Document of The World Bank

Report No: 43378-IN

PROJECT APPRAISAL DOCUMENT

ON A

PROPOSED LOAN

IN THE AMOUNT OF US$180 MILLION

AND A PROPOSED GRANT FROM THE GLOBAL ENVIRONMENT FACILITY TRUST FUND

IN THE AMOUNT OF US$45.4 MILLION

TO THE

REPUBLIC OF INDIA

FOR A

COAL FIRED GENERATION REHABILITATION PROJECT

May 22, 2009

Sustainable Development Department India Country Management Unit South Asia Region This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

CURRENCY EQUIVALENTS

(Exchange Rate Effective December 31, 2008)

Currency Unit = Indian Rupee Rs. 44 = US$1

US$ 0.02273 = Rs. 1

FISCAL YEAR April 1 – March 31

ABBREVIATIONS AND ACRONYMS

ABT Availability Based Tariff GoM Government of Maharashtra BTPS Bandel Thermal Power Station GoWB Government of West Bengal C&AG Comptroller and Auditor General HERC Haryana Electricity Regulatory Commission CAGR Compounded Annual Growth Rate Hg Mercury CAS Country Assistance Strategy HPGCL Haryana Power Generation Company Limited CDM Clean Development Mechanism HSPCB Haryana State Pollution Control Board CEA Central Electricity Authority IBRD International Bank for Reconstruction and

Development CERC Central Electricity Regulatory

Commission IUFR Interim Unaudited Financial Report

CHP Coal Handling Plant KfW Kreditanstalt fur Wiederaufbau CPCB Central Pollution Control Board Km Kilometers CSR Corporate Social Responsibility KTPS Koradi Thermal Power Station EADD Environmental Audit Due Diligence

Report M&E Monitoring and Evaluation

EE R&M Energy Efficient Renovation and Modernization

MERC Maharashtra Electricity Regulatory Commission

EHS Environment, Health and Safety Mg/Nm3 Milligram per Newton cubic meter EIRR Economic Internal Rate of Return MOP Ministry of Power EMAP Environmental Management Action

Plan MPCB Maharashtra Pollution Control Board

ERP Enterprise Resource Planning MSPGCL Maharashtra State Power Generation Co Ltd ESP Electro-Static Precipitator MU Million Units = million kilowatt hours ESMAP Energy Sector Management Assistance

Program MW Mega watts

ETP Effluent Treatment Plant MYT Multi Year Tariff FIRR Financial Internal Rate of Return NAAQS National Ambient Air Quality Standards FM Financial Management NEP National Electricity Policy FOR Forum of Regulators NTPC National Thermal Power Corporation GEF Global Environment Facility NOx Nitrogen Oxides GoH Government of Haryana O&M Operations and Maintenance GOI Government of India PFC Power Finance Corporation

FOR OFFICIAL USE ONLY

This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not be otherwise disclosed without World Bank authorization.

PLF Plant Load Factor SEB State Electricity Board PM Particulate Matter Sox Sulfur Oxides PPAH Pollution Abatement and Treatment

Handbook STP Sewage Treatment Plant

PTPS Panipat Thermal Power Station TA Technical Assistance R&D Research and Development TPS Thermal Power Station R&M Renovation and Modernization WBERC West Bengal Electricity Regulatory

Commission RLA Residual Life Assessment WBPCB West Bengal Pollution Control Board RSA Rapid Social Assessment WBPDCL West Bengal Power Development

Corporation Limited

Vice President: Isabel M. Guerrero Country Director: N. Roberto Zagha

Sector Director: John Henry Stein Sector Manager: Salman Zaheer

Task Team Leader: Mikul Bhatia

INDIA COAL FIRED GENERATION REHABILITATION PROJECT

CONTENTS

Page

A. STRATEGIC CONTEXT AND RATIONALE ................................................................. 1

1. Country and sector issues.................................................................................................... 1

2. Rationale for Bank involvement ......................................................................................... 5

3. Higher level objectives to which the project contributes.................................................... 6

B. PROJECT DESCRIPTION ................................................................................................. 7

1. Lending instrument ............................................................................................................. 7

2. Project development objective and key indicators.............................................................. 7

3. Project global environment objective and key indicators ................................................... 7

4. Project components............................................................................................................. 8

5. Lessons learned and reflected in the project design.......................................................... 10

6. Alternatives considered and reasons for rejection ............................................................ 11

C. IMPLEMENTATION ........................................................................................................ 12

1. Partnership arrangements.................................................................................................. 12

2. Institutional and implementation arrangements................................................................ 13

3. Monitoring and evaluation of outcomes/results................................................................ 14

4. Sustainability..................................................................................................................... 15

5. Critical risks and possible controversial aspects............................................................... 16

6. Loan/grant conditions and covenants................................................................................ 19

D. APPRAISAL SUMMARY ................................................................................................. 21

1. Economic and Financial Analysis..................................................................................... 21

2. Technical........................................................................................................................... 22

3. Fiduciary ........................................................................................................................... 23

4. Social................................................................................................................................. 25

5. Environment...................................................................................................................... 26

6. Safeguard policies............................................................................................................. 27

7. Policy Exceptions and Readiness...................................................................................... 28

