consultant’s final report - asian development bank...consultant’s final report project no. 41139...

Consultant’s Final Report Project No. 41139 Final Report February 2012

TA 4992- IND: Energy Efficiency Enhancement in Power Generation Sector Prepared by Mr. PricewaterhouseCoopers Pvt. Limited, India

The Consultant’s final report is a document of a team of consultants led by PricewaterhouseCoopers Pvt. Limited, India. The views expressed herein do not necessarily represent those of ADB's Board of Directors, Management, or staff, and may be preliminary in nature. Your attention is directed to the “Terms of Use” section of this website.

ADB TA 4992 – IND

Energy Efficiency Enhancement in Power Generation Sector

Final Report

02 February, 2012

TA-4992-IND Final Report

Energy Efficiency Enhancement in Power Generation Sector Page 2 of 160

Contents

Executive Summary ....................................................................................................................................... 7

Finding in relation to project portfolio ....................................................................................................... 17

Selection of projects ................................................................................................................................. 17

Vijayawada TPS .................................................................................................................................. 19

Poringalkuthu HEP ............................................................................................................................. 19

Sholaya HEP ........................................................................................................................................ 19

Satpura TPS ......................................................................................................................................... 19

Guru Gobind Singh TPS ..................................................................................................................... 20

Machkund HEP ................................................................................................................................... 20

Giri HEP ............................................................................................................................................... 21

Umium HEP ........................................................................................................................................ 22

Koradi TPS .......................................................................................................................................... 23

Barriers to CDM development ............................................................................................................... 24

Residual life ......................................................................................................................................... 25

CDM consideration ............................................................................................................................. 25

Validation and registration cost ....................................................................................................... 25

Inadequate monitored data for setting baseline.............................................................................. 26

Capacity Building ........................................................................................................................................ 28

Requirements .......................................................................................................................................... 28

Outcome .................................................................................................................................................. 29

TA Progress and Near Term Opportunities .............................................................................................. 32

MOU between EA and IA ................................................................................................................... 32

Inception report .................................................................................................................................. 32

Diagnostic report ................................................................................................................................ 32

Workshops ........................................................................................................................................... 32

PDD preparation ................................................................................................................................ 32

Host country approval ....................................................................................................................... 32

Validator appointment ...................................................................................................................... 33

Webhosting of PDD ............................................................................................................................ 33

Near term opportunities: ........................................................................................................................ 33

Emission Trading Schemes ................................................................................................................ 33

Nationally Appropriate Mitigation Actions ..................................................................................... 35

National mission on enhanced energy efficiency (NMEEE) ........................................................... 35

Other category of CDM projects in power generation .................................................................... 36

Learning from the TA ............................................................................................................................. 39

Up-scaling emission reduction project activities in power sector ........................................................ 41

Capacity building through workshops and seminars ...................................................................... 41

Governance .......................................................................................................................................... 41

Prioritisation of projects ..................................................................................................................... 41



Alleviating barriers - Sale of CERs post 2012 .................................................................................. 42

Alleviating barriers – Cost of validation and registration ............................................................. 42

Annexure ..................................................................................................................................................... 44

Annexure 1: Final Webhosted PDD of MSPGCL ................................................................................... 45

Annexure 2: Presentation made to MSPGCL on stakeholder consultation process .......................... 112

Annexure 3: Presentation made to Indian DNA for Koradi TPS ........................................................ 117

Annexure 5: Presentation made to MeSEB on project specific issues ................................................ 139

Annexure 6: Presentation made to HPPCL on project specific issues ................................................ 144

Annexure 7: Presentation made to APGENCO and OHPC on project specific issues ....................... 149

Annexure 8: Workshops on Capacity building..................................................................................... 158



Abbreviations

ACM Approved Consolidated Methodology

APGENCO Andhra Pradesh Power Generation Corporation Limited

BVCL Bureau Veritas Certification

CDM Clean Development Mechanism

CER Certified Emission Reduction

CERPA Certified Emission Reduction Purchase Agreement

COP Conference of Parties

CPA CDM Project Activity

CPRI Central Power Research Institute

CRC Carbon Reduction Commitment

CVF Capital Venture Fund

CPSU Central Public Sector Utility

DCPL Development Consultants Private Limited

DNA Designated National Authority

DOE Designated Operational Entity

DPR Detailed Project Report

DSM Demand Side Management

EA Executing Agency

ECERT Energy Saving Certificate

EB Executive Board

EEFP Energy Efficiency Financing Platform

ERC Electricity Regulatory Commission

ERPA Emission Reduction Purchase Agreement

ERU Emission Reduction Units

EUETS European Union Emission Trading Scheme

FEEED Framework for Energy Efficient Economic Development

GDP Gross Domestic Product

GEF Global Environment Facility

GHG Green House Gas

GSECL Gujarat State Electricity Corporation Limited

HEP Hydro Electric Project

HPPCL Himachal Pradesh Power Corporation Limited

IA Implementing Agency

IEX Indian Energy Exchange

IPCC Intergovernmental Panel on Climate Change

IRR Internal Rate of Return

JI Joint Implementation

J&K Jammu and Kashmir

KPTCL Karnataka Power Transmission Corporation Limited

KSEB Karnataka State Electricity Board

LDC Least Developed Countries



MAHAGENCO Maharashtra State Power Generation Company Limited

MeSEB Meghalaya State Electricity Board (now Meghalaya Energy Corporation Limited)

MoEF Ministry of Environment and Forests

MoP Ministry of Power

MoU Memorandum of Understanding

MPPGCL Madhya Pradesh Power Generation Company Limited

MSEB Maharashtra State Electricity Board

MSPGCL Maharashtra State Power Generation Company Limited

MTEE Market Transformation for Energy Efficiency

MW Mega Watt

NAMA Nationally Appropriate Mitigation Action

NAPCC National Action Plan on Climate Change

NCDMA National CDM Authority

NMEEE National Mission on Enhanced Energy Efficiency

ODA Official Development Assistance

OHPC Orissa Hydro Power Corporation

PCN Project Concept Note

PDD Project Design Document

PFC Power Finance Corporation

PoA Programme of Activities

PRGF Partial Risk Guarantee Fund

PSEB Punjab State Electricity Board

PXIL Power Exchange India Limited

PwC PricewaterhouseCoopers

R & M Renovation and Modernisation

RLA Residual Life Assessment

SPCB State Pollution Control Board

TA Technical Assistance

TPS Thermal Power Station

UNFCCC United Nations Framework Convention on Climate Change

WBPDCL West Bengal Power Development Corporation



Executive Summary



Executive Summary

Introduction

(1) ADB TA 4992 - IND on Energy Efficiency Enhancement in Power Generation Sector was

executed through Power Finance Corporation (Executing Agency) with participation

from the state power generating utilities (Implementing Agencies) and assistance from

the TA consultant. The TA was instituted by the Asian Development Bank (ADB) to

provide assistance to the state power generating utilities in India for CDM development

of their Renovation and Modernization schemes in thermal and hydro power stations.

(2) PricewaterhouseCoopers Pvt. Ltd (PwC) was appointed as the TA consultants. The scope

of work assigned to PwC covered capacity building for the Implementing Agencies and

assisting the Implementing Agencies in CDM development of their R&M initiatives.

(3) The TA inception meeting was conducted on 24 July, 2008 involving representatives

from ADB, Executing Agency, PwC and participating Implementing Agencies.

(4) The inception report covered details of inception activities carried out including (i)

review of R&M in India, (ii) progress and current status of thermal and hydro R&M

projects in India, (iii) preparing the MoU to be executed between the Executing Agency

and Implementing Agencies, (iv) visits to the Implementing Agencies for collecting

information on the projects and performing preliminary review for the project activities,

(v) preparing the pipeline of clean energy projects and conducting CDM capacity building

workshop for Implementing Agencies.

(5) The first interim report describing the findings in relation to the project portfolio, status

of near-term opportunities and capacity building requirements was submitted on 24

January, 2009 to ADB.

(6) Second interim report covered details of activities carried out for the period between

January, 2009 and June, 2009 and was submitted to ADB on 29 June, 2009. At the time

of second interim report following key activities were completed:

Out of 9 selected projects during second interim, PDD for 8 projects were

completed. Out of 9 selected projects, PDD for Sholaya hydro project could not be

developed as remaining technical life of the project could not be established by

the study conducted by CPRI.

Review of DPR of 5 projects was completed

3 projects were submitted for host country approval to National CDM Authority

(NCDMA)

Discussions for financing validation cost were initiated with ADB carbon fund

Capacity building workshop was conducted for MSPGCL

Workshops with regard to stakeholder consultation process were conducted for

HPPCL and APGENCO.



(7) During the period between June 2009 and March 2011; the following activities were

completed:

Three projects received host country approval was from NCDMA

Appointment of DOE for 660 MW supercritical project of MSPGCL

Capacity building workshop was conducted for MSPGCL

Workshops with regard to stakeholder consultation process were conducted for

MSPGCL.

Workshops with regard to project specific issues were conducted for MSPGCL,

HPPCL and MeSEB.

(8) The deliverables submitted under the TA are provided in Table 1 below.

Table 1: TA milestones

S.No. Milestone Submission Date

1 Inception Report 20 August, 2008

2 Diagnostic Report 4 September, 2008

3 First Interim Report 24 January, 2009

4 Second Interim Report 29 June, 2009

5 Draft Final Report 14 October, 2011

Selection of projects

(9) The pipeline of 64 clean energy projects was identified in the inception report. PwC and

Executing Agency carried out a second round of visits to the Implementing Agencies for a

more detailed review of each and every project and assessing their CDM eligibility. A

diagnostic report was submitted on 4 September, 2008 which includes the key issues

involved in baseline, additionality and monitoring requirements for R & M projects.

Based on assessment made during the diagnostic study conducted by PwC, short-listed

projects were reduced to 13 to be taken up for CDM.

(10) In the subsequent stage, this list was further revised, as 5 projects were added and 9

short-listed projects had to be excluded. In total, 9 projects were taken for PDD

development in the second interim report.

(11) The scope of services under the TA contract did not include any services relating to host

country approval, arrangement of funds for validation expenses or appointment of

validator. At the request of implementation agencies, PwC took these additional

responsibilities as these were important requirements for accomplishment of the overall

TA objective.



(12) The 9 projects selected (Table 2 below) in second interim report for further consideration

were analysed in detail on aspects such as CDM consideration, remaining technical life of

the project activity, timeline for implementation, validation and registration cost,

statutory clearances, baseline data and additionality.

Table 2: List of potential CDM projects

Implementing Agency Power Station Capacity (MW)

1 Maharashtra State Power Generation Corporation Limited (MSPGCL)

Koradi TPS 660

2 Andhra Pradesh Power Generation Corporation Limited (APGENCO)

Machkund HEP 114.75

3 Meghalaya State Electricity Board (MeSEB)

Umiam HEP 60

4 Himachal State Power Corporation Limited (HPPCL)

Giri HEP 60

5 Kerala State Electricity Board (KSEB) Poringalkuthu HEP 32

6 Kerala State Electricity Board (KSEB) Sholaya HEP 54

7 Punjab State Electricity Board (PSEB) Guru Gobind Singh TPS 420

8 Andhra Pradesh Power Generation Corporation Limited (APGENCO)

Vijayawada TPS 420

9 Madhya Pradesh Power Generation Corporation Limited (MPPGCL)

Satpura TPS 830

(13) Two hydro projects selected in the state of Kerala were expected to be implemented in

12th period plan (2013 – 2018). Further, Detailed Project Reports for the project activities

did not explicitly state the remaining technical life for the project activity. Under the

CDM rules, the crediting period for the R&M project is limited to remaining useful life of

the project activity that can be established. In the absence of the documentary evidence

for remaining useful life of the project, the two hydro projects in the state of Kerala were

dropped.

(14) Satpura TPS and Guru Gobind Singh TPS were dropped on account of inadequate

historical monitoring data for setting baseline. Monitoring data for both the projects was

inadequate to establish the baseline for each of the units as the fuel measurement system

under both the projects was common to all the units. Therefore efficiency of each unit

considered for R&M could not be established and hence these projects could not be

considered further.

(15) The annual estimated CERs for Vijayawada TPS was 2,854. The cost benefit (cost of CDM

registration and CER issuance vs. revenue from CERs) did not show a positive cash flow.



Therefore Vijayawada TPS was also dropped for further consideration. Therefore out of

the 9 projects that were selected in the second interim report, 5 projects were dropped

after discussion with Executing Agency. Finally four projects were selected for further

development.

Figure 1: CDM project short list

(16) The Implementing Agencies raised their concern over validation and registration fee as

these were not covered under TA. We discussed several possibilities for financing the

validation expenses; two routes were explored to resolve the issue of validation and

registration fee.

Upfront finance from ADB carbon fund to cover up validation and registration fee

Application of contingency fund of TA towards validation and registration fee

(17) We provided the PDDs to the ADB Carbon fund, after which ADB carbon fund requested

for more information on the projects to carry out their due diligence. We assisted ADB

Carbon fund in their due diligence process; we carried out site visits and held discussions

with the Implementing Agencies and submitted the relevant information to ADB Carbon

Fund. We conducted a meeting at Delhi on 04 February, 2009 to explain the terms of

ADB Carbon fund and its benefits particularly in the context of CDM development of

their R&M projects.

(18) We also carried out a review of the CERPA submitted by ADB Carbon Fund and have

confirmed to Executing Agency that these terms are as per acceptable market practices

and that the CERPA signing process should be completed so that funds for meeting

validation expenses are available to the projects.

(19) One of the conditions laid by ADB Carbon Fund for upfront finance was the ability of the

project to generate CERs before 2012. The implementation of the projects under

consideration was expected to be delayed and likely to move to 12th plan period (2012 –

2017) and therefore these projects were unable to secure finance for validation and

registration from ADB Carbon Fund. Application of contingency amount of TA towards

validation was not approved by ADB.

64

13

9

4

0 10 20 30 40 50 60 70

Long List of projects

Shortlisted during Diagnostic

Shortlisted for PDD preparation

Final List

Number of Projects



PDD development

(20) Out 9 projects that were selected during the second interim report, PDD for 8 projects

were developed. The PDD for Sholaya hydro project could not be developed as

remaining technical life of the project could not be established by the study conducted by

CPRI.

Host country approval

(21) Giri HEP, Umium HEP and Machkund HEP were filed with NCMDA for host country

approval before second interim report. PwC assisted Implementing Agencies with the

presentation that was requested by NCMDA. During the meeting NCDMA requested

statutory clearances and minutes of stakeholder consultation from HPPCL

board resolution and stakeholder minutes from MeSEB

(22) The documents requested by NCMDA were submitted by HPPCL and MeSEB. Two

projects including Giri HEP and Umium HEP received host country approval from

NCDMA on 17 November, 2009.

(23) Machkund is an interstate project (between Andhra Pradesh and Orissa) and therefore

board resolutions were required from APGENCO and OHPC. Due to intergovernmental

issues surrounding the project, the board resolution from OHPC could not be submitted

to NCDMA within the stipulated deadline i.e. within six months from date of NCMDA

meeting and the project did not receive host country approval.

(24) Koradi TPS was submitted to NCDMA along with the supporting documents. Additional

documents were requested by NCDMA during the meeting which were submitted and

project received host country approval from NCDMA on 15 November, 2010.

Appointment of DoE

(25) As per communication received from HPPCL on 08 March, 2011, the Giri HEP was

pending consideration by their board and therefore the validator (Designated

Operational Entity) for this project could not be finalized.

(26) Machkund is an interstate project and there were issues in regard to sharing of the

validation fee between the project proponents amidst pending issues such as sharing of

electricity. APGENCO was in the process of appointing the independent third party

engineering consultant for preparing the scheme of works the results of which were

expected only by November, 2011. Due to delays in resolution of issues between state of

Orissa and state of Andhra Pradesh and unavailability of DPR by third party, the board

approval of the project was pending from OHPC. Therefore CDM process for this project

could not move forward beyond the PDD stage.

(27) MeSEB envisaged grant funding for Umium HEP. Under the CDM rules, additionality

has to be demonstrated by showing that the project revenues are not sufficient to meet

the capital and operating costs (and acceptable level of returns). Given the context of



grant financing, it is unlikely that the project would pass the additionality test. Therefore

the appointment of validator for the project activity was kept on hold by MeSEB.

