Registered PDD

8/3/2019 Registered PDD

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PROJECT DESIGN DOCUMENT FORM (CDM PDD) - Version 02

CDM Executive Board page 1

This template shall not be altered. It shall be completed without modifying/adding headings or logo, format or font.

CLEAN DEVELOPMENT MECHANISM

PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 02 - in effect as of: 1 July 2004)

CONTENTS

A. General description of project activity

B. Application of a baseline methodology

C. Duration of the project activity / Crediting period

D. Application of a monitoring methodology and plan

E. Estimations of GHG emissions by sources

F. Environmental impacts

G. Stakeholders comments

Annexure

Annex 1: Contact information on participants in the project activity

Annex 2: Information regarding public funding

Annex 3: Baseline information

Annex 4: Monitoring plan


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SECTION A. General description of project activity

A.1 Title of the project activity:

Switching of fuel from Naphtha to Natural gas at United Phosphorus Limited (UPL)

Version: 02

Date: 28/03/2006

A.2. Description of the project activity:

United Phosphorus Limited (UPL), is the largest producer of crop protection products in India.

UPL has one of its manufacturing units in Jhagadia, in the state of Gujarat in India. It runs a state of art,integrated Caustic Chlorine and Value-added Specialty Chemical Complex at Jhagadia. The powerrequirement of this unit is catered by the captive Power plant situated with in the complex at Jhagadia.

The project activity primarily aims at reducing GHG gas emission through switching Naphtha as a fuel toNatural Gas as a fuel for their power plant. While Naphtha was used as a continuous run regular fuel,HSD was the start up fuel. The consumption of Naphtha was around 50,000 Tons/year. The initialfinancial analysis of the fuel switch project showed unattractiveness due to the huge investments thatwould go into making this project a reality. But, the extra income derived from the sale of carbon creditswas envisaged to pay for the part of the conversion.

The project also brings social (employment, health and labor conditions), environmental (air quality) andeconomic benefits, thus contributing to sustainable development objectives of the government of India.

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 interim approval guidelines for Clean Development Mechanism (CDM) projects.

Social well being

By demonstrating feasibility of adoption of a cleaner fuel, by taking recourse to innovativefinance mechanism (clean development Mechanism), the project helps diffusion of use of cleanfuel in a industrial project

Environmental well being

Natural gas use produces less Greenhouse gases into the atmosphere in comparison to Naphtha;

Project activity reduces the Greenhouse gases emissions to local and global environment. Reduce GHG emissions per unit of electricity generation;

Economic well being

The project activity has resulted in direct and indirect employment generation due to lay down ofpipeline for gas transport in the regions;


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Technological well being

The project activity involves implementation of a newly built infrastructure using state of the arttechnology for transmission & distribution of natural gas.

The project activity increases the safety of the operations and hazard potentials.

A.3. Project participants:

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)

Ministry of Environment and

Forest, Government of India;(DNA of Government of India.)(Host)

United Phosphorus Limited

(UPL)(Project proponent)

No

United Phosphorus Limited will be the sole owner of the CERs generated from the project. The projectactivity is of unilateral kind.

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

A.4.1.1. Host Party(ies):

Government of India.

A.4.1.2. Region/State/Province etc.:

State of Gujarat in India

A.4.1.3. City/Town/Community etc:

Jhagadia

A.4.1.4. Detail of physical location, including information allowing the

unique identification of this project activity (maximum one page):

The project is located within -Jhagadia industrial estate complex of Gujarat with approximate location -210 20' 45" - N latitude and - 720 34' 19"-E longitude. The site is at a distance of 100 kms from

Baroda by road. The nearest airport is Baroda .The nearest railway station is at Ankleshwar, Dist:Bharuch about 20 km away from site. The site is located at 10 kms away south -east of Narmada river.The site location is located at an altitude of 38.25m above MSL


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A.4.2. Category(ies) of project activity:

The project activity is applicable to Scope Number 4, manufacturing Industries, as per the CDM sectoralscope.

A.4.3. Technology to be employed by the project activity:

UPL has employed a cogeneration technology for power generation. In this technology the fuel is fired into the gas turbine from where its exits into a combustor. In the combustor there is a mix of air and fueldemand during firing/ignition. Once the engine reaches to its Full Speed No load Stage and warm upcycle is completed, it needs to be synchronised with grid to load the machine or one may choose to run iton a Island Mode i.e isolation from the grid. There after the fuel demand may increase as per the load.

The fired fuel generates huge amount of hot gas, which strikes on turbine blades to run the turbine. Theturbine shafts being connected to the generator generate power, which gets evacuated through theelectrical distribution system. The entire energy of the hot gas generated by natural gas is not utilised inpower generation but partly gets exhausted from turbine outlet. With the help of Heat Recovery SteamGenerator, the exhaust gas energy is used for steam generation. The steam generated may be categorized

into a low-pressure steam or a high-pressure steam. Low pressure is utilised in house or recycled back toconserve water. The high-pressure steam is utilised in two different ways. Firstly it may be sent to steamturbine power generation and secondly may be diverted for process use through pressure reducing cumde-super heating process.

UPL uses LM6000 gas turbine based on Natural gas (single fuel system). Prior to this, the turbine hadprovisions for Liquid fuel ( naphtha as well as diesel ). General Electric is the technology provider.


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The initiatives that lead to fuel switch required UPL to change their equipments right from outside theengine to the final feeding point into the engine i.e. up to the fuel nozzle.

Further due to the project activity the following conversions took place1. Fuel manifold - liquid fuel manifold i.e. two in numbers (primary and secondary) replaced by single

gas manifold.2. Liquid fuel driver i.e. diesel and naphtha driver replaced by gas driver only.3. Dual fuel nozzles replaced by single fuel nozzles.4. Piping and Instrumentation Diagram Changes5. Equipments outside the engine

The turbine is an aero derivative gas turbine, first developed for use in aircraft and subsequently utilizedfor power generation. This turbine is efficient, reliable and light in weight. Such turbine is only at a fewplaces in India and in fact at three locations. These turbines are operating on Naphtha and this projectactivity is the only fuel shift activity for this class of turbines in India.

A.4.4. Brief explanation of how the anthropogenic emissions of anthropogenic greenhouse

gas(GHGs) by sources are to be reduced by the proposed CDM project activity, including why the

emission reductions would not occur in the absence of the proposed project activity, taking into

account national and/or sectoral policies and circumstances:

The proposed CDM project would reduce the emissions of CO2 by replacing more carbon intensive fuels(Naphtha/HSD) by natural gas.

Each fuel existing in nature is associated with a carbon emission factor, and such number differsdepending on the fuel itself. Natural gas is considered the cleanest fuel of the fossil fuels, as its

combustion is associated with low GHG emissions.

The shift in the fuel from Naphtha/HSD to Natural Gas at the project site would also lead to reducedemissions caused by the transportation of Naphtha and HSD by road, in addition to those that are duecombustion of fuel. There would be additional reduction in emissions, as this mode of transport will nolonger be needed.