Annex 1: Country and Sector Background .............................................................................. 29

Annex 2: Major Related Projects Financed by the Bank and Other Agencies..................... 37

Annex 3: Results Framework and Monitoring ........................................................................ 39

Annex 4: Detailed Project Description...................................................................................... 42

Annex 5: Project Costs ............................................................................................................... 51

Annex 6: Implementation Arrangements ................................................................................. 53

Annex 7: Financial Management and Disbursement Arrangements..................................... 55

Annex 8: Procurement Arrangements ...................................................................................... 77

Annex 9: Economic and Financial Analysis ............................................................................. 87

Annex 10: Safeguard Policy Issues.......................................................................................... 110

Annex 11: Project Preparation and Supervision ................................................................... 121

Annex 12: Documents in the Project File ............................................................................... 123

Annex 13: Statement of Loans and Credits............................................................................ 124

Annex 14: Country at a Glance ............................................................................................... 128

Annex 15: Governance and Accountability Action Plan....................................................... 130

Annex 16: Incremental Cost Analysis ..................................................................................... 143

Annex 17: STAP Review and Responses ................................................................................ 156

Annex 18: Map .......................................................................................................................... 161

INDIA

COAL FIRED GENERATION REHABILITATION PROJECT

PROJECT APPRAISAL DOCUMENT

SOUTH ASIA

SASDE

Date: May 22, 2009 Country Director: N. Roberto Zagha Sector Manager/Director: Salman Zaheer Project ID: P100101 Environmental Assessment: Partial Assessment Lending Instrument: Specific Investment Loan

Team Leader: Mikul Bhatia Sectors: Power (100%) Themes: Infrastructure services for private sector development (P);Regulation and competition policy (S)

Global Supplemental ID: P100531 Lending Instrument: Specific Investment Loan Focal Area: C-Climate change Environmental Assessment: Partial Assessment Supplement Fully Blended?: Yes

Team Leader: Mikul Bhatia Sectors: Power (100%) Themes: Infrastructure services for private sector development (P);Regulation and competition policy (S)

Project Financing Data [X] Loan [ ] Credit [X] Grant [ ] Guarantee [ ] Other: For Loans/Credits/Others: Total Bank financing (US$m.): 180.00 Proposed terms: IBRD Loan with variable spread, 30 year maturity, including a 5 year grace period, and level repayments.

Financing Plan (US$m) Source Local Foreign Total

BORROWER/RECIPIENT 78.0 0.0 78.0 International Bank for Reconstruction and Development 0.0 180.0 180.0 Global Environment Facility (GEF) 0.0 45.4 45.4 Total: 78.0 225.4 303.4 Borrower: India Responsible Agencies: West Bengal Power Development Corporation Ltd Vidyut Unanyan Bhawan 3/C LA Block, Sector -3 Vidhan Nagar, Salt Lake Kolkata, West Bengal India 700 098 Tel: 0091-33-2339 3100; 2335 0571 Fax: 0091-33-2339 3186; 2335 0516 s.mahapatra@wbpdcl.co.in www.wbpdcl.co.in

Haryana Power Generation Company Limited Shakti Bhawan Sector - 6 Panchkula Haryana India 134109 Tel: 0091-172-256 0673 Fax: 0091-172-256 0805 jckinra@yahoo.co.in www.hpgcl.org Maharashtra State Power Generation Co Ltd Prakashgad, Plot No. G-9 Bandra (E) Mumbai Maharashtra India 400 051 Tel: 0091-22-2647 6231 Fax: 0091-22-2647 1060 md@mahagenco.in www.mahagenco.in Central Electricity Authority Ministry of Power, Government of India Sewa Bhawan, R.K.Puram New Delhi Delhi India 110066 Tel: 0091-11-26102583 Fax: 0091-11-26109212 chair@nic.in www.cea.nic.in

Estimated disbursements (Bank FY/US$m) FY 2010 2011 2012 2013 2014 2015 Annual 18.00 30.00 50.00 39.00 34.00 9.00 Cumulative 18.00 48.00 98.00 137.00 171.00 180.00

GEF Estimated disbursements (Bank FY/US$m) FY 2010 2011 2012 2013 2014 2015 Annual 5.90 8.80 12.60 8.70 7.30 2.10 Cumulative 5.90 14.70 27.30 36.00 43.30 45.40

Project implementation period: Start: July 1, 2009 End: June 30, 2014 Expected effectiveness date: December 15, 2009 Expected closing date: June 30, 2014

Does the project depart from the CAS in content or other significant respects? Ref. PAD I.C. [ ]Yes [X] No

Does the project require any exceptions from Bank policies? Ref. PAD IV.G. Have these been approved by Bank management? Is approval for any policy exception sought from the Board?