(28) MSPGCL invited quotes from the DOEs for validation of the project. Four quotations

were received by MSPGCL and BVCL was selected as a DoE for the project activity. The

PDD was provided to DoE for webhosting on 28 April, 2011. Completeness check was

performed by the DoE before webhosting of the PDD. PwC assisted MSPGCL in

addressing the queries raised by BVCL and PDD was finally webhosted on 10 May, 2011.

The webhosting period of PDD was from 10 May, 2011 to 08 June, 2011 and project is

currently under validation stage.

Capacity building

(29) The institutional capacity building requirements of the Implementing Agencies was

identified in the following areas.

Data collection and data management for PDD development

Preparation for Project validation

Monitoring and Verification requirements.

(30) We conducted a total of 21 capacity building workshops under this TA. The date and

venue for these workshops is included in Annexure 8. We understand that the

Implementing Agencies who were engaged in this TA are now aware of roles of different

entities that are involved at various stages of the CDM process. CDM workshops helped

the Implementing Agencies in understanding the importance of data collection, data

management, monitoring and verification requirements which are essential for

successful issuance of CERs from the project activity. The Implementing Agencies can

now independently identify the CDM projects, execute local stakeholder process and

apply for host country approval.

(31) The governance of CDM process in the Implementing Agencies is another critical aspect

that was strengthened. HPPCL nominated office of chief engineer system planning to

oversee CDM activities in relation to R&M. Similarly, MeSEB nominated office of chief

engineer generation, APGENCO nominated office of chief engineer commercial and

MSPGCL nominated its environment cell to identify and execute CDM activities.

(32) The Implementing Agencies are now aware of requirements of CDM consideration

including (i) intimation to NCDMA and UNFCCC within six months of the project start

date and (ii) consideration of CDM revenues while making a decision to implement the

project activity.

(33) The projects taken independently (without assistance of ADB TA) by the Implementing

Agencies for whom we have conducted capacity building workshops are listed in Table 3

below:

Table 3: CDM projects developed independently by IAs

Implementation agency Project activity



MSPGCL 4 MW Solar Energy based Power Plant

MSPGCL 2 x 660 MW supercritical project

APGENCO Portfolio of supercritical, hydro projects

GSECL Grid connected, combined cycle power project of

capacity 374.57 MW at Gujarat, India

MeSEB Myntdu Leskha Hydro Electric Project in Meghalaya

(34) A summary of the tasks completed during the tenure of TA is set out in Table 4 below.

Table 4: Summary of tasks under the TA

CDM cycle Tasks

PDD

development

Draft PDDs completed for 8 projects

Review of DPRs prepared by the Implementing Agencies

completed in respect of 8 projects and inputs provided to the

Implementing Agencies

Local stakeholder consultation completed for 4 projects including

Giri HEP, Umium HEP, Machkund HEP and Koradi TPS

Host country

approval

Four PDDs and PCNs submitted for host country approval

Presentation to NCDMA completed for these PDDs

Local stakeholder consultation completed for these PDDs

NCDMA approval achieved by Giri HEP, Umium HEP and Koradi

TPS

Validation Discussions with ADB Carbon Fund for financing of validation

costs was completed

Presentations made to Implementing Agencies to introduce the

ADB Carbon Fund, the terms of arrangement for financing advance

funding against CERs

Review of CERPA completed and feedback submitted to Executing

Agency for commencing the process of signing the CERPA

DOE appointed for Koradi TPS

PDD for Koradi TPS webhosted on 10 May, 2011

Capacity

Building

CDM capacity building workshops conducted for 11 Implementing

Agencies.

Special workshops conducted for HPPCL, MeSEB and APGENCO



in regard to the local stakeholder consultation process under CDM.

Centralized workshop for all the participating Implementing

Agencies in New Delhi.

Project specific presentations to MSPGCL, APGENCO, MeSEB and

OHPC focusing on CDM consideration, setting baseline,

establishing additionality and monitoring requirements.

Learning from TA

(35) The tenure of TA was initially 16 months which was later extended to 34 months. The

time required for the board of the Implementing Agencies to approve the project

investments from the date of identification of the project to final approval of the board

extends to multiple years. The information on the project required for CDM can be made

available only after approval has been granted by the board for project activity. We

recommend that for designing TAs for future interventions, the life cycle of the

underlying investments, from identification to investment approval to start of

implementation, should be considered. In the context of R&M project activities, as the

board approval is expected to take upwards of 2 years from the start of first activity and

CDM registration is expected to take between 1.5 to 2 years, the TA should cover a period

of 3.5 to 4 years.

(36) The CDM rules require conducting RLA studies to demonstrate remaining useful life of

the plant. In some instances, the RLA studies were not available while in others, the RLA

studies did not explicitly state the residual life. We understand that the reason why RLA

studies do not explicitly mention the residual life was because it is not provided in the

terms of reference of the studies. The future TA design must require the Implementing

Agencies to include this requirement as part of the terms of reference of RLA studies.

(37) On the same lines, it is advisable to secure the cost of validation and registration of the

CDM project activities. Most of the Implementing Agencies in India were unwilling to

incur expense on cost of validation and registration leading to delays in moving the

projects beyond the PDD stage. There are instances of buyers who would provide upfront

financing for securing emission reduction purchase agreements.

(38) CDM is a data intensive process and requires constant effort with multiple stakeholders

such as local stakeholders, NCDMA and DOE during the CDM cycle. A dedicated 2- 3

member team in the Implementing Agency is required, headed by a sufficiently senior

representative (a chief engineer or equivalent), who can work closely with the various

stakeholders to identify and develop CDM requirements.

Benefiting from carbon markets

(39) Under the current CDM framework, we would recommend using the Programme of

Activities (PoA) approach covering the thermal R&M and hydro R&M separately given

the nature of project activity and long lead times. PoA approach was introduced in 27

July, 2012.



(40) As and when an international climate agreement is reached, there will be a significant

boost to the carbon markets. Emission trading schemes and mechanisms that are

currently operational or are in development are listed in Table 7. Linking CERs into some

of these emission trading schemes under development may open new markets for CDM

projects. There are trading schemes outside the EU ETS which has a window of linking

CERs (including those resulting from projects located in India and China) to the ETS.

The time frames and the nature of linking are expected to emerge over the next few years

as these schemes gain operational experience.

(41) In addition, there are now new mechanisms like standardised baselines and NAMAs

(unilateral, funded and credited) that are being developed which can be employed to

move away from a project by project approach to a sectoral approach. NAMAs provide

the link between a domestic action being linked to international carbon markets. As an

example, the Perform, Achieve, Trade scheme run by the Bureau of Energy Efficiency for

improving energy efficiency in thermal power generation and carbon emission reductions

may be developed as a credited NAMA for improving energy efficiency in thermal power

generation and credits generated from such a NAMA may be eligible in future carbon

markets.



Finding in relation to project portfolio



Finding in relation to project portfolio

Selection of projects

1. In total of 64 projects from 17 states were identified and analyzed for selection of

potential candidates for CDM. PwC and Executing Agency teams carried out site visits to

the available Implementing Agencies for discussing and collecting data relating to their

R&M projects. CDM diagnostic study was carried to examine the CDM eligibility of the

projects selected in 17 states.

Andhra Pradesh

Gujarat

Haryana

Himachal Pradesh

Jammu & Kashmir

Jharkhand

Karnataka

Kerala

Madhya Pradesh

Maharashtra

Meghalaya

Punjab

Uttar Pradesh

Uttarakhand

West Bengal

Orissa

Tamil Nadu

2. The states of Karnataka, Jharkhand and Orissa were excluded as none of the R&M

projects in these states were expected to be implementation in 11th plan (2007-12), a

criteria that was agreed by ADB, EA and IAs. The projects in the state of Haryana were

financed through World Bank-GEF funding which prevented it from being considered.

The state of J&K was excluded due to prevailing law and order situation.

3. Based on the preliminary information that was made available by the Implementing

Agencies, a total of 13 projects were short-listed for further review and PDD preparation.

In the subsequent discussions held with the Implementing Agencies, West Bengal Power

Development Corporation (WBPDCL) informed that the R&M projects were being

financed under the World Bank GEF program and the terms of GEF financing constrains

WBPDCL to participate in the ADB TA for CDM development of these R&M projects.

Similarly, the Gujarat State Electricity Corporation (“GSEC”) also informed that the R&M projects submitted by them have been deferred and are unlikely to be taken up during

the 11th plan period. In light of this, two projects each of GSEC and WBPDCL were

dropped. One project of PSEB had to be dropped because of non availability of CDM

consideration.

4. The meeting with Maharashtra State Power Generation Corporation (MSPGCL) was held

on 12 November, 2008. However, MSPGCL proposed a replacement project of 4X120

MW projects with a new 660 MW supercritical project. Supercritical projects are eligible

for CDM revenues and therefore it was decided to examine this project for CDM

eligibility. The approved methodology ACM0013 was closest that could be applied for the

project activity. Therefore, this project was included in the list for further examination

and consideration. Two hydro projects of Kerala State Electricity Board and one thermal

R&M project of MPPGCL were discussed and it was agreed that these projects would be

taken up for PDD development. PSEB proposed two additional hydro R&M projects

which were examined.



5. After completion of diagnostic study and review of information submitted by the

Implementing Agencies, 14 projects were included in the second shortlist. Out of above,

four APGENCO projects and two PSEB projects were dropped from further

consideration, as they were either already under implementation phase or were approved

without considering CDM revenue in the investment decision. PSEB proposed yet

another thermal R&M project. It was decided to continue work on the nine projects. The

projects contained in the first, second and final shortlist are set out below:

Table 5: List of potential CDM projects

Implementing Agency

Power Station Total Capacity (MW)

First List of 13 projects

Second List of 14 projects

Final List of 9 projects

APGENCO Kothagudem TPS 240

APGENCO Machkund HEP 114.75

APGENCO Nagarjuna Sagar HEP 815.6

APGENCO Sri Sailem HEP 770

APGENCO Upper Sileru HEP 240

APGENCO Vijayawada TPS 420

GSECL Kutch Lignite TPS 140

GSECL Ukai TPS 240

HPPCL Giri HEP 60

KSEB Poringalkuthu HEP 32

KSEB Sholaya HEP 54

MeSEB Umiam HEP 60

MPPGCL Satpura TPS 830

MSPGCL Koradi TPS 660

PSEB Anandpur Sahib HEP 15

PSEB Shanan HEP 15

PSEB Upper Bari Doab Canal HEP

15

PSEB Guru Gobind Singh TPS 420

WBPDCL Bandel TPS 210

WBPDCL Kolaghat TPS 1260

6. In order to develop the PDD for the identified projects, the Implementing Agencies

expressed the need to have a formal understanding with Executing Agency before sharing

further information on the projects. Executing Agency forwarded the MoU draft to the

Implementing Agencies and held discussions with the Implementing Agencies to

conclude the MoU signing process. The process of PDD preparation was started after the

execution of MoU between the Implementing Agencies and Executing Agency.

Further progress on 9 shortlisted projects



Vijayawada TPS

7. The PDD for Vijayawada TPS was completed and provided to project proponent for

review. The project activity involved implementation of variable frequency drives (VFDs)

that is expected to result in decrease in auxiliary consumption.

8. The annual estimated CERs for Vijayawada TPS was 2,854. The cost benefit (cost of CDM

registration and CER issuance vs. revenue from CERs) did not show a positive cash flow.

Therefore Vijayawada TPS was also dropped.

Poringalkuthu HEP

9. The cost benefit analysis (validation, registration and verification cost vis-à-vis CDM

revenues) was conducted for the project and was submitted to KSEB for consideration of

this project as CDM project. The PDD for Poringalkuthu hydro project was completed

and provided to KSEB.

10. KSEB appointed CPRI for DPR preparation. We advised KSEB on the aspects that relates

to CDM guidelines so that they can be considered while finalizing the detailed project

report. The remaining technical life of the project could not be established by the study

conducted by CPRI. Therefore this project could not be pursued further beyond the PDD

stage.

Sholaya HEP

11. Cost benefit analysis (validation, registration and verification cost vis-à-vis CDM

revenues) was conducted for the project and was submitted to KSEB for consideration of

this project as CDM project.

12. We advised KSEB on the aspects that relates to CDM guidelines so that they can be

considered while finalizing the detailed project report. The technical life of the project

could not be established by the study conducted by CPRI. Therefore this project could

not be pursued further and was dropped.

Satpura TPS

13. The PDD for R&M of Satpura thermal power station of MPPGCL was completed and

submitted to MPPGCL prior to submission of the first interim report in January, 2009.

14. CDM rules require that the project proponent should establish, through documentary

evidence, that CDM was seriously considered at the time of decision making. This can be

established from board resolution or detailed project report.

15. The draft DPR submitted by DPR consultant to MPPGCL did not contain an analysis of

the CDM revenues and its impact on the project activity. The CDM rules require the DPR

and Board resolution to be explicit in reference to the importance and its impact on the

project activity.

16. MPPGCL expressed its unwillingness to pay for validation and registration fee. ADB

Carbon fund was willing to give upfront finance against CERs to the projects that are

expected to generate CERs before 2012. As per DPR, the project was scheduled to be

implemented in March, 2013. Further we explored the possibility of utilizing the

contingency fund that was available in TA for financing validation fee. ADB informed



that the allocation for contingency under TA cannot be used for financing of validation

fee. Thus there was bottleneck to proceed further in the absence of availability of finance

for validation and registration fee.

17. The monitoring data available was inadequate to measure the efficiency for individual

equipment (boiler, generator, turbine, auxiliary etc). As per approved methodology ACM

0061, the baseline efficiency has to be established for each R&M measure that is

envisaged by the project proponent.

18. In the absence of the evidence of CDM consideration, non availability of finance for

validation fee and inadequate data for establishing baseline efficiency, the project was

dropped from further consideration.

Guru Gobind Singh TPS

19. The PDD for the project activity was completed and provided to PSEB. Units I and II

were proposed by PSEB for R&M. The issues that were highlighted in the PDD include

residual life of the project activity, establishing heat rate for units I and II and envisaged

heat rate after implementation of R&M activities.

20. Units I and Unit II were commissioned on 26 September, 1984 and 29 March, 1985

respectively. The CDM rules require that residual technical life of the plant shall be

established. The CERs for the project activity are available only up to the residual

technical life of the project activity. The DPR for the project activity was not able to

establish remaining technical life of the project.

21. There were two monitoring issues in the project activity (1) establishment of heat rate

and (2) capping of baseline capacity of the existing equipment. The CDM rules require

that efficiency of the each unit should be established separately. However the weighing

system for fuel measurement was common to all six units of the thermal station, and the

amount of fuel being fed to each of the six boilers could not be identified separately.

22. Due to inadequate data on efficiency for each of the units and inability to establish the

remaining technical life, the project was dropped from further consideration.

23. Therefore out of the 9 projects that were selected during the second interim report, 5

projects were further dropped after discussion with Executing Agency. Finally four

projects were selected for further development.

CDM project development

Machkund HEP

PDD development

24. Machkund HEP is a joint project between the states of Andhra Pradesh and Orissa and

the formal approval for the project has been long pending because of the dispute between

the two states regarding the sharing of electricity. The electricity generated by the project

is shared in the ration of 30:70 between the state of Orissa and state of Andhra Pradesh.

However, state of Orissa is now demanding the sharing of electricity generated in the

ratio of 50:50 after implementation of R&M activities. Due to the dispute on sharing of



the electricity between the state of Orissa and the state of Andhra Pradesh, the approval

on implementation of the project is pending from OHPC.

25. The DPR that was prepared internally by APGENCO was provided to us for development

of PDD. The PDD for Machkund hydro electric project was completed and submitted to

APGENCO for their review and approval.


26. The PDD was submitted to NCDMA for host country approval. The NCDMA meeting for

the project was held on 03 March, 2009 and was attended by personnel from APGENCO

and PwC. The presentation on salient features of the project and its CDM eligibility was

made to NCDMA. NCDMA requested certain additional information – an undertaking

from APGENCO that the project does not require any environmental clearance. NCDMA

also requested to submit the undertaking that CDM revenues were considered by the

project proponent for approving the R&M activity.

27. As the project is jointly developed by OHPC and APGENCO, the undertaking that CDM

revenues were considered by the PP for approving the R&M activity was requested from

both the project proponents.

28. Further as per guidelines of NCDMA, the documents that are requested during the

meeting shall be submitted within six months of the date of meeting. Due to pending

intergovernmental settlement on implementation of the project, the documents could not

be presented to NCDMA before the deadline date and hence the project was not able to

secure host country approval.