Switching from Naphtha to natural gas would require investment in new equipments. The additionalinvestments imply that project will not be cost effective on its own, in the absence of benefits from GHGemissions reductions. The baseline adopted for the project is based on the assumption that in the absenceof benefits from the project being a clean development mechanism project, the company would continueoperating its plant with Naphtha, following the trends of the sector as a whole. Thus the project activityis not the baseline and the estimated emission reductions would not occur in the absence of it. Therefore

the project shows reduced GHG emission since the CO2 emission from natural gas is lower than fromNaphtha and HSD.

The estimated total reduction in tonnes of CO2 equivalent over the crediting period of 10 years is 557826tCO2e.


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A.4.4.1. Estimated amount of emission reductions over the chosen crediting period:

The estimated emission reductions over the 10 year fixed crediting period would be 557826 tCO2e.

Year

Annual estimation of

emission reductionsin tonnes of CO2e

Jun 02- Dec 02 33240

Jan 03-Dec 03 54205

Jan 04-Dec 04 56660

Jan 05-Dec 05 55783

Jan 06-Dec 06 55783

Jan 07-Dec 07 55783

Jan 08-Dec 08 55783

Jan 09-Dec 09 55783

Jan 10-Dec 10 55783

Jan 11-Dec 11 55783

Jan 12-May 12 23243

Total estimated reductions (tonnes ofCO2e) 557826

Total Number of Crediting Years 10 years

Annual average over the creditingperiod of estimated reductions (tonnesof CO2e) 55783

A.4.5. Public funding of the project activity:

This CDM project activity has been internally funded. No public funding or ODA has been used on thisproject activity.

SECTION B. Application of a baseline methodology

B.1. Title and reference of the approved baseline methodology applied to the project activity:

Title: Baseline methodology applied to UPL is AM0008 named Industrial fuel switching fromcoal and petroleum fuels to natural gas without extension of capacity and lifetime of thefacility

Reference: AM0008

B.1.1. Justification of the choice of the methodology and why it is applicable to the project

activity:

As per the methodology document, the methodology is applicable to a project activity, which is to switchthe industrial fuel currently used in some element process of a facility to a natural gas from coal, and /orpetroleum fuels that would otherwise continue to be used during the crediting period.


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The conditions under which the methodology would be applicable are delineated:

The local regulations/programs do not constrain the facility from using coal/petroleum fuels;

Use of coal and/or petroleum fuels is less expensive than natural gas per unit of energy in the

country and sector; The facility would not have major efficiency improvements during the crediting period;

The project activity does not increase the capacity of final outputs and lifetime of the existingfacility during the crediting period (i.e., this methodology is applicable by the end of the lifetimeof existing facility if shorter than crediting period), and

The proposed project activity is defined as fuel switching applied to element processes and doesnot result in integrated process change, except for possible associated changes in other energy use(such as electricity for coal processing) outside the affected element processes, which shall(could) be treated as leakage.

The present project activity is a switch from Naphtha to Natural gas to generate power, the capacity ofgeneration remaining the same. The use of Natural gas would replace Naphtha resulting in loweremissions.

The present project activity is eligible to use the approved methodology AM0008 for Industrial fuelswitching from coal and petroleum fuels to natural gas without extension of capacity and lifetime of thefacility since the following conditions in the project activity fulfil all the applicability conditions as inAM 0008 :

The local regulations/programs in the state of Gujarat or in India do not constrain the facilityfrom using Naphtha

Since India has no regulation, which requires a manufacturing unit to switch the industrial fuelcurrently being used to natural gas from Coal and/ or petroleum fuel. The Indian Electricity Act of2003 does not restrict or empower any authority to the fuel choice for power generation. There are noenvironmental regulations in India and Gujarat state preventing the use of naphtha/petroleum fuel/

coal or promoting the use of natural gas for power generation.

1

The use of coal as a fuel is less expensive than the natural gas per unit of energy generation inIndia.

India has some of the largest reserves of coal in the world (As per the latest estimate of GeologicalSurvey of India (GSI), coal resources in the country are 211.59 billion tonnes, upto the depth of 1200metres.) in the world. Lignite reserves in the country are approximately 27.45 billion tonnes.2 Coal isthe dominant energy source in India, accounting for more than half of the country's requirements.70% of India's coal production is used for power generation, with the remainder being used by heavyindustry and public use.3

The State of Gujarat where the plant is located is rich in lignite deposits. The plant based on lignite asfeedstock have been put up by Gujarat Industries Power Company Limited (GIPCL )(Surat LigniteTPP (Unit -1 & 2)(date of addition :16/01/00,06/11/99)4 (250 MW) and by Gujarat company Gujarat

1 www.powermin.nic.in/acts_notification/ electricity_act2003/preliminary.htm - 41k -

2http://pib.nic.in/archieve/factsheet/fs2000/coal.html

3 http://www.mbendi.co.za/indy/ming/coal/as/in/p0005.htm

4 CEA General Review 1999-00


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Mineral Development Corporation (GMDC) (125 MW Akrimota TPS )5. Both GMDC and GIPCLare further planning new plants based on lignite.

Generating Stations in Gujarat receive coal from far off places in the eastern part of the Country. To

mitigate the impact of the transportation cost, Gujarat Electricity Board (GEB) has secured linkagesof coal from the Western Coal fields (WCL). The cost of generation of power has also got reduced byway of purchase of beneficiated coal and the washed coal. However, new capacity added is on lignitenot coal as due to development of lignite mines in the state of Gujarat. M/s. GIPCL is also engaged ingeneration of power by exploiting lignite deposits in Gujarat.

The break-up of the net addition is as under:

2 x 125 MW Pit Head Lignite Based Power Project at Akrimota in Kachchh district throughGMDC.

3 x 125 MW Pit Head Lignite Based Power Project at Ghogha in Bhavnagar district through(Reliance Industries Limited) RIL

615 MW Dual Fuel Based Power Project at Kovaya in Amreli district through KRIBHCO.

The above data indicates that addition in capacity in the State based on lignite is increasing. Gas usedin the state of Gujarat is increasing but simultaneously other fuel used is also increasing.

Generation cost of power with coal and or lignite is lower as compared with use of Natural Gas

as per details given below for Power Plants of Gujarat.

The cost of coal in Gujarat is Rs 2193 per MT for D Grade coal of Useful Heat Value of 4608 Kcal /Kg. The cost of energy is working out 2101 Kcal / Rs and fuel cost of power as Rs 1.14 per unit (Heat Rate 2400 Kcal / kwh ).

