt is due to different timings for noting the re

KPTCL. USWL notes the readings at 4.00 am daily, while KPTCL generally note their readin


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8.3 Emission Reduction Calculations, CERs to USWL

Emission Reductions can be calculated using equation (1)

BEelectricity,y = EG,y EFelectricity, y

EG2006-07 = 39224 MWh

EF electricity = 0.996 tCO2/MWh

BE electricity = 39224 0.996 = 39067.104 tCO2/MWh

Table 8.13: CERS to USWL during the period January 1, 2006 to January 31, 2007

SrNo

YearEG,y (MWh) EF,y

(tCO2/MWh)CERs

1.Jan 1, 2006 -

January 31, 200739224 0.996

39067.104


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9.0 Bagasse and Steam balance check for Baseline

requirement

The bagasse and steam balance is monitored and recorded to check that the

1. Purchased bagasse is not used in the project activity

2. Bagasse is not diverted to project activity from other existing activities.

The calculation of the steam and bagasse balance for the period 1st January 2006 to 31st

January 2007 is given in Appendix 13.

The bagasse and steam balance will be done as below:


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Figure 8.1: Bagasse balance at USWL

Figure 8.2: Steam balance at USWL


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10.0 Appendices

Appendix 1

Name of item FFi,y

Description Amount of fossil fuel consumed at the

project activity

Value in period 0 ton

Recording frequency Yearly

Background data Furnace oil consumption file available at

plant

Calculation method Measured from the furnace oil data

source available at plant

Archiving mode Electronic

Year Fossil Fuel Consumption (Tonnes)

1st

January 2006 31st

January 2007 0


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Appendix 2

Name of item EG, y

Description Electricity Quantity, Electricity supplied

to grid by SNM2

Value in period 39224 MWh

Method of monitoring Measured using Energy Meter

Recording frequency Hourly

Background data Log sheets available at the plant

Calculation method Measured from the log sheets available at

plantArchiving mode Electronic

Year EF, y

MWh

1, January 2006 31, January 2007 39224

Refer to Table 8.11


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Appendix 3

Name of item EF,y - Ex-ante option for OM calculations

Description Emission Factor, CO2 Emission factor for

Southern Regional Grid

Value in period 0.996 tCO2/MWh


Background data CEA general review

Calculation method Calculated from CEA general review


Year EF,y

tCO2/MWh

1, January 2006 31, January 2007 0.996

Refer Tables 8.1 -8.6 for calculations


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Appendix 4

Name of item EFOM,y

Description Emission Factor, CO2 Operating Margin

Emission factor for Southern Regional

Grid






Year EF,OMy

tCO2/MWh

1st

January 2006 31st

January 2007 1.261; Ex-ante

Refer Table 8.1-8.6 for calculations


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Appendix 5

Name of item EFBM,y

Description Emission Factor, CO2 Build Margin

Emission factor for Southern Regional

Grid






Year EF,BM y

tCO2/MWh

1st

January 2006 31st

January 2007 0.733; Ex-ante

Refer to Tables 8.7 and 8.8 for calculations

Appendix 6

Name of item Fi,y

Description Amount of each fossil fuel consumed by

each power source

Value in period At Tables 8.2, 8.4, and 8.6 for the periods

2001-02, 2002-03, and 2003-04 (3rd

Column ). Example: 5,29,85,000 MT in

2003-04 for coal


Background document CEA general review


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Calculation method Data extracted from CEA general review


Appendix 7

Name of item COEFi

Description Emission factor coefficient for each fuel


2001-02, 2002-03, and 2003-04.

Example: 1505.6 tCO2/10

3

tonnes in2003-04 for coal


Background document IPCC Default

Calculation method Data from the IPPC source


Appendix 8

Name of item Genm,y

Description Electricity generation by each power

source


2001-02, 2002-03, and 2003-04.

Example: 98434600 MWh/yr in 2003-04

due to coal



Calculation method Data measured from CEA general review



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Appendix 9

Name of item Sr No 8 in Table

Description Identification of plant source, Name of

source of power plant for OM


2001-02, 2002-03, and 2003-04.

Example: Coal is source of power plant

for OM in 2003-04



Calculation method Text


Appendix 10

Name of item Sr No 8 in Table

Description Identification of plant source, Name of

source of power plant for BM

Value in period At Tables 8.8 for the periods 2003-04

Example: Neyveli FST is a power

plant(steam)



Calculation method Text



50/52



Appendix 11

Name of item GEN import

Description Electrical Quantity

Value in period 119835223 KWh



Calculation method Calculated based on CEA general review


Appendix 12

Name of item COEFi, imports

Description CO2 Emission factor in the connected grid

Value in period 1505.6 tCO2/103 tonnes in the year 2003-

04


Background document IPCC Default

Calculation method Data from the IPPC source



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Appendix 13

Bagasse Balance

Statement showing Mass balance of Fuel for the period 1, Jan 06 31, Jan 07)

1) Own Bagasse generated 438721.11 4387.211 (1% to Oliver)

= 434333.89 MT

2) Bagasse Purchased 21012.9 MT

3) Steam generated from 4 HP

Boilers

894633.84 MT

4) Bagasse consumed by 4 HP

Boilers

894633.84 /2 (where 2 is Steam fuel ratio)

= 447316.79 MT

5) Steam generated by 50 TPHBoiler

24186.41 MT

a) Rectified Spirit 3998732*3.5 (3.5 kg of steam require to produce 1lit RS)

=13995562 kg = 13995.56 MTb) Neutralized Spirit 1682321.1*6.0 (6.0 kg steam require to produce 1 lit NS)

=10093926.60 kg = 10093.93 MT

c) Ethanol 437634.8*4.5 (4.5 kg steam is require to produce 1lit Ethanol)

=1969356.60 kg = 1969.36 MT

Total A+b+c

26058.85=*1.05 = 27361.79 (5% losses added)

6) Bagasse consumed by 50 TPH

Boiler

27361.79/1.6 (where 1.6 is steam fuel ratio)

=17101.12 MT

Own

Bagasse

(OBi)

434333.89 MT

Bagasse required for 4

Boilers

(BBi)

447316.79 MT

Bagasse Used in 4

Boilers (OB1i)447316.79 MT

Excess Bagasse

(OB2i)-12982.9 MT

InventoryIBi= OB2i+BS(i-1)

6806.34 MT

Previous Stock in

inventory (BS(i-

1))19789.24 MT

Purchased Bagasse

(PBi) used in 50TPH Boiler

17101.12 MT

Bagasse required for

50 TPH Boiler T(Bi)

17101.12 MT


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Balance:

Own Bagasse + Purchased Bagasse + Inventory from Previous Year = Excess

Bagasse(from own bagasse after used for 4Hp Boilers) + Inventory carried to next year +

Bagasse consumed by 4 HP Boilers + Bagasse consumed by 50 TPH Boiler

434333.89 + 21012.9 + 19789.24 = -12982.9 + 17316 + 447316.79 + 17101.12

475136.03 468751.01 (1.34%)

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