Other Issue

29. Sharing of the cost of validation between OHPC and APGENCO was to be done on the

basis of sharing of electricity generated from the project activity. Due to pending

intergovernmental settlement on sharing of electricity generated by the project, the

extent to which the cost will be borne between both the parties could not be established.

30. In a recent development, the Governments of Andhra Pradesh and Orissa have signed

the MoU but the contract for same has yet not been executed.

31. OHPC informed that its board will approve the project only after completion of

assessment of the R&M activities by the engineering consultant. APGENCO has

appointed an engineering consultant for assessment of the R&M activities and cost of

undertaking R&M activities. The report from the engineering consultant is expected by

November, 2011 and therefore approval is pending from board of OHPC.

32. In light of above issues, the validator for the project could not proceed beyond the PDD

stage.

Giri HEP

PDD development

33. The detailed project report for the project activity was prepared by M/S Four Seasons.

DPR was provided to us for PDD development. The PDD was completed and submitted

to HPPCL for their review and comments before the first interim report.




34. The PDD was also filed with NCDMA along with the supporting documents. The meeting

for the project activity was conducted for NCDMA on 22 April, 2009. NCDMA directed

HPPCL for submission of statutory clearances and minutes of stakeholder consultation.

35. The stakeholder meeting was conducted on 19 June, 2009. We assisted HPPCL with the

process for stakeholder consultation and also with draft templates for conducting local

stakeholder consultation. The submission of statutory clearances and minutes of

stakeholder consultation was made to NCDMA. The host country approval for the project

activity was finally received on 17 November, 2009.

Board Approval

36. HPPCL informed on 8 March, 2011 that the project was pending consideration of their

board. The validator for the project activity was not finalized by HPPCL as the scheme of

works was pending board approval. As the project will now be executed in the 12th plan,

due to uncertainty of CER revenues post 2012 HPPCL expressed its concerns about

incurring cost towards validation and registration. For these reasons, this project was

dropped.

Umium HEP

PDD development

37. The DPR for the project activity was provided to us by MeSEB. The PDD was completed

based on DPR provided by MeSEB and was submitted before the first interim report.


38. The PDD was also filed with NCDMA along with the statutory clearances for host

country approval. The meeting for the project activity was scheduled by NCMDA on 22

April, 2009. NCDMA directed MeSEB for submission of statutory clearances and

minutes of stakeholder consultation.

39. The stakeholder meeting was conducted by MeSEB on 15 May, 2009. We assisted MeSEB

with the process for stakeholder consultation for CDM project and recording minutes of

meeting including CDM procedures on engaging stakeholders. The submission of

statutory clearances and minutes of stakeholder consultation was made to NCDMA by

MeSEB. The host country approval for the project activity was finally received on 17

November, 2009.

Other issues

40. DPR for the project activity was prepared in 2006. MeSEB filed the DPR for techno

economic clearance from CEA for implementation of the project. CEA requested

clarification on relevance of capital cost that was expected to be commissioned in 2012

but is now expected to commence commissioning in 2012 and complete implementation

only in 2015. Therefore the need to revise the capital cost was expressed by MeSEB that

may reflect the current expected financial cost.

41. MeSEB is planning to apply for grant funding. CDM is project specific mechanism and in

case of grant funding is successfully achieved; the project may not be additional.



Therefore, in light of above issues, the appointment of validator for the project activity

was kept on hold by MeSEB.

Koradi TPS

Project documents

42. We reviewed the draft DPR particularly in relation to the levelized cost calculations and

found that the tariff numbers did not match with the numbers provided in the DPR. We

provided our feedback to MSPGCL requesting for a copy of the financial workings,

however the DPR consultants of MSPGCL have declined to share the financial workings

with us. We have conducted several rounds of meetings with MSPGCL and DCPL to

discuss and resolve this issue, during the discussions we discovered that in many

instances the assumptions given in the DPR by DCPL and the assumptions considered

for financial calculations do not match.

43. Based on the assumptions provided in the DPR and publically available information, the

levelised cost of the project was calculated and PDD was finalized.

Stakeholder meeting

44. The four activities that are important part of stakeholder consultation process include

identification of stakeholders to be approached, information to be disseminated,

methods of dissemination to be used and addressing comments. We assisted MSPGCL

with the documents and process of conducting stakeholder consultation as per

requirements of CDM.

45. The draft templates for inviting stakeholders and issues to be discussed with

stakeholders were provided to MSPGCL. Stakeholder meeting was conducted on 18

November, 2009.


46. The PDD was also submitted to NCDMA for host country approval. The presentation on

the project was made to NCDMA on 24 September, 2010.

47. NCDMA requested the following the documents to be submitted within six months of the

meeting.

SPCB clearance dated 29 January, 2010 by Maharashtra State Pollution Board

PCN version 1.0 in PDF Format

Credible monitoring action plan for large scale CDM projects earmarking 2% of

annual CER revenue for sustainable development activities

48. We assisted MSPGCL in submission of documents requested by NCDMA for host country

approval. The host country approval for the project was received on 15 November, 2010.

Finalization of PDD

49. A presentation was made to MSPGCL focusing on the following issues so that concerned

persons will have adequate understanding of the CDM validation process and issues

related to the project:

CDM process



PDD requirements

Data requirements

Applicability of approved methodology

CDM consideration


Additionality

Baseline

Pipeline of super critical projects

Review questions raised by CDM EB for such projects in the past

50. After discussion with MSPGCL, the PDD was finalized that was to be submitted to DoE

for webhosting.

Appointment of DoE

51. MSPGCL had earlier expressed its inability to bear cost of validation and registration.

This was pointed out in the second interim report. Two routes were explored to resolve

the issue of validation and registration fee.

Upfront finance from ADB Carbon Fund to cover up validation and registration

fee

Diversion of contingency fund of TA towards validation and registration fee

52. One of the key requirements laid by ADB Carbon Fund was that the project should be

implemented and has the potential to generate CERs before 2012. Second route could not

fructify as ADB did not approve the application of TA contingency fund towards

validation and registration fee.

53. We again took the matter with MSPGCL and presented the approval note for

appointment of DOE for consideration of their management. MSPGCL finally agreed to

appoint the DOE for validation of the project at their own cost.

54. We assisted MSPGCL in preparing the tender document for inviting interest for

validation of the project. The tender document was floated by MSPGCL and four bids

were received. BVCL was selected as the validator for the project activity.

Webhosting of PDD

55. The PDD was provided to BVCL on 28 April, 2011. The completeness check of PDD was

undertaken by BVCL. We assisted MSPGCL in addressing the queries that were raised by

BVCL during completeness check for webhosting of the PDD. The PDD was webhosted

by BVCL on 10 May, 2011.

Barriers to CDM development

56. The key issues due to which the projects were dropped are as follows

Residual Life

CDM consideration documentation



Cost of validation and registration

Inadequate monitored data for setting baseline

Residual life

57. As per approved methodologies, remaining residual life of the project activity can be

substantiated as one of the following:-

The typical average technical lifetime of the type of power equipments may be

determined taking into account common practices in the sector and country

(e.g. based on industry surveys, statistics, technical literature, etc.);

The practices of the responsible company regarding replacement/rehabilitation

schedules may be evaluated and documented (e.g. based on historical

replacement records for similar power equipments).

58. The technical life of the project could also be established by conducting RLA (Residual

Life Assessment) studies for R&M projects. Crediting period for the project activity will

be limited to the extent of remaining residual life of the project activity. The projects that

have completed their technical useful life may not be eligible to generate CERs.

59. The number of projects under consideration has conducted a RLA study but was not very

specific in stating the remaining residual life. The RLA studies focused on the health of

the equipment but were not explicit on estimating the remaining technical life, one of the

requirements for setting crediting period. We understand that the reason is that the

terms of reference for RLA studies may not have contained the requirement to explicitly

state the residual life.

CDM consideration

60. CDM consideration is gauged by the following documents by a validator:

Board resolution

DPR

61. During the validation stage, one of the important documents that are required by the

validator for establishing the seriousness of CDM consideration is a copy of the board

resolution. The board resolution shall clearly state the importance of CDM revenues

while decision to invest was taken by the Board.

62. The board decision is in general based on the notes contained in the board agenda

including recommendations from corporate team or DPR documents. The validator

requires the entire audit trail for the board resolution – board note, DPR and other

backup documents based on which the decision was taken by the board to confirm the

CDM consideration. Therefore the projects where CDM consideration could not be

established had to be dropped.

Validation and registration cost

63. The Implementing Agencies expressed their concern over committing their funds

towards validation and registration fee in view of the uncertainties prevailing over CDM

registration of projects in general. Also the ADB TA does not contain any provisions for

financing of such costs.



64. In order to address the concern of the Implementing Agencies and to ensure that the

projects move forward in the CDM process, we discussed with the ADB Carbon Fund for

financing the CDM related expenses up to registration stage. Further, we also requested

the application of contingency fund under ADB TA towards validation and registration

cost.

65. The Implementing Agencies can enter into the future contract with the ADB Carbon

Fund for the CERs that will be generated from the project activity and avail advance

funding from the carbon funds. One of the key requirements for projects in order to be

able to receive advance funding was that the project should be implemented and should

generate CERs before 2012.

66. The gestation period of these projects in most cases extends from 3 to 5 years and

therefore most of the projects were expected to be commissioned/ completed after 2012.

Therefore only a few projects were eligible for availing the benefit of receiving upfront

financing to meet validation costs. ADB also informed its inability to approve the

application of contingency fund under TA towards validation and registration cost. As a

result, the projects of those Implementing Agencies that were unwilling to bear the cost

of validation and were expected to be implemented beyond 2012 could not be taken

forward beyond the PDD stage.

Inadequate monitored data for setting baseline

67. The availability of historical data records is critical for setting the baseline in case of

thermal R&M projects. In case of thermal R&M projects, efficiency of the existing units is

required to be established based on the past historical data according to the CDM rules.

Two of the projects (Guru Gobind Singh TPS and Satpura TPS) under consideration had

common fuel measurement system for all the units of the power station. Therefore

establishment of the efficiency of the individual units cannot be established.

68. Other issues with respect to availability of data includes establishment of efficiency for

each of the equipment (boiler, turbine, generator, auxiliary etc.) that is being considered

under CDM. In most of the cases, only limited data was available.



Capacity Building



Capacity Building

Requirements

69. The CDM process is data intensive and requires proper documentation that is

transparent in stating the decision making context, assumptions that are used during the

decision making, statutory clearances for the project, sustainable development criteria

including stakeholder consultation and monitoring requirements.

70. It starts from the decision to implement the project by the management, at which stage

revenues from CDM should have been explicitly considered in the investment analysis of

the project. As per guidance for investment analysis under CDM rules, the assumptions

that are used for decision making should be available to the management at the time of

decision making for substantiating additionality. The validation opinion is published by

the DoE based on the documentary evidence which is verifiable and provided by the

project proponent during the validation stage.

71. NCDMA also insists on documentary evidence for granting host country approval to the

project. The documents that are requested by NCDMA include board resolution stating

CDM consideration, statutory clearances and undertaking stating that 2% of the CDM

revenues will be contributed towards sustainable development in case of large scale

projects. The NCDMA also can at its own discretion demand additional documents

before providing NCDMA approval.

72. NCDMA evaluates the projects with respect to their contribution to sustainable

development and financing to ensure that there is no ODA (Official Development

Assistance) diversion. This is a requirement under the Kyoto Protocol. In case public

funding from developed countries is involved, information is to be provided on sources of

public funding for the project activity. The projects that are financed using public

funding which is counted towards the financial obligations of developed countries are not

eligible for CDM revenues as this will be termed as ODA diversion. Therefore in cases

where ODA is used for financing CDM projects, confirmation has to be provided by the

developed countries/multilateral agencies that such funding does not result in a

diversion of ODA and is separate from and is not counted towards the financial

obligations of those developed countries.

73. NCDMA expects the project sponsors to liaise directly with it. The CDM workshops

geared the Implementing Agencies to undertake host country approval process

independently.

74. The three critical areas in the CDM registration process include baseline, additionality

and monitoring. Additionality for R&M projects can be substantiated using investment

analysis. UNFCCC has approved the guidance for investment analysis that must be

followed to substantiate additionality. It has been observed in the past that the projects

under which the monitoring procedures are not defined as per requirements of PDD are

not able to generate CERs even if they are registered.



75. Bearing in mind the data and documentation requirements under CDM, institutional

capacity building requirements of the Implementing Agencies were identified in the

following areas.

Data collection and data management for PDD development

Preparation for Project validation

Monitoring and Verification requirements.

76. Capacity building workshops helped the state utility in understanding the basic concepts

of CDM additionality, baseline establishment, monitoring, project eligibility, potential

revenue, local stakeholder process and host country approval process. In addition to

CDM process and data requirements, the capacity building exercise helped the

Implementing Agencies in understanding the process for monetizing the CERs and

updates on the carbon markets.

77. A CDM project activity is additional if anthropogenic emissions of greenhouse gases by

sources are reduced below those that would have occurred in the absence of the

registered CDM project activity. The additionality tool on demonstration and assessment

of additionality lists the step wise approach to check additionality of the project activity.

The workshop conducted focused on approach to conducting additionality based on the

requirements of the Tool for the Demonstration and Assessment of Additionality.

78. Validation of the project activity is a data intensive process. All the assumptions that are

used under additionality arguments, baseline setting and CER estimation have to be

provided in the form of documentary evidence to the DOE for verification. As per CDM

rules, the emissions reductions from the project activity should be real, measurable and

verifiable. Therefore all the parameters that are used for calculating emission reductions

shall be supported by documentary evidence. There are many instances where projects

are registered but fail at the time of issuance and hence are unable to yield emission

reductions. Therefore the workshops focussed on the importance of documentary

evidence in the CDM process so that projects shall be registered keeping in mind the

requirements of verification.

79. Local stakeholder process is an integral part of CDM process to gauge sustainable

development. Local stakeholder process includes engaging the local stakeholders to

identify the impact of the project activity to local environment and local population. The

workshops conducted on local stakeholder process helped the Implementing Agencies in

understanding the importance of sustainable development in the CDM process, the

process of conducting the stakeholder consultation and incorporating feedback.

Outcome

80. We conducted a total of 21 capacity building workshops under this TA. The date and

venue for these workshops is included in Annexure 8. The capacity building workshops

focused on the CDM consideration, CDM tools and guidelines, additionality, baseline,

stakeholder consultation process, host country approval process, monitoring process and

requirements.

81. We understand that the Implementing Agencies whom were engaged in this TA are now

aware of roles of different entities that are involved at various stages of the CDM process.



CDM workshops helped the Implementing Agencies in understanding the importance of

data collection, data management, monitoring and verification requirements which are

essential for successful issuance of CERs from the project activity. The Implementing

Agencies are now aware of requirements of CDM consideration including (i) intimation

to NCDMA and UNFCCC within six months of the project start date and (ii)

consideration of CDM revenues while making a decision to implement the project

activity. The Implementing Agencies can now independently identify the CDM projects,

execute local stakeholder process and apply for host country approval.

82. The governance of CDM process in the Implementing Agencies is another critical aspect

that was strengthened. HPPCL nominated office of chief engineer system planning to

oversee CDM activities in relation to R&M. Similarly, MeSEB nominated office of chief

engineer generation, APGENCO nominated office of chief engineer commercial and

MSPGCL nominated its environment cell to identify and execute CDM activities.

83. We understand that the Implementing Agencies that participated in the TA have taken

up CDM project development independently (without external assistance). While

information on such projects which have reached validation is available on UNFCCC,

others are in the process of PDD completion. Some of the examples are:

MSPGCL is developing a 4 MW solar power project as CDM project. It is also

developing a 2 x 660 MW supercritical power project as CDM project activity.

GSECL is in the process of developing 374.57 MW CCGT as a CDM project activity.

MeSEB is developing Myntdu Leskha hydro electric power project as a CDM project

activity.

APGENCO is developing a portfolio of CDM project activities in supercritical and

hydro power projects



TA Progress and Near Term Opportunities



TA Progress and Near Term Opportunities

MOU between EA and IA

84. A draft of the proposed MoU to be entered into between the Executing Agency and

Implementing Agencies was prepared and submitted to Executing Agency for review on

15 July, 2008.

Inception report

85. The TA Inception Report was submitted on 20 August, 2008

Diagnostic report

86. The diagnostic Report was submitted on 4 September, 2008

Workshops

87. We conducted a total of 21 capacity building workshops under this TA. The date and

venue for these workshops is included in Annexure 8.