Generation cost (Rs./kwh) basedon coal

Plant

GSECL Gandhinagar Unit 5 GSECL Wanakbori Unit 7

2000-01 1.33 1.33

2001-02 1.33 1.35

Source: Case No. 252/ 2003, Before the Gujarat Electricity Regulatory Commission at Ahmedabad

At the time of signing of contract with Gujarat Gas, the company analyzed historical purchase dataof Naphtha procurement cost (procured from Reliance Petroleum Ltd and Indian Oil CorporationLtd) and it was observed that the operation of Power Plant on Naphtha is slightly cheaper ascompared to Natural Gas from Gujarat Gas. The average landed cost of Naphtha from the plant data

is calculated as Rs.9779/- MT at UPL Plant.6

. The feedback available to the company and Gas

5 www.gujaratindia.com/Useful-Info/ Socio%20Economic%20Review/ser03/serp2-5.pdf

6 Reliance Petroleum Ltd and Indian Oil Corporation Ltd Invoice


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Purchase Agreement from Gujarat Gas7 shows that the gas price will be approx. US$ 3.773 / 1000SCF at 8350 Kcal / SM3 calorific value, and the landed cost after adding for transportation and taxetc. would be approximately Rs.5.07 USD per mmbtu. Based on the above information, thegeneration costs with each fuel as assessed at the time of Gas contract agreement is as mentioned

below.

Price for naphtha will be (9779*0.252*1000000)/(10580*1000) = Rs 232.92 per mmbtuPrice for NG- Supply (3.773*0.03531*0.252*1000000)/8350 = 4.02 USD- Tax 0.01 USD- Transport (1.70*1000000*0.252)/(8350*49.05) = 1.05 USD

- Total 5.08 USD per mmbtu = 5.07*49 = Rs 249 per mmbtuFuel cost on naphtha = (1900*232.92)/1000000*0.252) = Rs 1.756 per unitFuel cost on NG = (1900*249)/(1000000*0.252) = Rs 1.88 per unit(Annex X:Naphtha NCV), (Annex XI: Exchange rate 1 USD=INR 49.05)

Thus cost of fuel per energy at the time of signing of contract, i.e. in 2001 was the lowest for Coal /

Lignite, followed by Naphtha and highest on Natural Gas.

The facility would not have major efficiency improvements during the crediting period;

The project activity is a fuel switch project. There is minor efficiency difference between Naphthaand natural gas combustion, as in the case of fuel switch for combustion. This difference cannot beconsidered as a major efficiency improvement.

Due to the switch to Natural gas, there is no increase in the capacity of the final output at UnitedPhosphorous Limited and lifetime of the existing facility during the crediting period

The capacity of LM 6000 gas turbine does not vary with change of fuel (naphtha to natural gas) Therated capacity before fuel switch was 41.80 MW and even after switch also it remains same (Source:General Electric catalogue). The project activity involved modification of existing equipmentstherefore there is no increase in the capacity of the final output.

The Switch from Naphtha to Natural gas does not result in any kind of the process change.This project activity has not resulted in any process change.

B.2. Description of how the methodology is applied in the context of the project activity:

The basic assumption of the baseline methodology is that in the absence of the project activities Naphthaand HSD would have otherwise been continued to be used in the existing facility at least up to the end ofthe crediting period without any retrofit, which extends its capacity or lifetime, or improve its fuelefficiency. The methodology as proposed by AM0008 has been applied to this project activity.

As per the methodology the parameters (variable) Q_Fi,y in the baseline emissions formula are calculatedas specified in the project scenario section by using parameters monitored ex ante or ex post.

7 15th October 2001, Gas Purchase Agreement between Gujurat Gas Company Limited and Search Chem IndustriesLimited


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Quantity of fuel used in the baseline scenario in the baseline emissions of this project activity, iscalculated expost from the quantum of Natural gas used (keeping the efficiency rate constant in the caseof Naphtha and Natural Gas being used for Power Generation)

The approved methodology AM0008 is used to calculate the baseline emission from Naphtha and HSDconsumption data during the period of October 1998 to September 2001and Natural Gas consumptionduring the project activity scenario. Methane and Nitrous Oxide produced in the combustion are estimatedusing the International Panel on Climate Change (IPCC) standard emission factors for each fuel. The totalCO2e emissions associated with Naphtha and HSD is calculated by the same Naphtha and HSDconsumption estimates from the Natural gas consumption during the project activity period.

The methodology is used to calculate the CO2 emissions from the project activity by estimating theconsumption of Natural Gas and its (Net Calorific Value) NCV value. It also takes into account theoverall CH4 and N2O emissions from the project activity.

The Baseline CO2 and project activity CO2 emissions are made up of carbon dioxide emissions fromcombustion, methane and nitrous oxide emission from combustion, and fugitive methane emissions

associated with Natural gas production, transport and distribution.

The emission reduction is calculated by subtracting the project activity emissions and leakages from thebaseline emission.

Carbon dioxide emissions are determined from standard IPCC emissions factors .

Methane and nitrous oxide produced in the combustion are estimated using IPCC standard emissionfactors for each fuel.

Fugitive emissions from natural gas production and transportation and distribution are also obtained fromregion specific emissions factors given by IPCC.

Total Methane emissions from combustion and fugitive emissions, are converted to equivalent CO2emission using the (Global Warming Potential) GWP of 21 as agreed on the First commitment period ofKyoto Protocol.

Similarly, nitrous oxide emissions are converted to equivalent CO2 emissions using the GWP of 310 asagreed on the First commitment period of Kyoto Protocol.

In order to calculate the baseline emissions, the following steps have been adopted:

Step 1. As per the methodology the parameters (variable) Q_Fi,y in the baseline emissions formula arecalculated as specified in the project scenario section by using parameters monitored ex ante or ex post.

Quantity of fuel used in the baseline scenario in the baseline emissions of this project activity, iscalculated expost from the quantum of Natural gas used.

Step 2. The emission factors for CO2, CH4 and N2O (that could be emitted from burning of fuels in thebaseline scenario) has been calculated.

Step 3. The total equivalent t CO2 emission is calculated.


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The baseline CO2, CH4 and N2O have been calculated by using IPCC factors.

The leakages have been estimated due to production of fuel using IPCC factor.

The additionality has been established as given in B.3. below.

Variable Data Source

Q_NGy = quantity of natural gas used (Joules) Power plant record, Natural Gas Supplier records

. _NG = fuel efficiency of natural gas Calculated from monitored variable

Q_F1,y = quantity of HSD used mass unit of HSDconsumed

Power plant record, Supplier records

Q_F2,y = mass unit of Naphtha consumed Power plant record, Supplier records

_HSD & Na Calculated from monitored variable

Parameter Data Source

EFNG =Carbon emissions factor per unit of energyof the Natural Gas

Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-2

EFHSD =Carbon emissions factor per unit of energyof the HSD


EFNa =Carbon emissions factor per unit of energyof the Naphtha


OXIDNG =Oxidation factor of the fuel Natural Gas(%)


OXIDHSD =Oxidation factor of the fuel HSD (%) Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-4

OXIDNa =Oxidation factor of the fuel Naphtha (%) Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-4

B.3. Description of how the anthropogenic emissions of GHG by sources are reduced belowthose that would have occurred in the absence of the registered CDM project activity:

The approved methodologys additionality assessment relates to the following

The local regulations/programs do not constrain the facility from using coal/petroleum fuels;

Use of coal and/or petroleum fuels is less expensive than natural gas per unit of energy in thecountry and sector

Since India has no regulation, which requires a manufacturing unit to switch the industrial fuel currentlybeing used to natural gas from Coal and/ or petroleum fuel, it can be clearly demonstrated that UPL is notconstrained by the local regulations from using coal/petroleum fuels and hence switch to Natural gas isadditional. Further to this, use of coal is less expensive than natural gas per unit of energy generation inthe country and sector.

