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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
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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
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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
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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
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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
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Executive Summary
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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.
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(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.
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(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.
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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
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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
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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
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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
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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.
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(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.
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Finding in relation to project portfolio
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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.
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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
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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
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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
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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.
Host country 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.
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Host country approval
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.
Host country approval
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.
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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.
Host country approval
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
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PDD requirements
Data requirements
Applicability of approved methodology
CDM consideration
Host country approval
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
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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.
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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.
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Capacity Building
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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.
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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.
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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
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TA Progress and Near Term Opportunities
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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.
Host country approval
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
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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;
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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
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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.
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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
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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
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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
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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.
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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
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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.
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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.
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Annexure
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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
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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
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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.
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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
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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:
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>>
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
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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.
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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
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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.
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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.
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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
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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
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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
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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.
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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
CO2 Yes Main emission source.
CH4 No Excluded (conservative approach).
N2O No Excluded (conservative approach).
Project
Activity
On-site fossil fuel combustion due to the project activity
CO2 Yes Main emission source.
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
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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
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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
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(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
http://www.cea.nic.in/power_sec_reports/general_review/0304/chap-6.pdf
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
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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
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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
Nathpa jhakri 2 250 NEWNE Himachal
Nathpa jhakri 3 250 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
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Name Unit
no.
Capacity
(MW)
Grid State
Nathpa jhakri 4 250 NEWNE Himachal
Nathpa jhakri 5 250 NEWNE Himachal
Nathpa jhakri 6 250 NEWNE Himachal
Tehri st -1 3 250 NEWNE Uttarakhand
Tehri st -1 4 250 NEWNE Uttarakhand
S.sarovar rbph 1 200 NEWNE Gujarat
S.sarovar rbph 2 200 NEWNE Gujarat
S.sarovar rbph 3 200 NEWNE Gujarat
S.sarovar rbph 4 200 NEWNE Gujarat
S.sarovar rbph 5 200 NEWNE Gujarat
Srisailam lbph 3 150 Southern Andhra Pradesh
Srisailam lbph 4 150 Southern Andhra Pradesh
Srisailam lbph 5 150 Southern Andhra Pradesh
Srisailam lbph 6 150 Southern Andhra Pradesh
Ranganadi 1 135 NEWNE Arunachal
Ranganadi 2 135 NEWNE Arunachal
Ranganadi 3 135 NEWNE Arunachal
Indira sagar 1 125 NEWNE Madhya pradesh
Indira sagar 2 125 NEWNE Madhya pradesh
Indira sagar 3 125 NEWNE Madhya pradesh
Indira sagar 4 125 NEWNE Madhya pradesh
Indira sagar 5 125 NEWNE Madhya pradesh
Indira sagar 6 125 NEWNE Madhya pradesh
Indira sagar 7 125 NEWNE Madhya pradesh
Indira sagar 8 125 NEWNE Madhya pradesh
Chamera 1 100 NEWNE Himachal
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Name Unit
no.
Capacity
(MW)
Grid State
Chamera 2 100 NEWNE Himachal
Chamera 3 100 NEWNE Himachal
Baspa 1 100 NEWNE Himachal
Baspa 2 100 NEWNE Himachal
Baspa 3 100 NEWNE Himachal
Vishnu prayag 1 100 NEWNE Uttarakhand
Vishnu prayag 2 100 NEWNE Uttarakhand
Vishnu prayag 3 100 NEWNE Uttarakhand
Vishnu prayag 4 100 NEWNE Uttarakhand
Dhauli ganga 1 70 NEWNE Uttarakhand
Dhauli ganga 2 70 NEWNE Uttarakhand
Dhauli ganga 3 70 NEWNE Uttarakhand
Dhauli ganga 4 70 NEWNE Uttarakhand
Sharavathy tail race 4 60 Southern Karnataka
Almatti dam 2 55 Southern Karnataka
Almatti dam 3 55 Southern Karnataka
Almatti dam 4 55 Southern Karnataka
Almatti dam 5 55 Southern Karnataka
Almatti dam 6 55 Southern Karnataka
S.sarovar chph 1 50 NEWNE Gujarat
S.sarovar chph 2 50 NEWNE Gujarat
S.sarovar chph 3 50 NEWNE Gujarat
S.sarovar chph 4 50 NEWNE Gujarat
S.sarovar chph 5 50 NEWNE Gujarat
Pykara alimate 1 50 Southern Tamil nadu
Pykara alimate 2 50 Southern Tamil nadu
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Name Unit
no.
Capacity
(MW)
Grid State
Pykara alimate 3 50 Southern Tamil nadu
Largi 1 42 NEWNE Himachal
Largi 2 42 NEWNE Himachal
Largi 3 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
Almatti dam 1 15 Southern Karnataka
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
Sewa-iii 2 3 NEWNE Jammu & Kashmir
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Name Unit
no.
Capacity
(MW)
Grid State
Sewa-iii 3 3 NEWNE Jammu & Kashmir
Madhavamantri 1 1.5 Southern Karnataka
Madhavamantri 2 1.5 Southern Karnataka
Madhavamantri 3 1.5 Southern Karnataka
Chembukadavu-ii 1 1.25 Southern Kerala
Chembukadavu-ii 2 1.25 Southern Kerala
Chembukadavu-ii 3 1.25 Southern Kerala
Urumi 1 1.25 Southern Kerala
Urumi 2 1.25 Southern Kerala
Urumi 3 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.
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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
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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
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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
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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
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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)
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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.
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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)
EFFF,CO2 = CO2 emission factor of the fossil fuel type used in the project and the baseline (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)
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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)
EFFF,CO2 = CO2 emission factor of the fossil fuel type used in the project and the baseline (tCO2/GJ)
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.
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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.
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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
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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.
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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.
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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
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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