PDD preparation

88. The diagnostic study and initial short-listing of projects was completed by first week of

September, 2008 and PDD development of these projects was initiated immediately

upon getting confirmation from the Implementing Agencies about their willingness to

participate in the ADB TA by agreeing to sign the MoU with Executing Agency. As per

term of reference, the total of 8 PDDs were completed and submitted to ADB, Executing

Agency and the Implementing Agencies.


89. The PDDs of Machkund HEP, Giri HEP, Umium HEP and Koradi TPS were submitted to

NCDMA. The host country approval for 3 projects (Table 6) was received by MeSEB,

Umium and Koradi TPS. Due to intergovernmental issues, board resolution from OHPC

could not be submitted to NCDMA and the project did not receive host country approval.

Table 6: List of projects receiving host country approval

Implementing

Agency

Project Host country approval

Date

MeSEB Umium HEP 17 November, 2009

HPPCL Giri HEP 17 November, 2009

MSPGCL Koradi TPS 15 November, 2010



Validator appointment

90. We assisted MSPGCL in preparing tender document for appointment of validator. Four

bids were received from DoEs for validation of Koradi TPS project. BVCL was selected as

validator for Koradi TPS project by MSPGCL.

Webhosting of PDD

91. The PDD was provided to BVCL for webhosting on 28 April, 2011. Completeness check

was performed by the BVCL before webhosting of the PDD. We assisted MSPGCL in

addressing the queries raised by BVCL and PDD was finally webhosted on 10 May, 2011.

The webhosting period of PDD was from 10 May, 2011 to 08 Jun, 2011 and the project is

currently under validation stage.

Near term opportunities:

Emission Trading Schemes

92. The Kyoto Protocol is an international agreement linked to the United Nations

Framework Convention on Climate Change. Kyoto Protocol sets binding targets for 37

industrialized countries and the European community for reducing greenhouse gas

emissions. The Kyoto Protocol was adopted in Japan on 11 December, 1997 and entered

into force on 16 February, 2005. The first commitment period of the Kyoto Protocol ends

in December 2012.

93. The Kyoto Protocol is generally seen as an important first step towards a truly global

emission reduction regime that will stabilize GHG emissions, and provides the essential

architecture for any future international agreement on climate change. There are three

market based Kyoto mechanisms that simulate green investment and help Parties meet

their emission targets – International Emissions Trading, Clean Development

Mechanism and Joint Implementation.

94. As per decision adopted jointly by the European Parliament and the Council on 23 April,

2009 on the effort of member states to reduce their greenhouse gas emissions to meet

the greenhouse gas emission reduction commitments of the member states up to 2020,

member States may use the following greenhouse gas emission reduction credits to

implement their obligations

CERs and ERUs, issued in respect of emission reductions until 31 December 2012

which are eligible for use in the Community scheme during the period from 2008

to 2012;

CERs and ERUs issued in respect of emission reductions from 1 January, 2013

from projects which were registered before 2013 and which were eligible for use

in the Community scheme during the period from 2008 to 2012;

CERs issued in respect of emission reductions achieved from projects

implemented in LDCs which were eligible for use in the Community scheme

during the period from 2008 to 2012, until those countries have ratified a

relevant agreement with the Community or until 2020, whichever is the earlier;



in case an international agreement on climate change is reached, CERs from

projects located in countries which have ratified the international agreement can

be used. Thus, if an international agreement is reached and India ratifies the

agreement, then CERs from Indian projects registered after 1 January 2013 will

also be eligible;

95. The second commitment period is agreed in COP 17 under the Kyoto Protocol which shall

begin on 1 January 2013 and end either on 31 December 2017 or 31 December 2020. The

reduction targets compared to 1990 levels and to be achieved by 2020 are:

European Union: 20% to 30%

Norway: 30-40%

Switzerland: 20-30%

Ukraine: 20%

Canada, Japan and Russia have withdrawn from the second commitment period of Kyoto

protocol. The targets that are decided are conditional on action by others countries and

will be more precisely defined in COP 18 in Qatar in 2012.

96. Emission trading schemes and mechanisms that are currently operational or are in

development are listed in Table 7. Linking CERs into some of these emission trading

schemes under development may open new markets for CDM projects. There is at least

one scheme outside the EU ETS which has a window of linking CERs (including those

resulting from projects located in India and China) to the ETS. The time frames and the

nature of linking are expected to emerge over the next few years as these schemes gain

operational experience.

Table 7: Emission Trading Schemes in operation/development

Scheme name Operating/Under development

CERs Eligibility

EU ETS Operating Yes

Norway ETS Operating Yes

Iceland ETS Operating Yes

Liechtenstein ETS Operating Yes

Swiss ETS Operating Yes

New Zealand ETS Operating Yes

Japan ETS Under development No

California cap and trade Under development No

Regional greenhouse gas initiative Operating No



Western climate initiative Under development CERs may be allowed

Canada ETS Under development No

UK CRC energy efficiency scheme Operating No

Australia new ETS Under development Yes

Nationally Appropriate Mitigation Actions

97. Nationally Appropriate Mitigation Actions (NAMAs) originated in the 2007 Bali Action

Plan for enhanced national / international action on mitigation of climate change. India

communicated that it will endeavour to reduce the emissions intensity of its GDP by 20–25 per cent by 2020 compared with the 2005 level.

98. The Cancun Agreements provide for structuring of NAMAs according to three different

ways of funding:

Domestically supported NAMAs

Internationally supported NAMAs

Market-based or credited NAMAs

At present, about 16 pilot NAMAs have been proposed by different countries. These

NAMAs are spread across transport, building, waste sector, industry and forestry.

National mission on enhanced energy efficiency (NMEEE)

99. Bureau of Energy Efficiency (BEE) has formulated the Perform Achieve and trade (PAT)

scheme under the NMEEE. PAT scheme is a domestic market based mechanism to

enhance cost effectiveness of improvements in energy efficiency in energy-intensive large

industries and facilities, through certification of energy savings that could be traded. The

targets under PAT scheme are set for cluster groups in an industry on the basis of specific

energy consumption.

100. Thermal power generation is one of the Designated Consumers covered under the PAT

scheme. Each unit covered under the PAT scheme will be provided a specific energy

consumption target (% reduction to the baseline specific energy consumption), initially

over a 3 year period. The units covered under the PAT scheme will be entitled to an

ESCert (Energy Saving Certificate) if they reduce their energy consumption by 1 mtoe

(metric tonne of oil equivalent). The units have the option to trade ESCerts if they

overachieve/ under-achieve the specific energy consumption benchmarks. Establishing

the baseline energy consumption for the units is underway and it is expected that the

scheme will become operational in year 2012 and trading of ESCerts will be allowed at

trading platforms at two power exchanges (IEX and PXIL).

101. Other initiative under NMEEE is market transformation for energy efficiency which

includes:

Leveraging international financing instruments to utilize bilateral and

multilateral funds for promoting energy efficiency.



Promotion of PoA of CDM in various sectors by leveraging CDM.

Identification of CDM potential in energy efficiency projects in renovation,

retrofit and replacement.

Adopting CDM potential roadmap for developing new methodologies, increasing

number of DOEs and promoting incentives in public sector.

Other category of CDM projects in power generation

102. CDM potential in power generation projects is not restricted only to R&M projects. The

other project categories that are eligible include:

Green field power generation projects

Fuel switch projects

Energy efficiency projects

103. The green field power generation projects using the following technologies could be

potential CDM projects

Renewable energy projects

Gas based generation projects

Supercritical coal based power generation projects

Therefore all the projects that developed under the above technologies are eligible1 for

CDM revenues provided further that prior consideration and additionality arguments can

be supported by means documented evidence such as board resolution, detailed project

reports, EPC offers etc.

104. CDM provides an economic incentive for switching from oil and coal to natural gas or

biomass. There are number of small scale and large scale methodologies for fossil fuel

switch approved by CDM EB that could be applied to power generation projects. The

purpose of fossil fuel switch in power generation is to increase energy efficiency and/or

replace or retrofit the existing facilities that could use less carbon intensive fuels.

105. Energy efficiency opportunities exist in power generation sector in all technologies

including thermal and hydro power stations. Renovation and modernisation and up-

rating of the existing thermal and hydro electric power projects is considered a cost

effective option to ensure efficiency, better availability and augment capacity addition.

106. CEA maintains the database2 of renovation and modernization of thermal and hydro

power projects that are expected to be implemented in near future. These projects could

be evaluated for documentary evidence on prior consideration, detailed project

1 The Executive Board has temporarily suspended the applicable methodology ACM0013 for supercritical power projects. Refer paragraph 91 of the EB 65 report. (source: http://cdm.unfccc.int/filestorage/T/7/U/T7UE2AMI6SY4OBHQ3KN08VXJWL5D1C/eb65_report.pdf?t=VUt8bHZkdHQ5fDCOQrf4lBnTKroehBgw_ujF) 2 http://www.cea.nic.in/ren_modern.html

http://cdm.unfccc.int/filestorage/T/7/U/T7UE2AMI6SY4OBHQ3KN08VXJWL5D1C/eb65_report.pdf?t=VUt8bHZkdHQ5fDCOQrf4lBnTKroehBgw_ujF

http://cdm.unfccc.int/filestorage/T/7/U/T7UE2AMI6SY4OBHQ3KN08VXJWL5D1C/eb65_report.pdf?t=VUt8bHZkdHQ5fDCOQrf4lBnTKroehBgw_ujF

http://www.cea.nic.in/ren_modern.html



report/feasibility report, EPC offers and baseline data to access the eligibility of the

projects that could be considered for CDM.

107. The approved methodologies (Table 8) that are available and could be applied to power

generation projects for availing CDM benefits are as follows:

Table 8: CDM methodologies for utility power generation

Small Scale Approved Methodology Methodology Number

Green Field Projects

Grid connected renewable electricity generation AMS-I.D

Fuel switch

Energy efficiency and fuel switching measures for

industrial facilities

AMS-II.D

Switching fossil fuels AMS-III.B

Fossil fuel switch in a cogeneration/tri-generation

system

AMS-III.AM

Energy Efficiency Projects

Thermal energy production with or without electricity AMS-I.C

Grid connected renewable electricity generation AMS-I.D

Supply side energy efficiency improvements –

generation

AMS-II.B

Energy efficiency measures through centralization of

utility provisions of an industrial facility

AMS-II.H

Large Scale Approved Methodology Methodology Number

Green Field Projects

Consolidated baseline methodology for grid-connected

electricity generation from renewable sources

ACM0002

Consolidated baseline and monitoring methodology for

new grid connected fossil fuel fired power plants using

ACM0013



a less GHG intensive technology

Baseline Methodology for Grid Connected Electricity

Generation Plants using Natural Gas

AM0029

Construction of a new natural gas power plant

supplying electricity to the grid or a single consumer

AM0087

Fuel switch

Consolidated baseline and monitoring methodology for

fuel switching from coal or petroleum fuel to natural

gas

ACM0009

Consolidated baseline methodology for fuel switching

from coal and/or petroleum fuels to natural gas in

existing power plants for electricity generation

ACM0011

Fuel switch from fossil fuels to biomass residues in

heat generation equipment

AM0036

Efficiency improvement by boiler replacement or

rehabilitation and optional fuel switch in fossil fuel-

fired steam boiler systems

AM0056

Energy Efficiency Projects

Consolidated baseline methodology for grid-connected

electricity generation from renewable sources

ACM0002

Baseline Methodology for Grid Connected Electricity

Generation Plants using Natural Gas

AM029

Efficiency improvement by boiler replacement or

rehabilitation and optional fuel switch in fossil fuel-

fired steam boiler systems

AM0056

Methodology for rehabilitation and/or energy

efficiency improvement in existing power plants

AM0061

Energy efficiency improvements of a power plant

through retrofitting turbines

AM0062



Learning from the TA

108. The CDM process starts with decision making context. The project proponent is required

to demonstrate the requirement of CDM revenues and evidenced through a chain of

documentation starting with feasibility report and ending with the board decision /

resolution. Therefore the projects where the decision has been made without

consideration of CDM revenues cannot be considered as CDM project. Further, for the

energy efficiency projects, the RLA study should clearly indicate the remaining useful life

of the project activity and DPR should demonstrate the awareness and requirement of

CDM. Absent these, it will not be possible to take the CDM projects forward.

109. Therefore while tendering for appointment of RLA and DPR consultant, we recommend

that state utilities shall include the assessment on residual remaining life of the project

activity and the potential of CDM revenues that are expected from the project activity in

the terms of reference.

110. The typical investment process for R&M of hydro and thermal power projects from

identification of the project to final approval of board covers 6 board activities. These

activities are expected to take 243 months from identification of the project to final

approval by the board.

Activity 1: Tendering for engaging RLA consultant by Implementing Agencies

Activity 2: Final RLA study

Activity 3: Appraising the Board for requirement of R&M

Activity 4: Tendering for engaging DPR consultant by Implementing Agencies

Activity 5: Final DPR

Activity 6: Board Approval

Activity 7: Tendering for scheme of works (start date for CDM project activity)

Activity 8: Implementation of the project activity

3 This is indicative and the state utilities may take bit longer or shorter time for approval of the project depending on the project requirements.



Figure 2: Timeline of R&M project activity

111. The tenure of TA was initially 16 months which was later extended to 34 months. The

time required for the Board of the Implementing Agencies to approve the project

investments from the date of identification of the project to final approval of the board

extends to multiple years. The information on the project required for CDM can be made

available only after approval has been granted by the Board for project activity. We

recommend that for designing TAs for future interventions, the life cycle of the

underlying investments, from identification to investment approval to start of

implementation, should be considered. In the context of R&M project activities, as the

board approval is expected to take upwards of 2 years from the start of first activity and

CDM registration is expected to take between 1.5 to 2 years, the TA should cover a period

of 3.5 to 4 years.

112. TA was aimed at providing assistance to the Implementing Agencies on developing the

R&M project as potential candidate CDM projects. The TA did not consider cost of

validation and registration of the project activities. Most of the Implementing Agencies

were unwilling to incur expense on cost of validation and registration. Therefore there

was delay in moving the projects beyond the PDD stage. Therefore, in future, if any such

TA is launched by ADB the cost of validation and registration may be considered in the

budget for TA. Alternatively, these barriers can be alleviated by utilising the upfront

finance from carbon funds that are willing to provide funding for cost of validation and

registration against long term commitment for sale of CERs. The carbon funds in such

cases will conduct the due diligence on the projects to measure the probability of yielding

CERs. The upfront financing of cost of validation and registration may be a valid option

to the project activities provided that the state utilities are open to take such support

against the forward sale of CERs. The forward sale of CERs is associated with the risk of

registration, verification, issuance, delivery and volume. Therefore while the barriers

related to cost of validation and registration may be alleviated using the upfront finance

from the carbon funds but also generates risk related to obligation for delivery of CERs.

0

10

20

30

40

50

60

70

Activity 1 Activity 2 Activity 3 Activity 4 Activity 5 Activity 6 Activity 7 Activity 8

Number of Months



113. Establishment of the baseline under the CDM rules for thermal R&M projects requires

data for last five years for each of the equipment covered under the CDM project. The

availability of this level of historical data for setting baseline efficiency was a significant

issue in most of the thermal R&M power projects.

114. We would recommend using the Programme of Activities (PoA) approach covering the

thermal R&M and hydro R&M separately given the nature of project activity and long

lead times. In addition, there are now new mechanisms like standardised baselines and

NAMAs (unilateral, funded and credited) that are being considered which can be

employed to move away from a project by project approach to a sectoral/ multi-project

approach.

115. Given the synergy between the Perform, Achieve, Trade scheme run by the Bureau of

Energy Efficiency for improving energy efficiency in thermal power generation and

carbon emission reductions, we would recommend developing a NAMA for improving

energy efficiency in thermal power generation.

Up-scaling emission reduction project activities in power sector

Capacity building through workshops and seminars

116. The important consideration for citing CDM potential and carrying them forward for

CDM registration include capacity building of the power sector utilities, better

management of the CDM specific documentation (such as prior consideration,

additionality and baseline data). The capacity building exercise will help the state utilities

in managing the CDM process better that could result in successful registration of the

projects.