In the absence of project activity, naphtha would have continued to be used as fuel for generation ofelectricity at the power plant. Since, naphtha is more Greenhouse Gas (GHG) intensive than natural gas,by switching over to the new fuel, emission reductions has occurred.


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This project activity will be defined as additional8 if anthropogenic emissions of GHGs by sources arereduced below those that would have occurred in the absence of the registered Clean DevelopmentMechanism (CDM) project activity. Within the scope of the adopted new baseline methodology,additionality has been demonstrated using the following points:

Additionality relates to the first and the second applicability conditions of the method.To assess the first condition, the project participants shall demonstrate that there are no localregulations/programmes constraining the use of coal/petroleum fuels.The methodology requires that trends in coal and natural gas consumption in the country/region andsector shall be analyzed and reported.The economic investment analysis shall use net present value (NPV) analysis. The project is additional ifthe NPV of the project activity is negative.

Additionality relates to the first and the second applicability conditions of the method.

Since India has no regulation, which requires a manufacturing unit to switch the industrial fuel currentlybeing used to natural gas from Coal and/ or petroleum fuel. The Indian Electricity Act of 2003 does not

restrict or empower any authority to the fuel choice for power generation. There are no environmentalregulations in India and Gujarat state preventing the use of naphtha/petroleum fuel/ coal or promoting theuse of natural gas for power generation. It can be clearly demonstrated that UPL is not constrained by thelocal regulations from using coal/petroleum fuels and hence switch to Natural gas is additional.

The additionality relates to the second applicability conditions have been described in section B1.1.

The availability of Natural Gas in the country is lower than the demand in the country and same is thescenario in the State of Gujarat. The demand of Gas in the State of Gujarat is higher due to variousindustrialization steps taken by the State Government. Though numbers of steps have been taken forincreasing the supplies of Gas but the demand has increased by manifolds. Some of the Power Plants inthe State are still lying idle in spite of development of new fields like GSPC at Hazira, setting-up of R-LNG Terminal at Dahej. There is a recent article on the availability of Natural Gas, which explains that

the Natural Gas availability in Gujarat is not there9. The article quotes Mr. R.V. Shahi, Secretary ofPower, Government of India that there is no availability in both domestically as well as imported in theform of (Liquefied Natural Gas) LNG and Power Plants in Gujarat like (National Thermal PowerCorporation) NTPC, Kawas and Gandhar, Torrent Power will have to starve for Natural Gas. It further,says that 2000 MW power capacity at an investment of Rs.8000 crores may have to go slow.

The fuel consumption figure for Gujarat state for different fuels in the power generation from the year2000 to 2004 are as follows:

Fuel Units 2003-2004 2002-2003 2001-2002 2000-2001

Coal 000' MT 15856 19298 16722 15940

Lignite 000' MT 2560 1931 1107 1144 Naphtha Kilo Ltrs 405808 426280 139937 469945

Natural Gas M. Cu.Mts. 1574 851 538 847

8 As per 17/cp.7

9 Gas , coal shortage fuels power shock in The Economic Times, Mumbai Edition dated 2nd December 2005


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Source: Table number 6.1, General Review 2000-2001, 2001-2002, 2002-2003, 2003-2004; Central ElectricityAuthority

Consumption of Coal, Lignite, Naphtha, Natural Gas for Electricty Generation in Gujurat

0

5000

10000

15000

20000

25000

2003-2004 2002-2003 2001-2002 2000-2001

Year

Quantity

Coal 000' MT

Lignite 000' MT

Naphtha 000' Kilo Ltrs

Natural Gas M. Cu.Mts.

The economic investment analysis use net present value (NPV) analysis. The project is additional ifthe NPV of the project activity is negative.

Investment requirements for fuel switching;Converting from Naphtha to Natural gas required UPL huge investments in new equipments as well asinfrastructure that would enable the shipping of the fuel at the plant site, installing meters and regulatorsetc. The total investment for the project activity is valued at INR 187.4 million. It includes cost ofconversion, hardware, LC and other charges, installation, transportation cost.

A discount rate appropriate to the country and sector;A discount rate appropriate to the country and sector has been considered to be 10%. However differentNPV analysis was done with a range of discount rate (10%-15%) to evaluate its outcome.

Efficiency of each fuel using equipment, with the baseline fuel and with natural gas;

The project activity is a fuel switch project. There is minor efficiency difference between Naphtha andnatural gas combustion, as in the case of fuel switch for combustion. This difference cannot be consideredas a major efficiency improvement.

Current price and projected price (variable costs) of each fuel;


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At the time of signing of contract with Gujarat Gas, the company analyzed 36 months purchase data ofNaphtha procurement cost (procured from IOC and RIL) and it was observed that the operation of PowerPlant on Naphtha is slightly cheaper as compared to Natural Gas from Gujarat Gas. The average cost ofNaphtha for the period Jan 1998 to Jan 2001 is Rs.9779/- PMT landed at UPL Plant. (Plant source and

IOL and RIL invoice) The feedback available to the company and Gas Purchase Agreement from GujaratGas shows that the gas price will be approx. US$ 3.773 / 1000 SCF at 8350 Kcal / SM3 calorific value,and the landed cost after adding for transportation and tax etc. would be approximately Rs.5.08 USD permmbtu. Based on the above information, the generation costs with each fuel as assessed at the time of Gascontract agreement is as mentioned below

Price for naphtha will be (9779*0.252*1000000)/(10580*1000) = Rs 232.92 per mmbtuPrice for NG- Supply (3.773*0.03531*0.252*1000000)/8350 = 4.02 USD- Tax 0.01 USD- Transport (1.70*1000000*0.252)/(8350*49.05) = 1.05 USD

- Total 5.08 USD per mmbtu = 5.07*49 = Rs 249 per mmbtuFuel cost on naphtha = (1900*232.92)/1000000*0.252) = Rs 1.756 per unit

Fuel cost on NG = (1900*249)/(1000000*0.252) = Rs 1.88 per unit

Price of fuel: The price of the fuel is based on global rather than a regional framework, given the globalinterdependence of energy markets. Price stability or volatility of the fuels will be felt by global marketsimultaneously. Considering the market variability about the petroleum products the trend for both theproduct was assumed to be same. Therefore, we have taken a constant price for the product during the lifetime of the project activity. The price of fuel during the inception of the project activity was Naphtha INR232.92 per mmbtu, Natural Gas 249 per mmbtu.

Difference in operating costs for each fuel (especially, handling/treatment costs for coal);There will be no major change in operating cost because naphtha is delivered by tankers and this cost hasbeen already included in the cost of naphtha. Natural Gas is billed at the delivery point.