[ ]Yes [X] No

[ ]Yes [ ] No [ ]Yes [X] No

Does the project include any critical risks rated “substantial” or “high”? Ref. PAD III.E. [X]Yes [ ] No

Does the project meet the Regional criteria for readiness for implementation? Ref. PAD IV.G. [X]Yes [ ] No

Project development objective Ref. PAD II.C., Technical Annex 3 Improve energy efficiency of selected coal-fired power generation units through renovation and modernization (R&M) and improved operations and maintenance (O&M). Global Environment objective Ref. PAD II.C., Technical Annex 3 A significant co-benefit of improving energy efficiency of the selected coal-fired power generation units is the reduction of greenhouse gas emissions per kilowatt hour of electricity generated. Project description [one-sentence summary of each component] Ref. PAD II.D., Technical Annex 4 Component 1: Energy Efficient Renovation and Modernization (EE R&M) Pilots. This component would renovate and modernize 640 MW of old coal-fired power generation capacity to demonstrate energy efficient rehabilitation approaches. Component 2: Technical Assistance. The technical assistance component of the project is aimed at providing support in implementation of EE R&M pilots, developing a pipeline of EE R&M interventions, addressing barriers to EE R&M projects and strengthening institutional capacities of implementing agencies. Which safeguard policies are triggered, if any? Ref. PAD IV.F., Technical Annex 10 The following safeguard policies are triggered: Environmental Assessment (OP 4.01) Projects on International Waterways (OP 7.50) Significant, non-standard conditions, if any, for: Ref. PAD III.F. Board presentation: None. Loan/credit effectiveness: None. Covenants applicable to project implementation: In addition to the standard Bank covenants on project and financial management, audit and reporting requirements, and procurement, the following are the key covenants under the project:

1. Eligibility criteria and Terms & Conditions required for Bank funding of sub-components under component-1 of the project:

a) Submission of a Detailed Project Report (DPR) satisfactory to the Bank, by the participating utility, for Energy Efficiency Renovation and Modernization (EE R&M), which should be based on energy audit by qualified consultants.

b) Endorsement and disclosure by the participating utility of Environmental Audit and Due Diligence (EADD) and Rapid Social Assessment (RSA), satisfactory to the Bank, for the power plant where EE R&M generation unit is located and the adoption of a Corporate Social Responsibility (CSR) policy by the participating utility.

c) Implementation by the participating utility of satisfactory financial management arrangements, submission of an action plan to improve corporate governance and financial accountability (CGFA) satisfactory to the Bank and initiation of steps for implementation of the CGFA Action Plan satisfactory to the Bank.

d) Submission by the participating utility of a report satisfactory to the Bank on detailed review of operations and maintenance (O&M) practices including a proposed O&M improvement action plan prepared by independent consultants in consultation with the participating utility.

e) Submission by the participating utility of a Project Implementation Plan (PIP), satisfactory to the Bank, incorporating inter-alia: (a) Governance and Accountability Action Plan (GAAP); (b) Strategy to Handle Surprises; (c) Corporate Governance and Financial Accountability Action Plan; (d) Environment Mitigation Action Plan for the plant; (e) Corporate Social Responsibility (CSR) Policy; (f) O&M Action Plan proposed by consultants, and (g) Funding Plan for the EE R&M investments.

f) Submission by the participating utility of a Procurement Plan satisfactory to the Bank for the EE R&M investments.

g) Signing of a sub-project agreement (or an equivalent document) satisfactory to the Bank, by the participating utility and the relevant state government, defining on-lending and repayment terms for the loan and terms for the grants, and the contractual obligations of each party under the EE R&M project.

2. Adherence to Project Implementation Plan: Each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will take all necessary measures to adhere to the respective Project Implementation Plans (PIPs), including in particular, the following plans/documents: (a) Governance and Accountability Action Plan (GAAP); (b) Strategy to Handle Surprises; (c) Corporate Governance and Financial Accountability Action Plan; (d) Environment Mitigation Action Plan for the plant; and (e) Corporate Social Responsibility (CSR) Policy.

3. Prioritized O&M Improvement Action Plan: Within one year of loan effectiveness, each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will adopt through board approval a Prioritized O&M Improvement Action Plan (including institutional capacity strengthening), and will subsequently take all necessary measures to adhere to the plan.

4. Air Pollution: Each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will take all necessary measures to maintain post rehabilitation particulate emissions at a level not exceeding 150 mg/Nm3 for the unit which is being renovated, while striving to achieve less than 100 mg/Nm3.

5. Liquidity/Financial Sustainability of Generation Utilities: WBPDCL and MSPGCL will maintain a minimum debt service coverage ratio of 1.1.HPGCL will maintain a minimum debt service coverage ratio of 1 for the financial years 2009-10 and 2010-11 and a minimum debt coverage ratio of 1.1 thereafter.

6. Sub-project agreement for CEA: Within one month of loan effectiveness, Ministry of Power Government of India and the CEA would sign a Grant Implementation Agreement satisfactory to the Bank, defining terms for the grants and the contractual obligations of each party under the EE R&M project.

1

A. STRATEGIC CONTEXT AND RATIONALE

1. Country and sector issues

1. Power shortages in a rapidly growing economy. India recorded a 9 percent GDP growth rate for the fiscal year 2007/08, which made it one of the fastest growing emerging economies in the world that year. Following the global financial meltdown and demand recession in the advanced countries, GDP growth in India is expected to slowdown to around 7 percent in 2008/09. GDP growth may retard further in 2009/10 once the impact of the global crisis fully unfolds. The economy is expected to recover thereafter in the medium term. Government of India is seriously considering a fiscal stimulus to counteract the negative impact of global demand, so as to sustain high rates of growth. This involves stepped up investments in infrastructure, including power and transport. Power supply infrastructure and service quality have been identified as among the most binding constraints to economic growth. In 2007/08, the country faced a peak power shortage of 16.6 percent and an energy deficit of 9.9 percent1.