117. CDM is very dynamic field with fast changing rules and regulations. It is therefore

important to keep a watch on the latest developments. We recommend that CDM team of

the state utilities should attend on continual basis seminars and workshops that are

organised by entities such as NCDMA, UNFCCC and DoE.

Governance

118. CDM is data intensive process and requires constant effort with multiple stakeholders

such as local stakeholders, NCDMA and DoE during the CDM cycle. A dedicated 2 – 3

member team in the Implementing Agency is required, headed by a sufficiently senior

representative (a chief engineer or equivalent) who can work closely with the various

stakeholders to identify and develop CDM projects. The team must contain members

from the projects/construction department, finance department and the

operations/plant personnel.

Prioritisation of projects

119. The CDM revenue for renovation and modernisation projects varies significantly

depending on the type of the measures undertaken by the utility. Therefore, while the

quantum of CDM revenues may be significant in some of the measures, same cannot hold

good for all the measures. Therefore it is important to prioritise the potential CDM

projects based on expected emission reductions resulting from the project. Once

prioritisation is done, the utilities can focus on the fewer projects with good CDM

potential in order to have better focus.



Alleviating barriers - Sale of CERs post 2012

120. The sale of CERs can be executed by the seller by using any of the below ERPA

structures:

Spot ERPA

Forward ERPA

Combinations of above

121. The spot ERPA is used where CERs are already issued and there is no delivery risk to the

buyer. Therefore buyers are willing to pay higher prices under such ERPA structure.

122. There are number of carbon funds that are active is post 2012 carbon finance. The carbon

finance can be obtained from the buyers by the state utilities by entering into long term

agreement on sale of CERs. There are three major types of forward ERPA pricing

structures (Table 9) that exist in the carbon market.

Table 9: Pricing structures in forward ERPAs

Type of ERPA structures Risk of Seller

Fixed price agreement for forward sale of CERs Low

Floating price agreement indexed to carbon

exchange futures contract with floor and cap.

Medium

Floating price agreement indexed to carbon

exchange futures contract without floor and cap.

High

123. The price of CERs is discounted by the buyers in case of forward contracts but such

contracts can help the state utilities in alleviating the risk of post 2012 CER price. The

state utilities can alleviate the barriers of price uncertainty by entering into long term

fixed price contract or long term floating price contract with floor and cap.

Alleviating barriers – Cost of validation and registration

124. The carbon funds that are willing to enter into long term fixed price contracts or long

term floating price contract with floor and cap for purchase of CERs provide upfront

finance to the extent of cost of validation and registration.

125. The carbon funds in such cases will conduct the due diligence on the projects to measure

the probability of yielding CERs. The projects that are able to pass the due diligence test

are able to avail the upfront finance. The state utilities can make use of such funds to

avail upfront finance and alleviate the barrier with respect to financing of validation and

registration cost.



Annexure



Annexure

Annexure 1: Final Webhosted PDD of MSPGCL

Annexure 2: Presentation made to MSPGCL on stakeholder consultation process

Annexure 3: Presentation made to NCDMA for Koradi TPS

Annexure 4: Presentation made to MSPGCL on project specific issues

Annexure 5: Presentation made to MeSEB on project specific issues

Annexure 6: Presentation made to HPPCL on project specific issues

Annexure 7: Presentation made to APGENCO and OHPC on project specific issues

Annexure 8: Workshops on Capacity building



Annexure 1: Final Webhosted PDD of MSPGCL

CLEAN DEVELOPMENT MECHANISM

PROJECT DESIGN DOCUMENT FORM (CDM-PDD)

Version 03 - in effect as of: 28 July 2006

CONTENTS

A. General description of project activity

B. Application of a baseline and monitoring methodology

C. Duration of the project activity / crediting period

D. Environmental impacts

E. Stakeholders‟ comments

Annexes

Annex 1: Contact information on participants in the project activity

Annex 2: Information regarding public funding

Annex 3: Baseline information

Annex 4: Monitoring plan

Appendix

Appendix 1: Minutes of local stakeholder meeting

Appendix 2: Assumptions for Levelised tariff computation



SECTION A. General description of project activity

A.1. Title of the project activity:

>>

Replacement of electricity generated by existing 4 subcritical units of 120 MW of Koradi TPS by 1 unit of 660 MW based on supercritical technology.

Version: 01

Date: 04/04/2011

A.2. Description of the project activity:

>>

Maharashtra State Power Generation Company Limited (MAHAGENCO), Project participant, with the objective of reducing Greenhouse Gas emissions associated with coal based electricity generation. With the same overarching objective of GHG reduction, MAHAGENCO has taken the

decision to invest in super-critical technology. This will involve setting up of three new unit of 660 MW each based on super-critical technology out of which 1X660 MW is presented under this PDD and 2X660 MW will be presented in the separate PDD..

Koradi Power Station at a glance

The Koradi Power station began operations in 1974 and is one of the nine active power stations operated by MAHAGENCO, a subsidiary of Govt. of Maharashtra owned by Maharashtra State Electricity Board (MSEB). The plant operates 7 units and has a total installed capacity of 1100 MW. The details of commissioning and project life are as follows:

Unit No Installed Capacity Commissioning date

1 120 13/06/1974

2 120 24/03/1975

3 120 03/03/1976

4 120 22/07/1976

5 200 15/07/1978

6 210 30/03/1982

7 210 13/01/1983

Purpose of the project activity

The project activity involves installation of one new unit of 660 MW based on supercritical technology using coal as fuel. The project activity would thus displace electricity in the grid and/or in other power plants that would be built in the absence of the project activity, identified in accordance to ACM0013.



The project activity due to utilization of efficient power generation technology will result in efficient use of fuel (coal) as compared to the existing subcritical units at Koradi and other similar project activities undertaken in the previous five years, in similar social, economic, environmental and technological circumstances, and whose performance is among the top 15% per cent of their category (based on sub critical technology). The project activity will therefore lessen GHG emissions and contribute towards environmentally sustainable development.

Project scenario

In post project scenario 1 x 660 MW supercritical coal based power plant would be generating electricity at its designed level of performance (as provided by technology supplier) The project activity will also reduce consumption of fossil fuel due to use of efficient technology. In the project activity scenario, vacant land available within the boundary wall of the existing Koradi TPS will be utilised to accommodate the proposed units along with all its auxiliary systems.

For meeting the water requirements of the replacement project water shall be procured partly from Pench Dam and Nagpur City sewage treatment plant. Sewage waste water of Nagpur City shall be suitably treated and then utilised for cooling water circuit of the extension station. However, Power Cycle Make-up and Potable water requirements shall be met from the existing arrangements for water from Pench Dam.

Baseline Scenario:

For the project activity, the applied baseline methodology ACM0013 version 04.0 is based on the approach 48 (b) of CDM modalities and procedures for determining the baseline scenario.

The project activity is installation of a new grid-connected power plant based on supercritical technology utilizing coal as fuel. The baseline scenario is that the electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected subcritical power plants operating on coal as fuel.

As indicated in the Section B.4, most plausible baseline scenario is power generation using subcritical technology and coal as a fuel. As a result of super-critical parameters, operational efficiency of the project activity is higher than that of identified baseline scenario resulting in lesser coal consumption and lesser CO2 emissions.

Contribution of the project activity towards sustainable development

The project activity contributes to the sustainable development of India. Sustainable development Indicators of the project activity are dealt under following four pillars of sustainable development.

Social sustainability

The project activity has generated employment for the local population during the construction as

well as operational phases of the project activity, both direct and indirect.

It has also provided an opportunity for secondary small scale entrepreneurs‟ development near the project site, such as small shops, etc. Overall, the project will result in creation of employment

opportunities thus enabling the people to have steady streams of income thus addressing issue of

livelihood. Economic sustainability



Scarcity of power restricts economic growth in a region. Project activity will address electricity

deficit situation in India. Increased electricity will support economic growth of the region and

India.

The project activity has lower specific coal consumption due to employment of superior power

generation technology resulting in fuel saving. The fuel thus saved can be used for other

applications.

Environmental sustainability

Superior power generation technology (supercritical technology) will result in lesser emissions

and thus reduce the environmental impacts of power generation in the region.

Some part of the water requirements of the project will be met by utilising the sewerage water

from Nagpur City. This will help reduce dependence on natural sources of water, thereby

contributing to water conservation.

The plant water system is designed for maximum usage of waste water to attain „zero discharge‟. Green belts have been planned on all sides to minimise impact of wind blown pollution to the

surrounding areas. Villages adjoining the ash disposal area would also be protected by green belt

buffer.

Superior technology will result in reduction in coal consumption which is a depleting natural

resource.

Technological Sustainability

The project being the first-of-its-kind to be implemented with super-critical technology, by

MAHAGENCO will assist MAHAGENCO and similar utilities in India to acquire the technical

capability and encourage capacity building among other government utilities.

New and superior technology (supercritical) will result in contributing to the skill level of

MAHAGENCO there by improving the knowledge base for the operations and maintenance of

supercritical technology based plants in India and MAHAGENCO in particular.

Superior technology will result in reduction in coal consumption which is a depleting natural

resource.

In addition to this, MAHAGENCO which is undertaking the CDM project activities which is the project proponent and will own the generated CERs from the candidate CDM project activity will contribute 2% of the CDM revenue realized from the candidate CDM project for sustainable development including society / community development.

A.3. Project participants:



>>

Name of Party involved

((host) indicates a host

Party)

Private and/or public entity(ies)

project participants (as applicable)

Kind indicate if the Party

involved wishes to be

considered as project

participant (Yes/No)

India (Host Party) “Maharashtra State Power Generation Company Limited” (MAHAGENCO)

No

A.4. Technical description of the project activity:

A.4.1. Location of the project activity:

>>

Koradi in Nagpur district of Maharashtra.

A.4.1.1. Host Party(ies):

>>

India

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

>>

Maharashtra

A.4.1.3. City/Town/Community etc.:

>>

Koradi in Nagpur district

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

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

>>

Selected Location : Koradi of Nagpur District in Maharashtra.

REP1 REP2 REP3 REP4

Latitude 210 14'6.3"N 210 14'6.3"N 210 14'1.86"N 210 14'1.86"N

Longitude 790 5'25.3"E 790 5'42"E 790 5'42"E 790 5'25.3"E

Nearest Major Towns : Nagpur



Seismic Zone : Zone-II as per IS 1893-1984.

Access by Road : From Nagpur-Bhopal National Highway (NH-69).

Access by Rail :The coal rakes shall be moved upto Nagpur on the Kolkata-Mumbai main line and then to Kalamna on the Nagpur-Ramtek (BG) section.

Access by Air :Nagpur Airport.

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

>>

The project activity will principally fall in Scope Number 1, Sectoral scope – energy industries (renewable/ non-renewable sources) being a Grid-connected electricity generating project using non-renewable fuel in energy industries.

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

>>

For the proposed replacement project, the configuration has been planned with overall capacity of 660 MW with supercritical steam parameters by the project proponent. The choice of supercritical steam parameters in once-through boiler is prima facie guided by the improvement in combustion efficiency.

Fossil fuel-fired (coal) power plants use steam to provide the mechanical power to electrical generators. Steam at super critical pressure and temperature expands through various stages of a turbine, transferring energy to the rotating turbine blades. The turbine is mechanically coupled to a generator, which produces electricity. The project activity power plant operates on single reheat steam cycle with regenerative feed heating system. The thermodynamic cycle will consist of super critical Boiler, the Steam Turbine, the condenser, the condensate extraction and boiler feed systems, the condensate and feed water heaters along with all other necessary equipment for single reheat, regenerative feed heating system.

It can be seen from the figure below, point 1 indicates the super-critical steam conditions. After expansion through the High Pressure (HP) Turbine, at point 2, steam enters the re-heater and then into the Low Pressure (LP) Turbine. From points 4 to 5, the steam condenses to form saturated liquid. It is then mixed with make up water, if required and pumped to a de-aerator. The Boiler Feed Pump pumps the water from the de-aerator to the boiler (6 to 7).From the diagram it is evident that in case of super-critical steam parameters the turbine work i.e. (1-4) is more than in case of subcritical for the same heat input to the boiler thus decreasing the heat rate and increasing the efficiency of the power plant as compared to that of a subcritical technology based power plant. The steam is generated by a boiler at super-critical pressure and temperature, where pure water passes through a series of tubes to capture heat from the furnace and gets converted to super heated steam.



The heat in the furnace is normally provided by burning fossil fuel (e.g. coal, fuel oil etc). The coal is fed to boiler after pulverization in the coal mills. The pulverized coal is transported to burners through primary air which is heated in Air Pre-heaters. The secondary air (preheated) is fed to boilers for complete combustion. The fuel firing normally takes place in the range of 1200-1300°C. The combustion chamber is enclosed by tubes termed as water wall tubes and these tubes form the gas tight chamber and water cooled furnace. The bottom ash is collected in the furnace bottom and fly ash carried along with the flue gases is collected in ESP hoppers and discharged to Ash areas. The superheated steam leaving the boiler at super critical parameters then enters the steam turbine throttle, where it powers the turbine and connected generator to make electricity. After the steam expands through the HP turbine, it goes back to the boiler to get re-heated. The reheated steam then enters the LP turbine and it exits at the back end of the turbine, where it is cooled and condensed back to water in the surface condenser. This condensate is then returned to the boiler through high-pressure feed



pumps for reuse. Heat from the condensing steam is normally rejected from the condenser to a body of water or cooling tower. The power plant efficiency is typically remains around 36 to 404%.

The steam parameters and basic inputs are given hereunder:

M.S. : 256 atm (a), 568 C, 2150 TPH

R.H. : 596 C

Feed Water Temperature : 190.0 C (BFP Outlet)

Condensate Flow : 1320 TPH

Water Requirement for : 68 Cusec initial years

4

http://cea.nic.in/thermal/Special_reports/Report%20of%20the%20committee%20to%20recommend%20next%20higher%20size%20of%20c

oal%20fired%20thermal%20power%20stations.pdf

The details of power cycle equipment for 660 MW supercritical units are given below: Equipment

Details

Boiler Once-Through

Turbine 1HP+1 IP+2LP

Generator (MVA) 780

LP Heaters Three(3) to Four(4) Nos.

HP Heaters Two(2) to Three(3) Nos.

Deaerator One(1) No.

Condensate Extraction Pumps 3 x 50%

Boiler Feed Pump 2x50% of BMCR TD + 1x30% of BMCR MD

Vacuum Pumps 2 x 100%

Condensate Polishing Units 3 x 50%/4 x 33.3%

HP Bypass Valves Two(2) Nos.

LP Bypass Valves Two(2) to Four(4) Nos.

Recirculation Pumps Two(2) Nos.



Brief technical features of power generating equipments

1. Turbine Generator and auxiliaries

Type : Single reheat multi cylinder tandem

compound, Condensing steam turbine

directly driving a 3000 rpm, 2-pole, 50 Hz,

synchronous generator.

Nominal Capacity : 660,000 KW at 306 K (33 °C) condenser

cooling water temperature.

Normal Operating Frequency Range : 47.5 to 51.5 Hz

Inlet Steam Parameters: -

Main Steam Hot Reheat

Pressure, Kg/cm2 (abs.) : 247 *

Temperature, C : 565 593

Steam flow at MCR T/hr. (approx.) : 2100 *

Exhaust Pressure : 76 mm of Hg (abs.)

Steam Extractions : CRH + 5 to 7 Nos. stages from HP, IP and

LP turbines for condensate/feed water

heating (depends on manufacturer).

Type of governing : Electro-hydraulic governing with fire

resistant fluid.

Turbine HP-LP bypass system : Capacity : 60% of BMCR (or lower

capacity commensurate with minimum

main steam flow corresponding to sustained

rated main steam temp.)

Condensing Equipment : Shell and tube type, surface condenser, of

single flow design operating on re-

circulating cooling water with evapora-tive

cooling towers.

Regenerative feed heating arrangement : Three/four stages of LP heaters (U-tube

design). One spray-cum-tray type deaerator,

two parallel chains of HP heaters.

Boiler feed water pumps : 2 x 50% of BMCR capacity steam turbine-

driven BFP with booster pump & 1x30 % of

BMCR electric motor driven, horizontal,

centrifugal BFP.



Condensate extraction pumps : 3 x 50% capacity vertical, centrifugal CAN

type construction, 3.3 kV motor driven.