Lifetime of the project, equal to the remaining lifetime of the existing equipment(s); and 15 years

Equipment replacement costs if any during the project lifetime.In case of natural gas hot section has to be replaced after 25000 hours and in case of naphtha hot sectionhas to be replaced after 12500 hours. However, as a conservative approach we have not considered thereplacement cost difference in the NPV calculations. (Source:plant)

The financial analysis conducted at the time of the project development and implementation, in 2002,showed the economic infeasibility of the initiative. Converting from Naphtha to Natural gas required UPLhuge investments in new equipments as well as infrastructure that would enable the shipping of the fuel atthe plant site, installing meters and regulators etc. The additional investments and anticipated businessdiscontinuity losses for switch over to natural gas implied that the project would not be cost effective.

NPV is calculated considering the investment and operational expenses including the cost of opportunitylosses that UPL incurred during the fuel switch activity. It is important to understand the figures wereestimated considering projections carried out by UPL at the time the project was being considered.Analysis carried out to assess the attractiveness and the feasibility also includes the residual value of thenew equipment, as required by the methodology. The analysis shows it was not an attractive investment.Without the expectation of this project being a CDM, the investment would not have happened. Creditsfrom GHG emission reductions were envisaged to reduce the deficit.


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The net present value of the investment into the project activity is estimated as negative.Alternative 1: Including the cost of opportunity losses that incurred during the shut down period of theplant

Discount

rate

10% 11% 12% 13% 14% 15%

NPV

(without

CER)

(951.76) (939.95) (929.14) (919.23) (910.12) (901.74)

NPV (with

CER)

(828.64) (823.55) (818.90) (814.63) (810.70) (807.09)

Alternative 2: Excluding the cost of opportunity losses that incurred during the shut down period of the

plant

Discount

rate

10% 11% 12% 13% 14% 15%

NPV

(without

CER)

(403.74) (391.93) (381.12) (371.21) (362.11) (353.72)

NPV (with

CER)

(280.63) (275.54) (270.88) (266.61) (262.68) (259.07)

NPV analysis with both the alternative scenarios has given a negative NPV results. However, the revenuehas substantially increased with CERs revenue. The investment cost and revenue loss towards the fuelswitch are offset in part by revenue earning from carbon credits that expand revenue earning that helps tooffset an investment barrier to project implementation.

The emission reductions are going to be achieved through the use of cleaner fuel, natural gas, instead ofone whose combustion is associated with higher emission factors, as put before. And since theequipments in use lead to nearly the same efficiency in fuel use for energy generation, natural gasgreenhouse gas emissions are lower than those accoutring when naphtha is used. As such a fuel shiftwould not have occurred during normal business course, the project activity reduces emissions belowthose that would have occurred in the absence of registered CDM project activity.

B.4. Description of how the definition of the project boundary related to the baseline

methodology selected is applied to the project activity:

For the purpose of this analysis, the project boundary encompasses the physical, geographical site of theplant. Schematically the figure shows the project boundary, indicating energy flows into the boundaryand fugitive methane emissions associated with natural gas.


17/37




Figure

B.5. Details of baseline information, including the date of completion of the baseline study and

the name of person (s)/entity (ies) determining the baseline:

The draft PDD with baseline study was completed on 01/10/2005.Baseline is calculated as mentioned under section E:

Date of completing the final draft of this baseline section (DD/MM/YYYY):28/03/2006Name of person/entity determining the baseline: PricewaterhouseCoopers (P) Limited has assisted theproject proponent in determining the application of baseline methodology for the identified CDM project.

Organization: PricewaterhouseCoopers (P) Ltd.

Street/P.O.Box: 252, Veer Savarkar Marg,Shivaji Park, (Opp. Shivaji ParkMaidan,Next to Mayor's Bungalow)

Building: 3rd Floor, A Wing

City: Dadar (W), Mumbai

State/Region: Maharastra

Postcode/ZIP: 400 028.

Country: India

Telephone: + 9122 5669 1500 (Board), + 9122 5669 1302 (Direct)

FAX: + 9122 5654 7804 / 05

E-Mail:

URL: ..

Represented by:

Title: Associate Director

Salutation: Mr.

Last Name: Ram Babu

Middle Name:

First Name: P

Department: Sustainable Business Solutions

Mobile: +91-9820135929

Boilers that are part of processcycle generating Power

Co2 emissions from the

transport of Naphtha

Naptha. HSD

Emissions of Co2,CH4 and N2O fromfuel combustion

Fugitive methaneemission from naturalgas production,pipeline and

distribution leakage

Natural Gas


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Direct FAX: +91-22-24913417

Direct tel: +91-22-56619341

Personal E-Mail: ...

PWC is not a project participant as meant in Annex I.

SECTION C. Duration of the project activity / Crediting period

C.1 Duration of the project activity:

C.1.1. Starting date of the project activity:

The commercial operation had commenced on 01/06/2002, which is taken to be the starting date of theProject Activity.

C.1.2. Expected operational lifetime of the project activity:

The project activity is expected to be operational for a period 15 years from the date of commencement ofoperations.

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:

10 years

C.2.2.1. Starting date:

01/06/2002

C.2.2.2. Length:

10 Years 0 months


19/37


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D.2. 1. Option 1: Monitoring of the emissions in the project scenario and the baseline scenario

D.2.1.1. Data to be collected in order to monitor emissions from the project activity, and how

ID number

(Please use

numbers to ease

cross-

referencing to

D.3)

Data

variable

Source of

data

Data unit Measured

(m),calculated(c) orestimated(e)

Recording

frequency

Proportion

of data tobemonitored

How will

the data bearchived?(electronic/paper)

Fois adat

1.Q_NGy Quantity ofnatural gasused

Apex ControlSystem,Power plant

records

TJ m Continuous/ Monthly

100% Electronic Pro

D.2.1.2. Description of formulae used to estimate project emissions (for each gas, source, form

equ.)

Project emissions are estimated considering the different fuels and efficiencies in their use in both the baseline andthe following formulae are used to estimate project emissions:

PEy= (iQi_NGy)*(EF_NG + FC_NG_CH4* GWP_CH4 + FC_NG_N2O* GWP_N2O)

Where:Qi_NGy = Are quantity of natural gas used in project scenario for replacing Q_Fi,y quantity of fuel i used in the ba

(e.g Joule or Kcal)

Q_NGy = (iQi_NGy) = Are the total quantity of natural gas in the project scenario for replacing all quantity of fubaseline scenario

EF_NG = Are the IPCC default CH4 emission factor of natural gas associated with fuel combustion (e.g. t CO2/TJ)


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FC_NG_CH4 = Are IPCC default Ch4 emission factor of natural gas associated with fuel combustion, measured in

FC_NG_N2O = Are IPCC default N2O emission factor of natural gas associated with fuel combustion, measured in

D.2.1.3. Relevant data necessary for determining the baseline of anthropogenic emissions by

boundary and how such data will be collected and archived :

ID number

(Please use

numbers to ease

cross-

referencing to

D.3)

Datavariable

Source ofdata

Data unit Measured(m),calculated

(c) orestimated

(e)

Recordingfrequency

Proportionof data tobe

monitored

How willthe data bearchived?