2. Challenges in Electricity Sector. The challenges in the electricity sector include: (i) low levels of connectivity, particularly in rural areas (only 44 percent of rural households have access to electricity)2; (ii) high coping costs of industry, with 60 percent of Indian firms relying on captive or back-up generation; (iii) limited grid supply infrastructure; limited capacity for inter-regional trade; and under-maintained state distribution systems that cannot meet demand; (iv) power shortages likely to continue with slower than needed additions of new capacity and about 25 percent of existing generation capacity in need of rehabilitation; (v) weak utility governance in most states resulting in high Aggregate Technical and Commercial (ATC) losses3; (vi) unpredictable fuel supply and costs, particularly for gas; and (vii) contribution to 50 percent of India’s carbon emissions, with reliance on indigenous coal based generation continuing and supply shortages leading to use of small inefficient and polluting back-up generators. In addition, growing concerns about energy security and high costs of energy imports have caused authorities to evaluate measures aimed at reducing non-essential or inefficient energy consumption as laid out in the 2006 Integrated Energy Policy.

3. Government strategy to address power sector challenges. Government of India (GOI) has already put in place the necessary legal and policy framework for the power sector in the form of the Electricity Act 2003, National Electricity Policy 2005 (NEP), National Tariff Policy (NTP), the setting-up of independent regulatory commissions at central and state levels, and the Integrated Energy Policy (IEP). The NEP sets ambitious targets for providing universal access to reliable and good quality power by 2012, while also highlighting the need to mitigate power shortages as well as achieving financial viability of the electricity sector. It is noteworthy that India’s policy reforms in the power sector are beginning to show results. For example, the sector’s financial performance is improving with virtually all payments to central public sector units in the power sector being made on time by state-level entities. Availability-based tariffs and tighter performance norms have helped raise plant load factors. System losses in some states have been brought down below 20 percent, and the national transmission company (POWERGRID) is successfully implementing a large-scale investment program to increase 1 Source: –Central Electricity Authority, Executive Summary April, 2008. 2 Source: Website of the Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY) program (www.rggvy.gov.in) 3 Ministry of Power Annual Report 2007-08 mentioned ATC losses of 29.89% for 2006 - 2007.

2

power exchanges between regions and states of India. Nonetheless, much remains to be done to meet the power needs of India’s growing economy. GOI is trying to address power shortage through a multipronged strategy which includes a major generation capacity addition program (around 80, 000 MW of capacity augmentation targeted by 2012), renovation and modernization (R&M) of existing coal-fired plants (about 27,000 MW of old generation capacity identified), increasing efficiency of the transmission and distribution sectors and promoting demand side measures, like use of energy efficient gadgets at consumer level.

4. Predominance of coal fired generation in India’s power mix. India currently has an installed generation capacity of 145,600 MW, of which 77,200 MW (53 percent) is coal-fired and contributes to about 80 percent of the total generation. Planned capacity addition of around 80,000 MW over the XI Plan (2007-12) is likely to be dominated by coal-fired generation plants, although other generation sources such as renewables (especially wind), large hydropower and nuclear power would also contribute notably.

Table-1: Source-wise Power Generation Capacity in India (as of July 31, 2008)

Central State Private Total Thermal 35759 47334 10022 93115

Coal 29120 42838 5241 77200 Gas 6639 3894 4183 14716 Diesel 0 602 598 1200

Nuclear 4120 0 0 4120 Large Hydro 8592 26337 1230 36159 Other Renewable Power 0 2200 9995 12195 TOTAL 48471 75871 21246 145588

All figures in MW; Source: Ministry of Power Website

5. The report on Integrated Energy Policy (IEP) (prepared by Planning Commission) examines energy demand and supply scenarios over the next 25 years to bring out the role of various energy sources and strategies for achieving greater energy access, energy availability, energy security and minimizing environmental impact4. The report suggests that coal would remain India’s primary energy source, accounting for nearly 42 percent of total energy consumption in case of a low carbon growth trajectory, going up to 65 percent in case of mostly coal based electricity generation.

6. Significant proportion of coal-fired power plants does not operate efficiently. More than half of the installed coal-fired generation capacity in India is owned by state-level utilities, while the remaining is with the central sector NTPC Ltd (formerly National Thermal Power Corporation), Damodar Valley Corporation (DVC) and private sector generation companies. Much of the state level generation capacity is relatively under-performing with average plant

4 The strategy for meeting India’s growing energy needs, as suggested by the IEP, encompasses development of nuclear, hydropower and natural gas resources, adoption of clean coal technologies (such as supercritical power plants), demand side management (reduction of transmission and distribution losses and energy efficiency measures), greater emphasis on railways for freight, improved vehicular efficiency, and development of renewable energy resources.

3

load factor (PLF) of about 70 percent (some plants have PLFs lower than 55 percent) and heat rate of about 3,000 kcal/kWh and above5.