Generator : 776,000 KVA output at 0.85 power factor

(lagging) 3 pH, 50 Hz and * kV voltage.

2. Steam Generator and Auxiliaries

Type : Pulverized fuel, once through, two-

pass/tower type, semi-outdoor type, dry

bottom, coal-fired unit preferably with

tangential firing and with associated

auxiliaries suitable for both constant

pressure and sliding mode operation.

Nominal Capacity : 2150 Tones/Hr

Nominal Outlet Steam Parameters at BMCR :-

Main Steam Hot Reheat

Pressure (Kg/cm2) : 255 *

Temperature, C : 568 596

Steam flow, T/hr. (approx.) : 2150 *

- Steam temp. Control range : 40-100% BMCR or better.

- Super heater/Re-heater : Attemperation and tilting burner control.

temperature control

Nominal Air Heaters Capacity : 2 x 60% of BMCR.

Draft Fans : 2 x 60% capacity axial flow forced draft

(FD) fans with blade pitch control with

VFD.

2 x 60% capacity axial induced draft (ID)

blade pitch control fans with variable

frequency drive.

2 x 60% capacity P.A. Fans.

Pulverizing Mills : Slow speed large bowl or ball and race type.

Coal Firing System : Direct suspended firing with state-of-the-art

low NOX burners giving stable fire between



40-100% MCR or better.

Start-up/auxiliary fuel : Light Diesel Oil for cold start and for

support (capacity up to 10%BMCR).

A.4.4. Estimated amount of emission reductions over the chosen crediting period:

>>

Years Annual estimation of emission reductions in

tonnes of CO2e

2015-2016 215,184

2016-2017 215,184

2017-2018 215,184

2018-2019 215,184

2019-2020 215,184

2020-2021 215,184

2021-2022 215,184

2022-2023 215,184

2023-2024 215,184

2024-2025 215,184

Total estimated reductions (tonnes of CO2e) 2,151,840

Total number of crediting years 10

Annual average over the crediting period of

estimated reductions (tonnes of CO2e)

215,184

A.4.5. Public funding of the project activity:

>>

There is no Official Development Assistance (“ODA”) involved in development of the proposed CDM project activity.

SECTION B. Application of a baseline and monitoring methodology



B.1. Title and reference of the approved baseline and monitoring methodology applied to the

project activity:

>>

Approved baseline methodology ACM0013 (version 04) has been used to determine the baseline emissions and emission reduction due to the project activity. The title of this baseline methodology is

“Consolidated baseline and monitoring methodology for new grid connected fossil fuel fired

power plants using a less GHG intensive technology”.

The project activity also refers to the following

Version 5.2 of The Tool for demonstration and assessment of additionality

Version 2.1.0 of Tool to calculate the emission factor for an electricity system

B.2. Justification of the choice of the methodology and why it is applicable to the project

activity:

>>

For newly constructed power generation stations based on supercritical technology, the Approved Consolidated Methodology ACM0013 Version 4.0 “Consolidated baseline and monitoring

methodology for new grid connected fossil fuel fired power plants using a less GHG intensive technology” is applicable.

Applicability Condition Explanation

The project activity is the construction and operation of a new fossil fuel fired grid-connected electricity generation plant that uses a more efficient power generation technology than what would otherwise be used with the given fossil fuel category.

The project activity is the construction and operation of a new 660 MW grid-connected electricity generation using supercritical technology over sub critical technology that would have been used in the absence of the project activity.

One fossil fuel category should be used as main fuel in the project power plant. In addition to this main fossil fuel category, small amounts of other fossil fuel categories can be used for start-up or auxiliary purposes, but they shall not comprise more than 3% of the total fuel used annually on an energy basis.

The project activity will use coal as a main fuel category with small quantity of Oil as secondary fuel which will be less than 3% of the total fuel used annually on an energy basis.

The project activity does not include the construction and operation of a co-generation power plant.

The project activity involves only power generation.

Data on fuel consumption and electricity generation of recently constructed power plants are available.

The data of fuel consumption and electricity generation of recently constructed power plants is published by CEA and is available.

The identified baseline fuel category is used in more than 50% of total generation by utilities in

The CEA database version 6 clearly state that indentified baseline fuel category is used more



Applicability Condition Explanation

the geographical area within the host country, as defined later in the methodology, or in the entire host country. To demonstrate this applicability condition data from the latest three years shall be used. Maximum value of same fossil fuel generation estimated for three years should be greater than 50%.

than 50% of total generation by utilities in NEWNE Grid.

B.3. Description of the sources and gases included in the project boundary:

>>

As per ACM0013, spatial extent of the project boundary includes 660 MW (supercritical technology based) power generation facility and all associated equipments at project site and all power plants considered for the calculation of the baseline CO2 emission factor.

Flow diagram of the project boundary:

Represents project activity

Represents project boundary

In accordance with ACM0013, for calculating the project emissions, only CO2 emissions from fossil fuel combustion in the project plant are considered. In the calculation of baseline emissions, only CO2 emissions from fossil fuel combustion in power plant(s) in the baseline are considered.

Source Gas Included? Justification / Explanation

Super Critical Project

Metering of Energy (Ex Bus)

NEWNE electricity grid

Project activity

Emission source in the baseline scenario

(emits CO )

Electricity import/export from/to the project activity to be monitored.



Source Gas Included? Justification / Explanation

Baseline

Power generation using coal in existing subcritical units of Koradi TPS

CO2 Yes Main emission source.

CH4 No Excluded (conservative approach).

N2O No Excluded (conservative approach).

Power generation using fossil fuels in power plants connected to the western regional grid


CH4 No Excluded (conservative approach).

N2O No Excluded (conservative approach).

Project

Activity

On-site fossil fuel combustion due to the project activity


CH4 No Excluded for simplification.

N2O No Excluded for simplification.

B.4. Description of how the baseline scenario is identified and description of the identified

baseline scenario:

>>

As required under ACM0013 (version 4.0), the approach 48 (b) of CDM modalities and procedures “Emissions from a technology that represents an economically attractive course of action, taking into account barriers to investment” is being used to determine the baseline scenario. ACM0013 suggests using the following two steps to define the baseline scenario:

Step 1: Identify plausible baseline scenarios

Step 2: Identify the economically most attractive baseline scenario alternative

Both the above steps have been analysed and presented as below.

Step 1: Identify plausible baseline scenarios:

In the absence of the project activity, one or more of the following could happen:

A. The project activity not implemented as a CDM project;

B. The construction of one or several other power plant instead of the proposed project activity,

including:

1 Power generation using the same fossil fuel type as in the project activity, but

technologies other than that used in the project activity;

2 Power generation using fossil fuel types other than that used in the project activity;

3 Other power generation technologies, such as renewable power generation.

C. Import of electricity from connected grids, including the possibility of new interconnections



An important fact to note here is that the MAHAGENCO power plant (project activity) has been designed for catering to the base load requirement. It is connected to the NEWNE electricity grid, which now is part of Central Regional (CR) electricity grid.

Regulatory compliance

Electricity generation is de-licensed in India. Neither the Indian Electricity Act 2003 nor any regulation restricts the implementation of any one of the alternatives identified in the table below. Hence all the alternatives as identified in the table below are permitted by regulations.

Alternative Potential alternative conditions Permitted by

regulations

A. Project activity implemented as a project without the CDM

revenue

Yes

B. The construction of one or several other power plant instead of

the proposed project activity, including

B.1 Power generation using the same fossil fuel type as in the project

activity, but technologies other than that used in the project

activity;

B.1.1 Power generation based on subcritical technology using coal as fuel (Pit Head)

Yes

B.1.2 Power generation based on subcritical technology using coal as fuel (Non-Pit Head)

Yes

B.2 Power generation using fossil fuel types other than that used in

the project activity;

B.2.1 Power generation using Lignite as fuel Yes

B.2.2 Power generation using Natural Gas as fuel Yes

B.2.3 Power generation using Naphtha as fuel Yes

B.3 Power generation using other technologies such as

B.3.1 New power plant (s) based on Wind energy Yes

B.3.2 New power plant (s) based on nuclear power Yes

B.3.3 New power plant (s) based on run-of-river5 hydro power Yes

B.3.4 New power plant (s) based on Wind energy Yes

B.3.5 New power plant (s) based on Biomass energy Yes

C. Import of electricity from connected grids, including the

possibility of new interconnections Yes

5 Storage, reservoir type hydro has been excluded since it delivers peak in power rather than base load power



Alternative A -The project activity not implemented as a CDM project

This project is based on supercritical technology, which is first-of-its-kind in state of Maharashtra, enables Rankine cycle to be operated at higher operating temperatures and pressures (reheat steam cycle with regenerative feed heating arrangement) thereby increasing the cycle efficiency. Higher efficiency means a reduction in fuel consumption and thereby a reduction in emissions per unit of electricity generated. The supercritical technology will enhance operational efficiency over sub-critical technology, which is the most prevalent and commonly used for thermal power generation in India as identified in applicability conditions of the methodology. The alternative has been analysed further to ascertain its plausibility.

Alternative B.1 - Power generation using the same fossil fuel type as in the project activity, but

technologies other than that used in the project activity;

Alternative B.1.1 Power generation based on subcritical technology using coal as fuel (Pit Head)

Alternative B.1.2 Power generation based on subcritical technology using coal as fuel (Non-Pit

Head)

Technically there are two alternatives enlisted above operate on same thermodynamic cycle (Rankine cycle) for power generation and have similar operations. The power generation technology (subcritical) using coal as fuel is commercially available in capacity of 210 to 500 MW units each. Fossil fuel fired (coal) power plants use steam to provide the mechanical power to electrical generators. The electrical generators convert this mechanical power into electrical power. The power plant efficiency is typically around 28% to 33%6. Power generation using coal as fuel with subcritical technology is most common (baseline) scenario in India. The difference among the above three alternatives is due to the source of fuel procurement.

The unit cost of generation depends upon the cost of fuel which in-turn depends upon the location of the fuel source and its distance from the power plant. Power generation in a pit head coal based thermal power station is relatively cheaper than power generation using coal at a Non pit head generating station. But in case of Maharashtra, there are no coal mines and all coal based power plants in the state of Maharashtra are operating on coal procured from coal mines in other parts of the country. Thus possibility of setting up a pit head coal based power plant in Maharashtra is ruled out as it is not a plausible alternative to the project activity and thus not discussed any further in the PDD. The other alternative for power generation using subcritical technology using coal as fuel in a non pit head station is plausible alternatives to the project activity and has been further discussed in the PDD. These power plants continue to emit higher quantity of Green House Gases due to lower generation efficiency of subcritical technology.

Alternative B.2 - Power generation using fossil fuel types other than that used in the project

activity;

Alternative B.2.1 Power generation using Lignite as fuel

Lignite based power plants also operate on similar thermodynamic cycle as coal based power plant. The steam from the steam generator is fed to turbine for power generation, the operational features of which are similar to that of in conventional Thermal Power plant. The power generation technology

6 Page 2 of 13 of Chapter 6 in CEA general performance review

http://www.cea.nic.in/power_sec_reports/general_review/0304/chap-6.pdf




(sub-critical) using coal as fuel is most commonly available in capacity of 125 to 2507 MW units each. Fossil fuel-fired (coal/lignite) power plants use steam to provide the mechanical power to electrical generators. The electrical generators convert this mechanical power into electrical power. The power plant efficiency is typically around 28% to 33%8. Lignite based power plant like coal based power plant emit higher quantity of Green House Gases due to lower generation efficiency of sub-critical technology. This alternative has been analysed further for assessing its plausibility.

The installations of Lignite based power plants are in state of Gujarat and Gujarat. The maximum unit size that is installed in the last five years using lignite as fuel is 135 MW which is not comparable to the unit size of 660 MW. Therefore the power plant using lignite as fuel is not comparable and hence is excluded from further analysis.

Alternative B.2.2 Power generation using Natural Gas as fuel

Power generation technology using Natural Gas as fuel operates on Brayton cycle and such power plants are generally referred as combined cycle power plants. These power plants use a compressor to compress the inlet air upstream of a combustion chamber. The turbine section of the power plant powers both the generator and compressor. Gas turbines are also able to burn a wide range of liquid and gaseous fuels. The turbine‟s energy conversion efficiency typically remains low (@ 25-35 %9 when utilized as an Open (simple) cycle. The simple cycle efficiency can be increased by installing a waste heat recovery boiler onto the turbine‟s exhaust. A waste heat boiler generates steam by capturing heat form the turbine exhaust. These boilers are known as heat recovery steam generators (“HRSG”). They can provide steam at high pressure and temperature which can be used to generate power with steam turbines, which is called a combined cycle (steam and Gas turbine operation). Thus HRSG and STG increase the overall energy cycle efficiency around 50 %10 comparable to the project activity).

Alternative B.2.3 Power generation using Naphtha as fuel

There has been no Naphtha based generation power plants added in India since 1999. Hence this alternative is not considered further for arriving at the baseline scenario.

Alternative B.3: Power generation using other technologies such as

Alternative B.3.1 New power plant (s) based on Wind energy

The potential for wind energy based power generation in Maharashtra has been estimated at 4584 MW11 of which the cumulative installed capacity on 30.11.2008 is only 1837.85 MW12. Due to the

7 http://www.cea.nic.in/planning/c%20and%20e/database_publishing_ver4.zip 8 Page 2 of 13 of Chapter 6 in CEA general performance review


9

http://books.google.co.in/books?id=KJOoQm3fbEoC&pg=PT433&lpg=PT433&dq=efficiency+of+open+cycle+power+plant&source=web

&ots=HRYT81RY0h&sig=yRBE5betwGqHsZ6RQVpjrYZoQWQ&hl=en&sa=X&oi=book_result&resnum=6&ct=result

10

http://books.google.co.in/books?id=KJOoQm3fbEoC&pg=PT433&lpg=PT433&dq=efficiency+of+open+cycle+power+plant&source=web

&ots=HRYT81RY0h&sig=yRBE5betwGqHsZ6RQVpjrYZoQWQ&hl=en&sa=X&oi=book_result&resnum=6&ct=result

11 Source: Ministry of Non-Conventional Energy Sources, Government of India. http://mnes.nic.in/wpp.htm

http://www.cea.nic.in/planning/c%20and%20e/database_publishing_ver4.zip


http://books.google.co.in/books?id=KJOoQm3fbEoC&pg=PT433&lpg=PT433&dq=efficiency+of+open+cycle+power+plant&source=web&ots=HRYT81RY0h&sig=yRBE5betwGqHsZ6RQVpjrYZoQWQ&hl=en&sa=X&oi=book_result&resnum=6&ct=result




http://mnes.nic.in/wpp.htm



inherent nature of wind power (infirm nature of the wind), Load factor achieved by wind energy projects is low. Moreover wind energy generation is seasonal and intermittent during the seasons which make wind power generation projects incapable of delivering base load power. Hence the alternative is not comparable to the project activity which is implemented to cater the base load requirements of the region. Thus, wind energy based power generation cannot be strictly compared with the proposed project activity in terms of the services that it delivers and hence has been excluded as a baseline option without any further discussion.

Alternative B.3.2 New power plant (s) based on nuclear power

Electricity Generation from the nuclear power generation plants is governed by The Indian Atomic Energy Act - 1962, not The Electricity Act - 2003. Though electricity generation is de-licensed in India, nuclear based electricity generation is not available for any of the private sector entities. All the nuclear based generation facilities are commissioned by the Nuclear Power Corp. of India (NPCIL) and there is no private sector participation in any of nuclear power generation facilities commissioned in the country with its tariff unilaterally being decided by NPCIL. The most recent capacity additions in power plants in India are as follows:

S.

No

Power Station

Name

Promoter Capacity

(MW)

Date of

Commissioning

1 TAPP 4 Nuclear Power Corp. Ltd. 540.00 March, 06

2 MAPPS-1 Nuclear Power Corp. Ltd. 50.00 December, 05

There is no verifiable source of information available in public domain on the unit cost of power generation using nuclear energy. The levelized tariff of generation from nuclear energy is, however, higher than that from coal by about 15%13. As there are restrictions on the availability of data public domain in terms of regulatory process, technology, tariff approval, for the conservatives, the alternative has been excluded as a baseline option without any further discussion.