(electronic/paper)

Foris adat

2. Q_F1,y Quantity ofHSD used

Power plantrecords

TJ

C

Monthly 100% Electronic Proj

3.Q_F2,y Quantity ofNaphthaused

Power plantrecords

TJ C Monthly 100% Electronic Proj

4._NG FuelEfficiencyof naturalgas used atprocess

Calculatedfrommonitoredvariable

%C

Once atthe earlystage ofthe project

100% Electronic/paper

Proj

5._HSD & Na FuelEfficiencyof Naphthaand HSD

Calculatedfrommonitoredvariable

%

C

Oncebeforefuelswitch to

Naturalgas

100% Electronic/paper

Proj

6. L_Factorn Load factorat the powerplant

Power plantrecords

% M

-- 100% Electronic/paper

7.L_Regy Localregulation

or

Legaldocuments or

laws

--checked

At therenewal of

crediting

100% Electronic/paper Pro


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D.2.1.3. Relevant data necessary for determining the baseline of anthropogenic emissions by

boundary and how such data will be collected and archived :

ID number

(Please use

numbers to ease

cross-

referencing to

D.3)

Datavariable

Source ofdata

Data unit Measured(m),calculated(c) or

estimated(e)

Recordingfrequency

Proportionof data tobemonitored

How willthe data bearchived?(electronic/

paper)

Foris adat

constraintsin using

naptha andotherpetroleumfuel

period

D.2.1.4. Description of formulae used to estimate baseline emissions (for each gas, source, for

equ.)

The variables in the baseline emissions (Q_Fi,y) and the project emissions (Q_NGy) are linked with the constraint r

(Q_F1,y+ Q_F2,y) * _HSD & Na= Q_NGy* _NG

Similar to what is going to be carried out for project emissions estimate, the baseline methodology presents the follo

BEy= iQ _ Fi,y*(EF_ Fi _CO2y+ FC_Fi_CH4* GWP_CH4 + FC_Fi_N2O* GWP_N2O)

Where:i : 1=HSD,2=NaQ_Fiy Are quantity of Naptha used in Baseline scenario, measured in energy units (e.g. Joule)

EF_ Fi are CO2 equivalent emission factor per unit of energy of fuel i (e.g. t CO2/TJ)


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EF_NG are the IPCC default CH4 emission factor of natural gas associated with fuel combustion (e.g. t CO2/TJ)

FC_Fi_CH4 are IPCC default CH4 emission factor of Fuel i associated with fuel combustion, measured in t CH4/TJ

FC_Fi_N2O are IPCC default N2O emission factor of natural gas associated with fuel combustion, measured in t CH

GWP_CH4 is the global warming potential set as 21 for the first commitment year

GWP_N2O is the global warming potential set as 310 for the first commitment year

D. 2.2. Option 2: Direct monitoring of emission reductions from the project activity (values should b

Not opted for.

D.2.2.1. Data to be collected in order to monitor emissions from the project activity, and how

ID number(Please use

numbers to

ease cross-

referencing

to table

D.3)

Datavariable

Source ofdata

Dataunit

Measured (m),calculated (c),estimated (e),

RecordingFrequency

Proportionof data to

bemonitored

How will the databe archived?

(electronic/paper)

NA

D.2.2.2. Description of formulae used to calculate project emissions (for each gas, source, forequ.):

Not applicable.


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D.2.3. Treatment of leakage in the monitoring plan

D.2.3.1. If applicable, please describe the data and information that will be collected in orderproject activity

ID number(Please use

numbers to

ease cross-

referencin

g to table

D.3)

Datavariable

Source ofdata

Dataunit

Measured (m),calculated (c)or estimated (e)

RecordingFrequency

Proportionof data tobemonitored

How will the databe archived?(electronic/paper)

Commen

In the ca

data is t

monitor

Conside

tables Dno need

D.2.3.2. Description of formulae used to estimate leakage (for each gas, source, formulae/algo

LEy= [Q_NGy * FE_NG_CH4 - i(Q _ Fi,y * FE_Fi_CH4) ] * GWP _CH4

FE_NG_CH4 are IPCC default CH4 emission factor of Natural gas associated with methane fugitive emissions, mea

FE_Fi_CH4 are IPCC default CH4 emission factor of Naphtha associated with methane fugitive emissions, measure

FE_NG_CH4= 118 kgCH4/TJ = 0.118 tCH4/TJ, as presented in the Revised 1996 IPCC Guidelines for National Reference Manual, Section 1.8.5, Table 1-58, Natural gas processing, transport and distribution.FE_FO_CH4 = 0. Fugitive emissions of CH4 associated with fuel oil production and transportation will be consideCH4 emission factors for the production of Naphtha &HSD fuel oil. This is conservative.EF_TF_NG andEF_TF_FO are CO2 emission factors for the transportation of Natural gas and HSD and Naphtha.


25/37




EF_TF_NG = 0. Natural gas is transported through pipelines; hence no emissions of CO2 are attributed due to itsare considered in FE_NG_CH4.

EF_TF_FO = 0. Fuel oil would be transported through trucks in the baseline and emissions of CO2 would occurthese emissions will not be considered. This is conservative.LE= Q_ NG Q*0.118*21 =2.48*Q_NG [tCO2]

D.2.4. Description of formulae used to estimate emission reductions for the project activity (for each

emissions units of CO2 equ.)

Emission reductions for the project activity are determined considering baseline emissions minus project emissionsreductions can be determined as

Er = BEy PEy- LEy

The variables in the baseline emissions (QE_LFy) and the project emissions (QE_GFy) are linked with the energy e

QE_LFy * LFy = QE_GFy * GFy

Here LFy and GFy are fuel efficiencies for use of liquid and gaseous fuels, respectively, and ensures a checefficiencies are not changed due to use of the new fuel.

D.3. Quality control (QC) and quality assurance (QA) procedures are being undertaken for data monitore

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 pro

1-6 Low These data will be directly used for calculation of emission reductiobe as per the procedures under ISO 9002 certified Quality Manag

7 Low This is to check that the applicability condition is met. Informationof Government of India and state govt of Gujurat


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D.4 Please describe the operational and management structure that the project operator will implement i

and any leakage effects, generated by the project activity

The project will be operated and managed by UPL who is also the project proponent. . The site also has an ISO 9Accordingly, the monitoring plan proposed herein will become an integral part of the project Management Poperational and management structure of this Quality Management System (QMS).

In order to monitor and control boilers performance, UPL has placed a project management team. They are co-ordiresponsible for checking the information consistency.

These operators are responsible for managing the computer system, which are utilised to collect data, whimeasurements are carried out electronically. Measuring steam pressure continuously, according to the process dema

The Instrumentation and the control system for the project activity are designed with adequate instruments to conparameters for safe and efficient operations. All the instruments are of reputed make and are calibrated at regular in

Designation Responsibilities

Project Head: Registration

Project Executer and Controller:Project Execution and Operation

Site Main Controller Monitoring & Verification ofdata (once in a week), Operation

Controller : Monitoring & Verification ofdata (once in a day), Operation,Power generation

Maintenance Engineer Mechanical Maintenance,Energy Input meter monitoring& Maintenance , Energy outputmeters

Operation Engineer (one in ashift)

Monitoring of data collection(once in every day), Operation,Power generation, Data


27/37




collection ,Checking dataaccuracy ,Data recording

D.5 Name of person/entity determining the monitoring methodology:

The draft PDD monitoring section study was completed on 01/10/2005.