Table-2: Distribution of Coal-Fired Generation Unit Sizes in Public Utilities in India

Up to 100 MW

100-200 MW

200-210 MW

250 MW

500 MW

Period of Original Commissioning Prior to 1970s

1970s 1970s-80s 1980s-90s 1980s

onwards Number of Units about 100 83 164 26 38 Total Installed Capacity (MW) about 5000 9555 34210 6500 19000

Source: Central Electricity Authority

7. While much of the 1970s (and older) vintage units have been or need to be retired, many of the coal-fired power plants (NTPC as well as state utility owned plants) that were commissioned in and before early1980s are now due for rehabilitation and life extension. Well-designed renovation and modernization (R&M) of these plants could potentially improve their operational efficiency and provide reliable and competitively priced electricity to the grid in a shorter span of time than needed to build new capacity6. In addition to lowering generation costs and having positive local and global environmental effects, R&M has the added advantage of: (i) not involving land acquisition and resettlement of people; (ii) being able to avail of existing coal, water supply, power transmission and other facilities and linkages; and (iii) enhancing the effective utilization of scarce fuel resources.

8. The Central Electricity Authority (CEA), the nodal technical and planning agency under the Government of India’s Ministry of Power, estimates that up to 27,000 MW of the coal-fired capacity base is in urgent need of rehabilitation now, or will be in the near future. Successful EE R&M of this capacity could potentially improve the heat rate of these plants by about 10~15 percent (from 2500~2900 kcal/kWh to about 2250~2450 kcal/kWh) thereby saving more than 10 million tons of coal per year (for the same amount of generation from these plants as now) and corresponding reduction in CO2 emissions7.

9. Significant shortfall in meeting R&M targets. Although India planned and implemented a large renovation and modernization (R&M) investment program through the late 1980s and 1990s, the program mostly covered essential repairs for plants, many of which were otherwise poorly maintained. GOI also launched the Partnership in Excellence (PiE) program during late 1990s, under which coal-fired power plants with poor availability (less than 60 percent, mainly 5 In comparison, the NTPC owned plants are more efficient and better maintained. These plants had an average PLF of about 92 percent in 2007-08 and have an average heat rate of about 2500 kcal/kWh. 6 Building a new coal based thermal plant takes about 36-42 months after the contract award, while well planned Renovation & Modernization could be completed in stages over 24-30 months, with around six months plant down time. Also, R&M of an old power plant typically costs less than 50% of an equivalent green-field coal-fired power project. 7 R&M would also result in some additional CO2 emissions through improved plant availability and increased capacity (which would lead to greater generation). This additional generation would replace the carbon emissions from marginal sources of generation from the grid. Annex-16 provides detailed calculations of emission reduction benefits from the project using GEF methodology. The direct emission reduction from rehabilitation of 640 MW of capacity under the project is estimated at 3.69 million TCO2, where as indirect impact is conservatively estimated at 11.06 million TCO2.

4

due to weak operations and maintenance (O&M) practices) partnered with stronger utilities such as NTPC and Tata Power to improve performance through adoption of better management systems and O&M practices. The program experienced mixed success with some utilities such as DVC benefitting significantly, but others showing little sustained improvement. One of the objectives of the PiE program was to assist the weak utilities in preparation and implementation of R&M activities. However, due to absence of adequate performance incentives, utility financial constraints and inter-institutional issues, the program did not achieve much success in promoting R&M of old units.

10. Since then, however, R&M requirements have increased rapidly even as the implementation of R&M schemes has slowed down. Due to a shortfall in meeting 10th plan (2002-07) R&M targets, nearly 16,000 MW of R&M schemes (across NTPC and state utility owned plants) have spilled over into the 11th plan (2007-12), which now requires R&M of nearly 27,000 MW capacity.

11. GOI response to the rehabilitation challenge. Several barriers have been identified (see Annex 1) which have hitherto deterred utilities from carrying out R&M schemes, especially with focus on energy efficiency. GOI is now trying to address some of these barriers with respect to rehabilitation of coal-fired generation. GOI’s National Electricity Policy states that renovation and modernization for achieving higher efficiency levels needs to be pursued vigorously and all existing generation capacity should be brought to acceptable performance standards (of efficiency, reliability and environmental performance). The policy also suggests closure of plants which can not be rehabilitated economically. In case of persistent poor operations and maintenance performance of plants, the policy suggests that alternate strategies including change of management may be considered. Similarly, the National Tariff Policy also encourages development of R&M projects and states that a multi-year tariff (MYT) framework may be prescribed which includes capital investments and an incentive framework to share the benefits of efficiency improvements between the generation utilities and beneficiaries (distribution companies and eventually the consumers of electricity).

12. Pilots to demonstrate energy efficient R&M approaches. In light of the large and growing pool of plants requiring R&M, the GOI has decided to revive its R&M efforts and has sought World Bank/GEF as well as KfW assistance to identify and address barriers to energy efficient renovation and modernization (EE R&M) of India’s old coal-fired power plants, including through the implementation of selected pilot investments (see Annex 4 for details). These pilots would demonstrate EE R&M approaches for eligible coal-fired generation capacity across select states, incorporating lessons from past R&M projects and international experiences. The pilots would also bring out approaches for successful implementation of R&M projects through suitable risk mitigation strategies and prudent project design and implementation. GOI has designated these pilots as Phase-I of the National R&M Program.