Alternative B.3.3 New power plant (s) based on run-of-river14

hydro power

Technology: Power generation using hydro power can be in two ways:

1. run-of-river plants: these deliver base-load power

2. reservoir storage based plants: these deliver peak load power

The power generation facility delivering same services as BPL plant would be run-of-river based hydro power stations. This alternative pertains to installation of 660 MW hydro power plant. Hydro power plants have operational life of 3515 years. This alternative is in compliance with all legal and regulatory requirements. It is important to note large hydro projects are known to be associated with risks of geological and hydrological uncertainties. They also cause dislocation of population and have

12 Source: Ministry of Non-Conventional Energy Sources, Government of India. http://mnes.nic.in/wp-

installed.htm 13 Projected Costs Of Generating Electricity, Update 1998 published by Nuclear Energy Agency of International Energy Agency & Organisation For Economic Co-Operation And Development

14 Storage, reservoir type hydro has been excluded since it deliver peak in power rather than base load power

15 Source: Appendix- 2, Depreciation Schedule, Page - 1, http://www.cercind.gov.in/070104/appendix_2.doc

http://mnes.nic.in/wp-installed.htm

http://mnes.nic.in/wp-installed.htm



risks of natural calamities16. Given these risks and unavailability of potential sites in India, hydro power generation is not a realistic and credible alternative to the proposed project activity.

Further generation of 660 MW in one place or installing 660 MW power plants at different locations would necessitate the construction of a dam i.e. storage type hydro project. Storage type hydro power plants primarily cater to the peak load demand which is not comparable since the project is a base load power plant. The table below further confirms this understanding.

Installed capacity (MW)

Electricity generation (GWh)

PLF obtained

2003-2004 29,50617 7533918 29.14%

2004-2005 30,94219 8472320 31.21%

2005-2006 32,18221 10129322 35.9%

The data above pertains to electricity generation from hydro power projects in India. As can be seen, the average PLF in the last three years is around 32% which is less than the 3000 hours equivalent threshold specified in the methodology, for Peak load power projects.

The table below provides details of power capacity additions in the last five years. This data indicates that out of the entire capacity of 7487 MW of hydro power plant, 93.7% (7020 MW) has been with 50 MW plus size with storage hydro thereby catering to the peak-in load rather than base load of the grid. On the contrary the project activity is a base load power plant. As per the guidelines of ACM 13, a peak load station cannot be compared to a base load power plant and thus, hydro power plants have been excluded from the analysis of baseline alternatives. In the last 5 years, the following hydro power plants have been added in the India-

Name Unit

no.

Capacity

(MW)

Grid State

Nathpa jhakri 1 250 NEWNE Himachal



16 http://www.powermin.nic.in/whats_new/pdf/hydro_power_policy_developmemt.pdf

17 Refer table no. 2.1 http://www.cea.nic.in/power_sec_reports/general_review/0405/ch2.pdf

18 http://www.cea.nic.in/power_sec_reports/general_review/0405/ch3.pdf

19 Refer table no. 2.1 http://www.cea.nic.in/power_sec_reports/general_review/0405/ch2.pdf

20 http://www.cea.nic.in/power_sec_reports/general_review/0405/ch3.pdf

21 http://www.cea.nic.in/hydro/Hydro%20Performance%20Review%20(Summary)%2006-07.pdf

22 http://www.cea.nic.in/hydro/Hydro%20Performance%20Review%20(Summary)%2006-07.pdf

http://www.powermin.nic.in/whats_new/pdf/hydro_power_policy_developmemt.pdf

http://www.cea.nic.in/power_sec_reports/general_review/0405/ch2.pdf




http://www.cea.nic.in/hydro/Hydro%20Performance%20Review%20(Summary)%2006-07.pdf

http://www.cea.nic.in/hydro/Hydro%20Performance%20Review%20(Summary)%2006-07.pdf



Name Unit

no.

Capacity

(MW)

Grid State




Tehri st -1 3 250 NEWNE Uttarakhand

Tehri st -1 4 250 NEWNE Uttarakhand

S.sarovar rbph 1 200 NEWNE Gujarat





Srisailam lbph 3 150 Southern Andhra Pradesh




Ranganadi 1 135 NEWNE Arunachal



Indira sagar 1 125 NEWNE Madhya pradesh








Chamera 1 100 NEWNE Himachal



Name Unit

no.

Capacity

(MW)

Grid State



Baspa 1 100 NEWNE Himachal



Vishnu prayag 1 100 NEWNE Uttarakhand




Dhauli ganga 1 70 NEWNE Uttarakhand




Sharavathy tail race 4 60 Southern Karnataka

Almatti dam 2 55 Southern Karnataka





S.sarovar chph 1 50 NEWNE Gujarat





Pykara alimate 1 50 Southern Tamil nadu




Name Unit

no.

Capacity

(MW)

Grid State


Largi 1 42 NEWNE Himachal



Upper sindh-ii 5 35 NEWNE Jammu & Kashmir

Kopili st.-ii 5 25 NEWNE Assam

Khopoli 1 24 NEWNE Maharashtra

Khopoli 2 24 NEWNE Maharashtra

Jog 8 21.6 Southern Karnataka

Bansagar (iii) 3 20 NEWNE Madhya pradesh

Madhikheda 1 20 NEWNE Madhya pradesh

Madhikheda 2 20 NEWNE Madhya pradesh

Bansagar (ii) 1 15 NEWNE Madhya pradesh

Bansagar (ii) 2 15 NEWNE Madhya pradesh


Bhawani kattalai barrage 1 15 Southern Tamil nadu

Bhawani kattalai barrage 2 15 Southern Tamil nadu

Bansagar (iv) 1 10 NEWNE Madhya pradesh

Bansagar (iv) 2 10 NEWNE Madhya pradesh

Likim ro 3 8 NEWNE Nagaland

Wy.canal-d 7 7.2 NEWNE Haryana

Wy.canal-d 8 7.2 NEWNE Haryana

Tawa 1 6.75 NEWNE Madhya pradesh

Tawa 2 6.75 NEWNE Madhya pradesh

Sewa-iii 1 3 NEWNE Jammu & Kashmir




Name Unit

no.

Capacity

(MW)

Grid State


Madhavamantri 1 1.5 Southern Karnataka



Chembukadavu-ii 1 1.25 Southern Kerala



Urumi 1 1.25 Southern Kerala



Alternative B.3.4 New power plant (s) based on Solar energy

Total installed capacity of solar installations in India is less than 50 MW. Power generation from utilization of solar energy like wind is intermittent in nature and is highly unreliable on account of seasonal variations. The plant load factor of commercially available PV cells is in range of 14% - 17% which makes the solar power projects incomparable to the project activity in terms of load factor achieved by the project. The alternative has been excluded as a baseline option without any further discussion.

Alternative B.3.5 New power plant (s) based on Biomass energy

Biomass based energy generation project comparable to project activity looks unlikely considering the inherent risks associated with the availability of biomass and biomass based generation in India. These are timely onset of monsoon, availability of feedstock, and complementary uses of biomass such as cooking fuel, fertilizer and fodder. The alternative has been excluded as a baseline option without any further discussion.

Wind, Solar and biomass are not a credible alternative because of them not catering to the base load requirements of the grid. Wind, solar and biomass based power generation will not qualify as a source of "base-load firm power" because such projects are not subject to the dispatch rules as the coal or gas. This is also due to the fact that there is no scheduling and dispatching of power from renewable sources - the grid accepts power generation as and when the renewable generators generate electricity.

Alternative C: Import of electricity from connected grids, including the possibility of new

interconnections

This alternative pertains to import of 660 MW of power from connected grids. This alternative is in compliance with all legal and regulatory requirements. However this is not a credible alternative as all the connected grids are power deficit.



The actual power supply position23 during the last three years of India is shows below-

Year Energy deficit (MU) % energy deficit

2003-04 39866 7.1%

2004-05 43258 7.3%

2005-06 52938 8.4%

Year % energy deficit (Northern grid)

% energy deficit (Western grid)

% energy deficit (Southern grid)

% energy deficit (Eastern grid)

% energy deficit (Northern- Eastern grid)

2003-04 5.5% 10.7% 5.2% 4.9% 5.3%

2004-05 9.2% 11.3% 1.5% 2.4% 6.3%

2005-06 10.7% 13.5% 0.9% 2.6% 8.6%

It remains implied from the statistics furnished above that all the regional grids in the country are power deficit. Therefore, import of electricity from the inter-regional grid is not a plausible option.

Further, import of power from grid is subjected to other transmission issues like availability of transmission corridor for long term etc. Hence this scenario is excluded from further consideration to determine the baseline alternative of the project activity

B.5. Description of how the anthropogenic emissions of GHG by sources are reduced below

those that would have occurred in the absence of the registered CDM project activity

(assessment and demonstration of additionality):

>>

As per para B of EB 48 Annex 61, for new projects that have start date after 02/08/2008, the PP must intimate UNFCCC and the host DNA within six months of the project activity start date. The project start date is 23/09/2009, being the date of place of letter of award to BTG supplier. The PP has intimated UNFCCC and host DNA within six months of the stat date of the project activity. The evidence for same (serious consideration- intimation mails) shall be provided to DoE during site visit.

As per the decision 17/cp.7 para 43, a CDM project activity is additional if anthropogenic

emissions of greenhouse gases by sources are reduced below those that would have occurred in

absence of the registered CDM project activity. The methodology requires the project

proponent to determine its additionality based on the “Tool for the demonstration and assessment of additionality (Version 05.2)”, agreed by the CDM Executive Board.

Step1: Identification of alternatives to the project activity consistent with current laws and

regulations

Sub-step 1 a: Define alternatives to the project activity and Sub-step 1b. Consistency with

mandatory laws and regulations:

23 Power Sector scenario- CEA June, 2009



Section B.4 of PDD identifies all the plausible alternatives to the project activity which are in compliance with the current laws and regulations have been dealt in details in the previous. The 6 options which available to the project proponent after the elimination of the other alternatives are:

Potential alternative conditions Plausible

1 Project activity implemented as a project without the CDM revenue

Yes

2 Power generation based on subcritical technology using coal as fuel (Non-Pit Head)

Yes

3 Power generation using Natural Gas as fuel Yes

Step 2: Investment analysis

Sub-step 2a: Determine appropriate analysis method

Option-I: Simple cost analysis is applicable to project activities in which revenue from sale of CER is the only available revenue stream. Since the candidate project activity will sell the electricity generated to the regional CR electricity grid, simple cost analysis cannot be used

Sub-step 2b: Option II. Apply investment comparison analysis

ACM0013 version 4.0 requires: “The economically most attractive baseline scenario alternative is identified using investment analysis. The levelized cost of electricity production in $/kWh should be used as financial indicator for investment analysis. Calculate the suitable financial indicator for all alternatives remaining after Step 1. Include all relevant costs (including, for example, the investment cost, fuel costs and operation and maintenance costs), and revenues (including subsidies/fiscal incentives, ODA, etc. where applicable), and, as appropriate, non-market cost and benefits in the case of public investors.”

MAHAGENCO has chosen levelized tariff i.e., levelized cost of generation as the financial indictor for identifying the economically most attractive baseline scenarios of the 3 plausible scenarios identified under step 1 above. Levelized tariff accounts for all relevant costs, revenues and benefits that are available to investors in power sector in the country.

Further, for all power generation projects in India, levelized cost of electricity generation is one way to perform comparisons among different technologies (alternatives) since it allows to quantify, the unitary cost of the electricity (the kWh) generated during the lifetime of all the alternatives being compared. The levelized cost of electricity being a mean value, allows the immediate comparison with the cost of other alternatives. It considers the total electrical energy that the power plant will produce in its lifetime and it is divided between the total cost generated by construction investment along with the interest rate and the cash flow during construction plus the operation and maintenance cost, etc (considering everything in present money worth). The consideration of all the affecting components in present money worth in calculation of levelized cost of generation provides a level ground for comparison and justifies its use as a suitable indicator. It is also important to note that for all power generation projects in India which are evaluated by Ministry of Power, Government of India, levelized cost of generation24 is the evaluation criteria.

Levelized Tariff Analysis

24 http://powermin.nic.in/whats_new/competitive_guidelines.htm

http://powermin.nic.in/whats_new/competitive_guidelines.htm



The basic levelized cost methodology used for the proposed project activity is based on Annex 10 of “Proposed Costs of Generating Electricity” published by IEA. The levelized cost has two cost components, fixed cost and variable cost.

For the alternatives 1, 2 and 3 as identified earlier in this section, the levelized tariff has been calculated based on two major components namely fixed cost and variable cost. The decision to invest in the project was taken in the meeting dated 18/01/2008 and therefore all the assumptions that were available at the time of decision making are presented in Appendix 2:

The Summary of Levelized tariff for all plausible baseline scenarios is as follows:

S No. Plausible Baseline Scenario Levelized Tariff (INR / kWh)

1. Project activity implemented as a project without the CDM revenue

3.72

2. Power generation based on subcritical technology using coal as fuel (Non-Pit Head)

3.51

3. Power generation using Natural Gas as fuel 5.58

From the above table it can be seen that the option of coal based power plant using subcritical technology has the lowest levelized tariff of 3.51 INR/KWh and hence has been considered as the most plausible baseline scenario. It can also be seen that Levelized tariff for alternative-1 i.e. the project activity (NG) implemented without considering the CDM revenue, is among the more costly power generation alternatives.

Price of fuel, escalation rate for the fuel price, Station Heat Rate, Plant Load Factor and EPC cost are important factors which affect the unit cost of generation of electricity. Therefore, a sensitivity analysis was performed on the data above for the following factors:

1. Price of Fuel: increase and decrease in base price of fuel by 10%;

2. Station Heat Rate (“SHR”): increase and decrease by 10%; 3. Plant Load Factor (“PLF”): increase and decrease by 10%; and

4. Project cost: increase and decrease by 10%.

Sensitivity Analysis Scenario 1 Scenario 2 Scenario 3

Parameter Variation

Coal- Super critical steam (Project

activity

without CDM)

Power generation based on subcritical technology using coal as fuel (Non-

Pit Head)

Power generation using Natural gas as fuel

Total Project Cost

` -10% 3.62 3.47 5.69

base case 3.72 3.51 5.58

` +10% 3.82 3.56 5.69



SHR

` -10% 3.49 3.24 5.17

base case 3.72 3.51 5.58

` +10% 3.95 3.78 6.00

Landed Cost of Fuel

` -10% 3.49 3.25 5.17

base case 3.72 3.51 5.58

` +10% 3.95 3.78 6.00

PLF

` -10% 3.87 3.60 5.74

base case 3.72 3.51 5.58

` +10% 3.60 3.44 5.45

Step 3: Barrier Analysis

Operational Barriers

Power generation using supercritical technology is not a common practice in India. This is emphasized by the fact that in India, out of the total installed power generation capacity the coal based thermal power constitutes more than 50% of it but till date there is not a single thermal power plant in India which is operational with super-critical technology. All coal based power generation is based upon subcritical technology. No operational track record makes this technology riskier as compared to the subcritical technology. Moreover since supercritical technology is significantly different from subcritical, project activity also faces problem of availability of skilled manpower. In most of the power plant which are coming up in India and utilizing supercritical technology expert help from other nations like china, UK or USA have been sought in one or the other way. The other evident barrier due to use of supercritical technology is availability of skilled man power. As said earlier since supercritical power plant are significantly different in operations, thus extensive training is required for the personnel so that they can be well equipped with the technology25.

As indicated above that the subcritical power plants using coal as fuels are mainstay of the Indian power generation mix. Thus operations of these power plants is not hampered by lack of technical knowhow. Since subcritical technology is well established in India there is ample availability of Technical experts and skilled manpower for managing the day to day operations of these power plants which is not the case for projects using supercritical technology. Barriers due to prevailing practice

The proposed project technology is new to the Indian electricity generation. There is no track record of this technology successfully being operated in India. MAHAGENCO the state power generation utility of Maharashtra does not have sufficient familiarity with operating the technology. Compare this with the fact that in India more than 50 % of the generation is through use of subcritical technology and MAHAGENCO has already implemented 680026 MW of power generation using subcritical technology. This emphasizes that project technology has very poor penetration in Indian

25 http://pepei.pennnet.com/display_article/278416/6/ARTCL/none/none/1/Modeling-New-Coal-Projects:-

Supercritical-or-Subcritical?/

26 http://www.mahagenco.in/INSTALLED-CAPACITY-01.shtm

http://pepei.pennnet.com/display_article/278416/6/ARTCL/none/none/1/Modeling-New-Coal-Projects:-



http://www.mahagenco.in/INSTALLED-CAPACITY-01.shtm



power sector and further substantiate the uniqueness of the proposed project activity in Indian power generation sector.