The final draft of this monitoring section was completed on (DD/MM/YYYY): 28/03/2006

PricewaterhouseCoopers (P) Limited has assisted the project proponent in determining the monitoring methodology


28/37




SECTION E. Estimation of GHG emissions by sources

E.1. Estimate of GHG emissions by sources:

PEy= (iQi_NGy)*(EF_NG + FC_NG+FC_NG_CH4* GWP_CH4 + FC_NG_N2O* GWP_N2O)

The GHG emissions (CO2) due to the project activity will result from burning of Natural gas. The annualproject emission is given below in tCO2.

YearProject Emissions(PEy)

Jun 02- Dec 02 81866

Jan 03-Dec 03 133500

Jan 04-Dec 04 139548

Jan 05-Dec 05 137386

Jan 06-Dec 06 137386Jan 07-Dec 07 137386

Jan 08-Dec 08 137386

Jan 09-Dec 09 137386

Jan 10-Dec 10 137386

Jan 11-Dec 11 137386

Jan 12-May 12 57244

For the year 2002 the calculation is based on the data from June- December. For the year 2012 thecalculation is based on data from the month of January May. For other year the Calculation is based onJanuary December. This is applicable to all the emission calculations.

E.2. Estimated leakage:

Year Leakage (LEy)

Jun 02- Dec 02 3634

Jan 03-Dec 03 5926

Jan 04-Dec 04 6194

Jan 05-Dec 05 6098

Jan 06-Dec 06 6098

Jan 07-Dec 07 6098

Jan 08-Dec 08 6098

Jan 09-Dec 09 6098

Jan 10-Dec 10 6098Jan 11-Dec 11 6098

Jan 12-May 12 2541

E.3. The sum of E.1 and E.2 representing the project activity emissions:


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The total project emissions during

Year

Total Project

Emissions (PEy+LEy)t CO2

Jun 02- Dec 02 85500

Jan 03-Dec 03 139425

Jan 04-Dec 04 145742

Jan 05-Dec 05 143484

Jan 06-Dec 06 143484

Jan 07-Dec 07 143484

Jan 08-Dec 08 143484

Jan 09-Dec 09 143484

Jan 10-Dec 10 143484

Jan 11-Dec 11 143484Jan 12-May 12 59785

E.4. Estimated anthropogenic emissions by sources of greenhouse gases of the baseline:

The GHG emissions (CO2) in the baseline is

YearTotal Baseline

Emissions (BE y)t CO2

Jun 02- Dec 02 118740Jan 03-Dec 03 193630

Jan 04-Dec 04 202403

Jan 05-Dec 05 199267

Jan 06-Dec 06 199267

Jan 07-Dec 07 199267

Jan 08-Dec 08 199267

Jan 09-Dec 09 199267

Jan 10-Dec 10 199267

Jan 11-Dec 11 199267

Jan 12-May 12 83028

E.5. Difference between E.4 and E.3 representing the emission reductions of the project activity:

The total emission reduction during 2002 2012 will be 557826tCO2 equiv.


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E.6. Table providing values obtained when applying formulae above:

Year

Estimation ofProject activity

EmissionReductions (tonesof CO2e)

Estimation of

BaselineEmissions(tones ofCO2e)

Estimation ofleakage (tones ofCO2e)

Estimation ofemission reduction(tones of CO2e)

t CO2 e t CO2 e t CO2 e t CO2 e

Jun 02- Dec 02 85500 118740 3634 33240

Jan 03-Dec 03 139425 193630 5926 54205

Jan 04-Dec 04 145742 202403 6194 56660

Jan 05-Dec 05 143484 199267 6098 55783

Jan 06-Dec 06 143484 199267 6098 55783

Jan 07-Dec 07 143484 199267 6098 55783

Jan 08-Dec 08 143484 199267 6098 55783

Jan 09-Dec 09 143484 199267 6098 55783

Jan 10-Dec 10 143484 199267 6098 55783

Jan 11-Dec 11 143484 199267 6098 55783

Jan 12- May 12 59785 83028 2541 23243

Total (tonnes ofCO2 e) 1434845 1992671 60982 557826

SECTION F. Environmental impacts

F.1. Documentation on the analysis of the environmental impacts, including transboundary

impacts:

The Environmental Impact Assessment is not required by the Environmental Impact Assessmentnotification under Environment Protection Act 1986 (Government of India) for the fuel switch project andhence not conducted as per the requirement of guidelines there under. This assessment is conducted forUPL, as a voluntary initiative to understand the impacts and mitigate any additional impacts that mayarise due to the proposed project activity. This project activity has received environmental clearance.

The environmental Impact Assessment study showed that overall environmental impacts are notsignificant. A summary of impacts is presented below:

Land use

There has no change in land use. The project activity is carried out inside the existing plant.

Water qualityThere will be no impact on water quality of local water source including the rivers. Previously, in thecase of Naphtha as primary fuel, for the centrifuge operation, the water requirement was 3 KL/day. Inthe current project scenario centrifuge is no longer required. This reduces the consumption of waterby 1000 KL/annum.


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Air qualityThe study shows that there is decrease in the gaseous emissions. The following is the change in thevarious emissions out of the project activity:

Gaseous Emissions at the Boiler stack:

Parameter Before (Naphtha)&HSD

After (Natural gas) Comments

Particulate Matter(mg/NM3)

BDL BDL Naphtha start up wason diesel and the startup in the project caseis on Natural Gas

SO2 ppm 1.5(32.4 KG/Day) BDL Diesel/Naphtha has0.25%/0.03% sulphurand the gas has only10 ppm sulphur

contentNOX ppm 26.5(380 KG/Day) 20-22 ppm The project activity

also expected to haveNOx control which ismanaged by waterinjection and this islikely to be moreeffective in the case ofgas

Liquid Effluent generation

The waste water characteristics have improved due to project activity as the oil and grease concentrationhas decreased as there is no centrifuging activity involved in natural gas operations like it was in naphthafor removal of impurities and sediments for which water was required.

Solid Waste Generation

Tank bottom sludge is not expected to be there in the case of Natural gas, in comparison to Naphtha. Inthe case of Natural gas, in comparison to Naphtha, the filter elements have more life. Accordingly, thesolid waste generation is expected to reduce in the case of Natural Gas.

Surface and Ground Water.

No impact on surface and groundwater sources was anticipated;

Flora and Fauna

No impacts of ecology flora and fauna, were expected.

Employment


32/37




There will be marginal decrease in employment, as the handling of Naphtha required labor and this is notrequired in the case of natural Gas.