13. The selection of states for pilot interventions has been done in discussion with the Ministry of Power, based on the scale of R&M requirement in the state as identified by CEA and the scope for achieving better energy efficiency and environmental performance by the utility going forward. Most importantly, each participating state utility has demonstrated its willingness to participate in this pilot program and carry out independent energy audits, detailed technical design; and prepare risk mitigation strategies, monitoring and evaluation frameworks, and

5

fiduciary and safeguard requirements. The states selected for participation in the Bank project are West Bengal, Maharashtra and Haryana8.

14. In particular, the project will pilot R&M approaches, which focus not only on life extension and increased plant availability (the typical goal of R&M schemes in the past) but also on getting the highest fuel efficiency that is cost-effectively achievable. Project preparation by the candidate utilities and state authorities (including regulatory agencies) – supported by the Bank - has identified key barriers to EE R&M and put in place a framework for implementation, risk mitigation, and post-rehabilitation operations and maintenance (O&M). The proposed project would test this framework and make course corrections (as needed) to enhance the prospects for a successful scale-up.

15. Scaling Up energy efficient R&M approaches. As this pilot program (Phase-I of the National R&M Program) gets rolling, the GOI will analyze the lessons from project preparation and implementation to develop the subsequent phases of the wider National R&M Program, targeting the entire 27,000 MW of eligible plants. The pipeline of energy efficient R&M pilots supported by the Bank would allow challenges faced by each pilot to be addressed in the next one. Even if all pilots fail to demonstrate adequate barrier mitigation approaches (and the energy efficient R&M approaches are seen as unsuccessful), the project would demonstrate that the rehabilitation route for energy efficiency needs to be abandoned in favor of replacement of such units.

2. Rationale for Bank involvement

16. The proposed project is consistent with the Bank’s country strategy for India (see below) and the Bank is well-placed to help the GOI to design and implement an appropriately sequenced program to scale-up the R&M of its old, inefficient and polluting coal-fired power generation capacity. This would help put the sector on a lower carbon path than continuing to operate these plants at their present efficiency levels while also bridging the power demand-supply gap. The Bank has secured a commitment from GEF to provide a US$45.4 million grant for the project (subject to GEF’s appraisal) and secured grant funds to carry out comprehensive diagnostics of the barriers to effective energy efficient R&M of candidate plants. By facilitating high quality project preparation and attractive financing terms, the Bank project can mitigate the barriers which have stymied previous attempts at rehabilitating and modernizing old coal plants. While this pilot project is targeting 640 MW for EE R&M, it is expected that its success could potentially result in the GOI and states rehabilitating a significant portion of the 27,000 MW capacity already identified for rehabilitation. Some of the key areas, where the IBRD-GEF involvement is expected to make significant impact are:

8 When the Bank team started engaging with the Government of India (GOI) in 2006 on R&M of old coal fired generation units, there was little appetite from state generation utilities to take up such projects. This lack of appetite was due to limited success in the past, inherent risks/challenges in R&M projects and several barriers to R&M projects, which have been discussed in Annex-1. West Bengal was the first state to indicate interest and commitment in the project, and is now the most advanced in terms of R&M preparation for the 210 MW Unit-5 of Bandel Thermal Power Plant. Maharashtra has the largest pool of generation units which require R&M (3090 MW) as identified by the CEA. The state generation utility has planned R&M preparation activities in six units of 210MW each. Of these, R&M of one unit each is being supported by the Bank (Koradi Unit-6) and kfw (Nasik, Unit-3). Design studies for another four units are being supported through technical assistance grants under the Bank/GEF project. In the third state - Haryana - R&M is planned for Units 3&4 of the Panipat which are of 110 MW capacities. The state was selected after discussions with some other candidate states with 110 MW units (Jharkhand and Uttar Pradesh) did not materialize.

6

� Barrier Reduction Strategy for Wider Replication of Rehabilitation Projects. The IBRD-GEF intervention would inform and attempt to address barriers to rehabilitation in the selected pilot states through studies backed with international experiences, policy/regulatory dialogue and strengthening of institutional capacity. In addition, the project would help mobilize qualified contractors to bid on India’s EE R&M opportunities and demonstrate effective R&M approaches which can be replicated across the country (and possibly elsewhere).

� Quick and Low Cost Option for Augmentation of Power Supply. Given the significant gap between demand and supply of power in India, these pilots would demonstrate whether and how the rehabilitation of old coal-fired power plants can augment availability of power on competitive terms.

� Strengthening Institutional Capacity of Utilities. Bank engagement with the selected state utilities would also help build institutional capacity, especially in the areas of design and execution of R&M projects, and efficient operation and management (O&M) of plants. The selection of beneficiary entities is also consistent with the Bank’s strategy of programmatic engagements with a few select states and entities, seen as an important element of successful institutional transformation.

� Improving Environmental Performance of the Plants. In addition to reduction in carbon emissions from power plants, the project would also support improving the overall environmental performance of these plants, including particulates emission, water treatment, ash disposal and overall safeguards practices and policies in the plant – areas which sometimes do not attract adequate attention of the utility.

� Consistency with Climate Change Mitigation Objectives. The project is consistent with climate change mitigation objectives and supports an energy efficient, low carbon growth strategy for India by demonstrating cost-effective, efficiency-enhancing approaches to reduce carbon emissions from coal-fired generation.