Step 4: Common practice analysis

Sub-step 4a: Analyze other activities similar to the proposed project activity

As per Tools for the demonstration and assessment of additionality - Version 05.2, the plants are considered similar only if they rely on a broadly similar technology or practices, are of a similar scale, take place in a comparable environment with respect to regulatory framework and are undertaken in the relevant country/region. Currently were no power plants based on supercritical technology which is operational in India at the time of decision making though many such projects were in planning or implementation phase.

Sub-step 4b: Discuss any similar options that are occurring

Considering the fact that such a investment projects are not common for a state owned power generation company, the project activity stands unique and thus is not a common practice.

B.6. Emission reductions:

B.6.1. Explanation of methodological choices:

>>

The project activity displaces electricity in the grid and/or in other power plants that would be built in the absence of the project activity, identified in accordance to ACM0013.

Project emissions

The project activity is the on-site combustion of fossil fuels in the project plant to generate electricity. The CO2 emissions from electricity generation in the project plant (PEy) should be calculated as follows:

PEy FFi,y NCVi,yi

EFFF,CO2 (1)

Where: PEy = Project emissions in year y (tCO2)

FFi,y = Quantity of fuel type i combusted in the project plant in year y (Mass or volume unit per year)

NCVi,y = Weighted average net calorific value of fuel type i in year y (GJ per mass or volume unit)

i = Fossil fuel types used in the project plant in year y

EFFF,CO2 = CO2 emission factor of the fossil fuel type used in the project and the baseline (tCO2/GJ)



Baseline emissions

Baseline emissions are calculated by multiplying the electricity generated in the project plant from using fossil fuel types within the main fossil fuel category (EGPJ,main_FF,y)

27 with a baseline CO2 emission factor (EFBL,CO2), as follows:

CO2BL,ymain_FF,PJ,y EFEGBE (2)

and,

q

yqyq

p

ypyp

p

ypyp

NCVFCNCVFC

NCVFC

,,,,

,,

yPJ,ymain_FF,PJ, EGEG (3)

Where: BEy = Baseline emissions in year y (tCO2)

EGPJ,main_FF,y = Net quantity of electricity generated in the project plant from using fossil fuel types within the main fossil fuel category in year y (MWh)

EGPJ,y = Total net quantity of electricity generated in the project plant in year y (MWh)

EFBL,CO2 = Baseline emission factor (tCO2/MWh)

FCp,y = Quantity of fossil fuel type p consumed by the project plant in year y (Mass or volume unit)

NCVp,y = Average net calorific value of the fossil fuel type p consumed by the project plant in year y (GJ/Mass or volume unit)

FCq,y = Quantity of fossil fuel type q consumed by the project plant in year y (Mass or volume unit)

NCVq,y = Average net calorific value of the fossil fuel type q consumed by the project plant in year y (GJ/Mass or volume unit)

P = Fossil fuel types that are used in the project plant and that belong to the main fossil fuel category

Q = Fossil fuel types that are used in the project plant for auxiliary and start-up

27 This methodology allows to claim emission reductions from using fossil fuels more efficiently for power

generation, but does not account for any emission reductions from using less carbon intensive fuels. Given

that the CO2 emission factor and amount of any start-up/auxiliary fuels may differ between the project and the

baseline, the crediting of emission reductions is limited to the electricity generated from the main fossil fuel

only.



purposes)

EFBL,CO2 will be determined using the lowest value between (i) the emission factor of the technology and fuel type that has been identified as the most likely baseline scenario, and (ii) a benchmark emission factor determined based on the performance of the top 15% power plants that use the same fuel category as the project plant and any technology available in the geographical area as defined in Step 2 below.

Consequently, project participants shall use for EFBL,CO2 the lowest value among the following two options:

Option 1: The emission factor of the technology and fuel type identified as the most likely baseline

scenario under “Identification of the baseline scenario” section above, and calculated as follows:

EFBL,CO2 3.6MIN EFFF,BL,CO2;EFFF,CO2

BL

(4)

Where: EFBL,CO2 = Baseline emission factor (tCO2/MWh)

EFFF,BL,CO2 = CO2 emission factor of the fossil fuel type that has been identified as the most likely baseline scenario (tCO2/GJ)


さBL = Energy efficiency of the power generation technology that has been identified as the most likely baseline scenario

3.6 = Unit conversion factor from GJ to MWh

EF BL,CO2 = 3.6 X 92.800/0.3509 = 0.952066 TCO2/MWh= 952.066TCO@/GWh

Option 2: The average emissions intensity of all power plants j, corresponding to the power plants

whose performance is among the top 15 % of their category, using data from the

reference year v as follows:

j

j

j

CO2FF,jj

CO2BL,EG

EFNCVFC

EF (5)

Where: EFBL,CO2 = Baseline emission factor (tCO2/MWh)

FCj = Amount of fuel consumed by power plant j in the reference year v (Mass or volume unit)



NCVj = Average net calorific value of the fossil fuel type consumed by power plant j in the reference year v (GJ/Mass or volume unit)


EGj = Net electricity generated and delivered to the grid by power plant j in the reference year v (MWh)

j = The top 15% performing power plants (excluding cogeneration plants and including power plants registered as CDM project activities), as identified below, among all power plants in a defined geographical area that have a similar size, are operated at similar load and use a fuel type within the same fuel category as the project activity

For determination of the top 15% performer power plants j, the following step-wise approach is used:

Step 1: Definition of similar plants to the project activity

The sample group of similar power plants should consist of all power plants (except for cogeneration power plants28):

That use the same fossil fuel category as the project activity. This should include power

plants which use small amounts of fuels within another fossil fuel category than the main fuel

for start-up or auxiliary purposes, but these other fuels shall not comprise more than 3% of the

total fuel used annually by the sample power plant on an energy basis;

That have been constructed in the previous five years, where the last year of this 5 years

period should be the reference year v;

That have a comparable size to the project activity, defined as the range from 50% to 150% of

the rated capacity of the project plant;

That are operated in the same load category, i.e. at peak load (defined as a load factor of less

than 3,000 hours per year) or base load (defined as a load factor of more than 3,000 hours per

year) as the project activity; and

That have operated (supplied electricity to the grid) in the reference year v.

28 Cogeneration plants excluded from the sample group shall simultaneously generates heat and power in a

specific installation through the combustion of fuels, and the heat generated shall be provided to end-users

which use the heat for other purposes than power generation (e.g. industrial users, district heating, etc).

Hence, power plants that use the heat to produce extra-electricity, as it is the case in natural gas combined

cycle power plants, are not considered as cogeneration plants and shall be included in the sample group.



The sample group of plants identified consists of coal based sub-critical power plants that have a capacity between 330MW to 990MW, have been constructed in last 5 years, operate at base load and have supplied electricity to the grid in the year prior to start of the proposed project activity.

Step 2: Definition of the geographical area

The geographical area to identify similar power plants should be chosen in a manner that the total number of power plants N in the sample group comprises at least 10 plants. As a default, the grid29 to which the project plant will be connected should be used. If the number of similar plants, as defined in Step 1, within the grid boundary is less than 10, the geographical area should be extended to the country. If the number of similar plants is still less than 10, the geographical area should be extended by including all neighbouring non-Annex I countries. If the number remains to be less than 10, all non-Annex I countries in the continent should be considered.

If the necessary data on power plants of the sample group in the relevant geographical area are not available, or if there are less than 10 similar power plants in all non-Annex I countries in the continent, then data from power plants Annex I or OECD countries can be used instead for the remaining plants required to complete the sample group.

As per the above guideline, the NEWNE grid to which the project will be connected is used and the numbers of plants are sufficient (10) to carry out the analysis.

S. No. Name Unit Number Commissionin

g date

Capacity (MW)

1 SANJAY GANDHI 5 27-Aug-08 500

2 SIPAT STPS 2 27-Dec-08 500

3 SIPAT STPS 1 27-May-07 500

4 RIHAND 4 24-Sep-05 500

5 RIHAND 3 31-Jan-05 500

6 KAHALGAON 6 16-Mar-08 500

7 KAHALGAON 5 31-Mar-07 500

8 TALCHER STPS 6 6-Feb-05 500

9 VINDH_CHAL STPS 9 27-Jul-06 500

10 VINDH_CHAL STPS 10 8-Mar-07 500

29 The grid boundary is defined as per the latest version of the “Tool to calculate the emission factor for an

electricity system” approved by the Board.



Step 3: Identification of the sample group

Identify all power plants n that are to be included in the sample group. Determine the total number N of all identified power plants that use the same fuel as the project plant and any technology available within the geographical area, as defined in Step 2 above.

The sample group should also include all power plants within the geographical area registered as CDM project activities, which meet the criteria defined in Step 1 above.

The units identified above in step 2 are the latest units that have the data available in public domain.

Step 4: Determination of the plant efficiencies

Calculate the operational efficiency of each power plant n identified in the previous step. The most recent one-year data available shall be used. The operational efficiency of each power plant n in the sample group is calculated as follows:

vn,vn,

vn,

vn,NCVFC

EG6.3さ (6)

Where:

さn,v = Operational efficiency of the power plant n in the reference year v

EGn,v = Net electricity generated and delivered to the grid by the power plant n in the reference year v (MWh)

FCn,v = Quantity of fuel consumed in the power plant n in the reference year v (Mass or volume unit)

NCVn,v = Average net calorific value of the fuel type fired in power plant n in the reference year v (GJ/mass or volume unit)

3.6 = Unit conversion factor from GJ to MWh

v = Reference year v

n = All power plants in the defined geographical area that have a similar size, are operated at similar load and use a fuel type within the same fuel category as the project activity

The Plant efficiency of the selected projects is as follows:

S_NO NAME

2008-09

Net

Generation

GWh

2008-09

Absolute

Emissions

t CO2

2008-09

Specific

Emissions

t

CO2/MWh

Output

Energy

(TJ)

95%

Confiden

ce

Interval (

t co2/TJ)

Input

Energy

(TJ)

Efficienc

y



1 SANJAY GANDHI

1,612 1,611,580 1.00 5,801.69 91,800 17,366.16 33.41%

2 SIPAT STPS 3,157 3,052,833 0.97 11,365.20 91,800 32,896.91 34.55%

3 SIPAT STPS 876 838,804 0.96 3,153.60 91,800 9,038.84 34.89%

4 RIHAND 3,988 3,791,550 0.95 14,355.32 91,800 40,857.22 35.14%

5 RIHAND 3,988 3,791,550 0.95 14,355.32 91,800 40,857.22 35.14%

6 KAHALGAON

769 730,550 0.95 2,768.40 91,800 7,872.31 35.17%

7 KAHALGAON

2,111 2,005,450 0.95 7,599.60 91,800 21,610.45 35.17%

8 TALCHER STPS

3,362 3,178,918 0.95 12,101.69 91,800 34,255.59 35.33%

9 VINDH_CHAL STPS

3,741 3,531,504 0.94 13,467.60 91,800 38,055.00 35.39%

10 VINDH_CHAL STPS

4,036 3,809,984 0.94 14,529.60 91,800 41,055.86 35.39%

Step 5: Identification of the top 15% performer plants j

Sort the sample group of N plants from the power plants in a decreasing order of the operational efficiency. Identify the top performer plants j as the plants with the 1st to Jth highest operational efficiency, where the J (the total number of plants j) is calculated as the product of N (the total number of plants n identified in Step 3) and 15%, rounded down if it is decimal.30 If the generation of all identified plants j (the top performers) is less than 15% of the total generation of all plants n (the whole sample group), then the number of plants j included in the top performer group should be enlarged until the group represents at least 15% of total generation of all plants n.

All steps should be documented transparently, including a list of the plants identified in Steps 3 and 5, as well as relevant data on the fuel consumption and electricity generation of all identified power plants.

S_NO NAME UNIT_NO

Capacity

MW

2008-09 Net

Generation

(GWh)

Net Calorific

Value (KJ/Kg)

Coal Consumption

(Tons)

1 SANJAY GANDHI 5 500 1,612 15,131 1,147,732

2 SIPAT STPS 2 500 3,157 15,131 2,174,162

30 This is conservative as this limits the number of the top 15% performer plants, which will always lead to

exclusion of the least efficient plant among them.



3 SIPAT STPS 1 500 876 15,131 597,378

4 RIHAND 4 500 3,988 15,131 2,700,260

5 RIHAND 3 500 3,988 15,131 2,700,260

6 KAHALGAON 6 500 769 15,131 520,282

7 KAHALGAON 5 500 2,111 15,131 1,428,238

8 TALCHER STPS 6 500 3,362 15,131 2,263,957

9 VINDH_CHAL STPS 9 500 3,741 15,131 2,515,061

10 VINDH_CHAL STPS 10 500 4,036 15,131 2,713,388

S_NO NAME

2008-09

Net

Generation

GWh

2008-09

Absolute

Emissions

t CO2

2008-09

Specific

Emissions

t

CO2/MWh

Output

Energy

(TJ)

95%

Confiden

ce

Interval (

t co2/TJ)

Input

Energy

(TJ)

Efficienc

y

1 VINDH_CHAL STPS

3,741 3,531,504 0.94 13,467.60 92,800 38,055.00 35.39%

2 VINDH_CHAL STPS

4,036 3,809,984 0.94 14,529.60 92,800 41,055.86 35.39%

The selected projects have more than 15% of the generation of the total group size n. The calculation of the generation from the selected projects is as follows:

Total Generation of top 15%

GWh 7,777.00

% Generation of top 15%

Percentage 28%

Total absolute emissions TCo2 7,341,488.00

Baseline emission factor TCO2/GWh 944

Leakage

No leakage emissions are to be considered.



Emission reductions

To calculate the emission reductions the project participant shall apply the following equation:

yyy PEBEER (7)

Where:

ERy = Emission reductions in year y (tCO2)

BEy = Baseline emissions in year y (tCO2)

PEy = Project emissions in year y (tCO2)

B.6.2. Data and parameters that are available at validation:

Data / Parameter: EFFF,BL,CO2

Data unit: tCO2/GJ

Description: CO2 emission factor of the coal (fossil fuel type that has been identified as the most likely baseline scenario)

Source of data: IPCC default values for the coal fuel type at the lower limit of the uncertainty at a 95% confidence interval as provided in table 1.4 of Chapter1 of Vol. 2 (Energy) of the 2006 IPCC Guidelines on National GHG Inventories

Value Applied For Sub Bituminous coal : 92,800

Measurement procedures (if any):

IPCC default values

Any comment: -

Data / Parameter: さBL

Data unit: Percentage

Description: Energy efficiency of the power generation technology that has been identified as the most likely baseline scenario

Source of data: CERC Regulations for Tariff 2004

Value Applied 35.09%

Measurement procedures (if

CERC Regulations for Tariff 2004



any):

Any comment: -

Data /

Parameter:

FCj,x and FCn,v

Data unit: Tonnes Kg (1000 kg)

Description: Amount of fuel consumed by power plant j or n in the reference year v, where:

j are the top 15% performer plants among all power plants in a defined

geographical area that have a similar size, are operated at similar load and

use a fuel type within the same fuel category as the project activity and any

technology available within the geographical area, as defined in Step 2 under

“Baseline emissions” section; n are all power plants (including power plants registered as CDM project

activities) in the defined geographical area that have a similar size, are

operated at similar load and use a fuel type within the same fuel category as

the project activity and any technology available within the geographical

area, as defined in Step 2 under “Baseline emissions” section

Source of data: CERC Database version 5.0 (Source: http://www.cea.nic.in/planning/c%20and%20e/database_publishing_ver5.zip)

Value Applied: Refer table under step 5 of B.6.1.

Measurement procedures (if any):

-

Any comment: The data is taken directly from CEA database version 5.0 published by Central Electricity authority of India, Ministry of Power, Government of India

Data / Parameter: NCVj and NCVn,v

Data unit: GJ/Mass or volume unit

Description: Average net calorific value of the fossil fuel type consumed by power plant j or n in the reference year v, where:

j are the top 15% performer plants among all power plants in a defined

geographical area that have a similar size, are operated at similar load and

use a fuel type within the same fuel category as the project activity and

any technology available within the geographical area, as defined in Step 2

http://www.cea.nic.in/planning/c%20and%20e/database_publishing_ver5.zip

consultant’s final report - asian development bank...consultant’s final report project no. 41139...

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