F.2. If environmental impacts are considered significant by the project participants or the hostParty, 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:

This project activity has received environmental clearance and the environmental impacts are considerednot significant both by the host party and the project participants.As above analysis shows, no significant environmental impacts are expected from this project activity. Infact, only positive impacts are expected, such as better local air quality and GHG emission reductions.More over, reduction in Naphtha and HSD consumption means fewer hazards in transportation andproduction of the same.

Hence, in conclusion, the project does not cause any significant impacts on the environment in the region.

SECTION G. Stakeholders comments

G.1. Brief description how comments by local stakeholders have been invited and compiled:

The stakeholders for the project activity were identified at the outset by a team of UPL staff and thestakeholders were duly informed of the consultation meeting. In addition public notices were also issuedfor the local stakeholder consultation meeting. Local stakeholder consultation meeting to discussstakeholder concerns on the proposed Clean Development Mechanism (CDM) project - Industrial Fuelswitching from Naphtha to Natural gas without extension of capacity and lifetime of the facility at UnitedPhosphorus limited, was held at 03:00 p.m. on 3rd September 2005 atUnited Phosphorus Limited, GIDC,Jhagadia, Dist: -Bharuch, Gujurat State, India.

The meeting elected a chairman to conduct the further proceedings and finally chairman prepared thesummary record of the meeting and provided to UPL- copy of which will be made available toDesignated Operating Entity during validation process.

The local stakeholders appreciated the CDM initiatives and applauded the effort towards clean energy produced. The stakeholders viewed UPL as a reputed company contributing to local environmentalbenefits and socio-economy through such initiatives. Overall there was unanimous agreement that theproject activity was really a proactive initiative by the project party, which contributes, to the sustainabledevelopment.

G.2. Summary of the comments received:

Mr S C Mittal, Vice President, Shriram Alkalis & Chemicals appreciated the efforts made by the UPL andforward thinking they have done. He stressed the point that its a good effort and contributes clean powergeneration in the local level. He once again highlighted the role of the local stakeholders to articulate anyconcerns that they may have on the CDM project.


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Mr Amit Jethava, President, GIR Nature Youth Club, Gandhinagar congratulated UPL for their uniqueefforts. He mentioned this will set a good example for the local industry and they will replicate such kindof project in future

The specific concerns expressed by the participants are summarized below along with clarificationsprovided on such concerns:

Stakeholder concerns /

question / comment

Answer / clarifications

Environment

With changing of fuel, is yourrequirement of water andgeneration of wastewaterincreased or decreased?

The requirement of water decreases by about 1000 KL/Year due tothe project activity and accordingly the quantum of wastewater hasalso decreased. The waste water characteristics have also improveddue to project activity as the oil and grease concentration hasdecreased as there is no centrifuging activity involved in natural gasoperations like it was in naphtha for removal of impurities and

sediments for which water was required.When and what kind of publicinformation that was provided atthe time of shifting the fuel in2002?

At the time of changing the fuel the permissions under EnvironmentalProtection Act 1986, Water pollution Prevention and Control Act1974 and Air Pollution and Prevention and Control Act 1981 have been obtained and the public was provided due information asrequired under these acts and the Factory Act.

Economic

GGCL contract of gas is going toexpire in 2007, what is GGCL plan for extension of gasagreement?

The extension of gas contract is under discussion and the informationcannot further be divulged, as it is confidential.

The result of the stakeholder meet showed that the stakeholders were satisfied with the project activityand the concerns of the stakeholders are cleared with adequate information. The stakeholders appreciatedthe proactive approach done by UPL through such project implementation.

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

The stakeholders were provided clarifications on the issues raised as above to their satisfaction. None ofthe concerns expressed by the stakeholders required an action to be taken by the UPL during the projectoperation and at any other stage.


34/37




Annex 1

CONTACT INFORMATION ON PARTICIPANTS IN THE PROJECT ACTIVITY

Organization: United Phosphorus limitedStreet/P.O.Box: 750, G I D C Jhagadia

Building: --

City: Bharuch

State/Region: Gujarat

Postfix/ZIP: 393110

Country: India

Telephone: +91-2645 226011

FAX: +91-2645226017

E-Mail: [email protected]

URL: www.uplonline.com

Represented by: S. Krishnan

Title: Vice President - CommercialSalutation: Mr.

Last Name: Krishnan

Middle Name: --

First Name: S

Department: Commercial

Mobile: 91- 9821088709

Direct FAX: 91-022-26041010

Direct tel: 91-022-26488535

Personal E-Mail: [email protected]


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Annex 2

INFORMATION REGARDING PUBLIC FUNDING

This is a unilateral CDM Project Activity undertaken by the project proponent for which no publicfunding has been used.


36/37




Annex 3

BASELINE INFORMATION

Variable Data Source

Q_NGy = quantity of natural gas used (Joules) Power plant record, Natural Gas Supplier records

. _NG = fuel efficiency of natural gas Calculated from monitored variableQ_F1,y = quantity of HSD used mass unit of HSDconsumed

Power plant record, Supplier records

Q_F2,y = mass unit of Naphtha consumed Power plant record, Supplier records

_HSD & Na Calculated from monitored variable

Parameter Data Source

EFNG =Carbon emissions factor per unit of energyof the Natural Gas


EFHSD =Carbon emissions factor per unit of energyof the HSD


EFNa =Carbon emissions factor per unit of energyof the Naphtha


OXIDNG =Oxidation factor of the fuel Natural Gas(%) Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-4

OXIDHSD =Oxidation factor of the fuel HSD (%) Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-4

OXIDNa =Oxidation factor of the fuel Naphtha (%) Revised 1996 IPCC Guidelines for NationalGreenhouse Gas Inventories : Workbook Table 1-4

All baseline information is presented in Section B. Please, refer to that section.


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Annex 4

MONITORING PLAN

Sl. No. Variables Meter Meter locationFrequency

of reading

Reading & recording

responsibility

Location of reading

recording*

Frequency of

calibration/Veri

fication of

meters

Calibration /

Checking

Responsibility

Calibaration Agency

/ Ref: Standard

1 EGGEN GTG meter power plant control room Daily Shift In Charge SAP/ Daily generation once in 3/5 years

electrical

engineer/power

plant

Gujarat Electricity

Board /Electricity

ACT

2 EGAUXIncomer one PMCC

meterpower plant control room Dai ly Shift In Charge SAP/ Dai ly genera tion once in 3/5 years

electrical

engineer/power

plant

Gujarat Electricity

Board /Electricity

ACT

1 Q1 Custody Gas meter GTCL metering skid /

UPL siteDaily Shift In Charge

Gas Ticket / pp daily

generation/sap entryMonthly

Joint

caliberation by

Gujarat gas and

UPL

Gujarat Gas / AGA3

2 NCV Gas chromatograph Sampling Point / Amboli DailyGuj. Gas /amboli shift

incharge

Gas Ticket /

GTCL,suratBi-monthly

Gujarat

Gas/GTCLABB / ISO-6976

Monitoring and Verification Protocol for Energy Input and Energy Output

Energy Output

Energy Input

All other monitoring plan is presented in Section D. Please, refer to that section.

Registered PDD

Documents