17. The World Bank engagement in power sector in India is consistent with the GOI strategy of augmenting availability, improving efficiencies, expanding access and encouraging competitive markets. Apart from the coal fired generation rehabilitation, the Bank engagement encompasses policy discussions and projects (ongoing and under preparation) in the areas of: (i) development of renewable large hydropower projects; (ii) strengthening of transmission network for transfer of energy from surplus to deficit regions and reduce losses; (iii) improving efficiency and quality of service in state electricity transmission and distribution; and (iv) promoting the development of renewable energy for rural areas. The Bank’s main value addition will be in advancing good implementation models, and helping to create an enabling policy and institutional environment for sector development.

3. Higher level objectives to which the project contributes

18. The proposed project is consistent with India’s priorities identified for the Country Assistance Strategy (CAS) of November 14, 2009 (FY2009-2012). It supports the new CAS pillar of sustainable development through lowering the carbon foot print of energy generation in

7

the country9. Besides, the project will help remove some of the constraints on the power generation side (by alleviating power shortages), thus contributing to the GOI’s objectives of maintaining a high and sustainable growth over the medium to long term. This is consistent with the pillars of inclusive growth and sustainable development of the new CAS.

19. The proposed projects is consistent with the previous CAS suggesting that the Bank seek ways to further expand its partnership with India on national and global issues through programs financed by the GEF, Montreal Protocol and Carbon Finance. The proposed project would utilize IBRD loans in conjunction with GEF grants and Indian counterpart financing, to make a systemic impact on R&M in India – by introducing EE R&M approaches, enhancing O&M practices and strengthening energy audit practices – and hence make long-term and sustained emission reductions.

B. PROJECT DESCRIPTION

1. Lending instrument

20. IBRD Loan (US$180 million) and GEF Grant (US$45.4 million). The project is designed as a Specific Investment Loan (SIL), which would be borrowed by Government of India and passed on to the three select state power generation utilities (HPGCL, MSPGCL, and WBPDCL), through the respective state governments on back-to-back lending terms . The IBRD loan of US$180 million will have a variable spread with a final maturity of 30 years including a grace period of five years, and level repayments. The project will be co-financed with a GEF grant of US$45.4 million.

2. Project development objective and key indicators

21. The objective of the project is to improve energy efficiency of selected coal-fired power generation units through renovation and modernization (R&M) and improved operations and maintenance (O&M). The key indicators to measure the achievement of development objectives of the project will be reduction in fuel (coal and oil) consumption per unit of power generation after completion of R&M. (See Annex 3.)

3. Project global environment objective and key indicators

22. A significant co-benefit of improving energy efficiency of the selected coal-fired power generation units is the reduction of greenhouse gas emissions per kilowatt hour of electricity generated.

23. The key indicator for measuring this will be: (i) Percentage reduction in carbon dioxide emissions per kilowatt hour as a result of energy efficiency R&M in selected coal-fired power generating units; (ii) Reduction in carbon dioxide emissions as a result of energy efficiency R&M in selected coal-fired power generating units.

9 While India has a low per capita emission compared to several large countries, because of its large population base, the absolute emissions levels are second highest among the developing countries.

8

4. Project components

24. The project will have the following components: � Component 1: Energy Efficiency R&M Pilots (US$295.9 million) � Component 2: Technical Assistance (US$7.5 million)

25. The project will be financed by a combination of IBRD loans, GEF grants and generation company internal (equity) funds. The financing plan is provided in the table below.

Table 2: Financing Plan (in US$ million)

Financing Plan Component Indicative Costs GEF IBRD Equity Total

Energy Efficiency R&M Pilots 295.9 37.9 180.0 78.0 295.9Technical Assistance 7.5 7.5 - - 7.5Total 303.4 45.4 180.0 78.0 303.4

A detailed description of the project components is as follows:

Component 1: Energy Efficiency R&M Pilots (US$295.9 million)

26. This component would renovate and modernize 640 MW (four generation units of 210/110 MW) of old coal-fired generation capacity to test and demonstrate energy efficient rehabilitation approaches. Energy efficient R&M of generation units would go beyond the typical Indian practice - of restoring original generation capacity, life-extension, and improving availability - by also modifying (or replacing) some equipment and systems to enable the unit to operate with higher fuel efficiency. This component would also explore and demonstrate approaches for successful implementation of R&M projects (with a focus on energy efficiency) by addressing barriers - including through early identification and mitigation of risks.

27. The Bank and GOI have agreed to focus on 110 MW and 210 MW units which are in urgent need for R&M in India and constitute about 68 percent of the 27,000 MW identified for R&M. The following generation units have been selected for participation in the pilot project, and would constitute the three sub-components under component-1:

Sub-component-1: Unit-5, Bandel Thermal Power Plant, West Bengal (210 MW) Sub-component-2: Unit-6, Koradi Thermal Power Plant, Maharashtra (210 MW) Sub-component-3: Units-3 & 4, Panipat Thermal Power Plant, Haryana (110 MW each)

28. The project would involve phased implementation of EE R&M activities in these three states, starting with Bandel Unit-5, followed closely by Koradi Unit-6 and finally Panipat Units 3&4. Accordingly, the project preparation activities in the three states would also be phased, as indicated in Figure 1. While the preparation activities are in an advanced state in West Bengal and Maharashtra, it is expected that status of project preparation in Haryana would be measured against eligibility criteria defined in loan agreement prior to any disbursement for the state.

9

Figure 1: R&M Preparation and Implementation Timelines

Calender Year →Quarter → 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4Unit-5, Bandel, West BengalEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&MUnit-6, Koradi, MaharashtraEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&MUnits 3&4, Panipat, HaryanaConsultant ProcurementEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&M

2007 2008 2009 2010 2011 2012 2013 2014

Note: Shutdown for R&M of Units 3 &4 Panipat would be taken up sequentially in the period indicated above.

Component 2: Technical Assistance (US$7.5 million)

29. The technical assistance component of the project is aimed at providing support in implementation of EE R&M pilots, developing a pipeline of EE R&M interventions, addressing barriers to EE R&M projects and strengthening institutional capacities of implementing agencies for improved operation and maintenance practices. This component would support preparation of EE R&M for an additional five or six old 110 MW / 210 MW units (not including Unit-5 Bandel and Unit-6 Koradi which have been already funded from PHRD grants).

30. The sub-components for the technical assistance program would cover: Sub-component-1: Support for Design of Energy Efficiency R&M Sub-component-2: Support for Implementation of Pilot EE R&M Investments Sub-component-3: Support for Addressing Barriers to EE R&M Projects10 Sub-component-4: Support for Strengthening Institutional Capacities of Utilities

For detailed description of these sub-components, please refer to Annex 4.

31. The technical assistance component of the project would be coordinated closely with similar efforts by other agencies including USAID (Eco-Asia), aimed at strengthening institutional capacities for improved O&M practices and disseminating EE R&M approaches and experiences; and the Indo-German Energy Forum (KfW and GTZ), supporting preparation of

10 This is in addition to barrier reduction activities being undertaken using other sources of funding, such as Study of Options for Regulatory Treatment of R&M projects (ESMAP funded) and Study of O&M practices in Bandel and Koradi Thermal Power Plants (ESMAP funded).

10

baseline measurements for nearly 80 generation units in India with the CEA. For further details, please refer Section C1.

5. Lessons learned and reflected in the project design

32. An important lesson has been drawn from the experience of an Asian Development Bank (ADB) project that created a financing window (US$150 million at ADB’s LIBOR based lending facility), implemented through the Power Finance Corporation, which also made funds available for R&M investments with the state power sector in addition to other sector interventions. The response for financing of R&M was quite low and approximately US$100 million had to be returned. The main causes for this low response included: lack of adequate support for improvement of environmental performance of the plants, absence of financial incentives for state generators to commit to higher energy efficiency norms and practices and the prevailing power shortage situation.

33. Analysis of past GOI efforts to jumpstart R&M investments, experiences of generation utilities in India11 as well as recent experiences from similar Bank projects (such as in Turkey) led directly to the design of the current project. In fact, it was recognized upfront that this project will have to face several risks based on the past rehabilitation experience in India and abroad. Therefore, the process of risk identification and initiation of steps towards mitigation of risks started early in the project design cycle. The approach to project design and preparation is therefore reflective of the focus on risk identification and mitigation efforts. Some of the key aspects are :

• Preparation of technical design of the project by reputable consultancy firms in close collaboration with the power generation companies. The consultants were responsible for review of Residual Life Assessment reports, conducting Energy Audit studies, development and evaluation of design options to select the preferred option, preparation of detailed technical specifications and support on commercial and contractual design of the bidding process.

• Detailed review of all technical aspects of project design by a panel of technical experts with extensive experience in design and implementation of R&M projects in India and abroad (including the recent projects in Turkey and China).

• Structuring of procurement for R&M of Unit-5 of Bandel into four packages – (a) Boiler, Turbine and Generator (BTG) package, (b) Coal Handling Plant, (c) Ash Handling Plant, and (d) Electrical System Package. The decision to keep the most critical BTG elements as a single package (as against allowing two or three separate packages for these elements) was based on past R&M experience in India and abroad which assists in correct risk allocation between the client and contractors. This would allow supplier’s accountability for unit performance as a whole, while also ensuring that the designs of various sub-systems are mutually compatible.

11 Past R&M experiences of several generation utilities in India have been reviewed, including Kothagudem (Andhra Pradesh), Bhatinda (Punjab), Ahmedabad (Gujarat), Panipat (Haryana), Koradi (Maharashtra) and several NTPC interventions.

11

• Two-stage bidding for the main BTG package would allow further refinements in technical design and performance requirements based on concerns highlighted by bidders. It would also allow the client to gauge the market response to R&M projects and accommodate any concerns in contractual design which may discourage wider participation in the bid process.

• Independent implementation support and quality assurance consultants, working in collaboration with the concerned power generation utility, would be appointed for monitoring implementation progress as well as quality. These consultants would act as owner’s engineers for the power generation utility and validate all design details, material supplies and works executions. The consultants would also support decision making process to handle surprises during the course of R&M implementation.

• In the past, R&M projects in India have faced environmental concerns which were not fully addressed because of which some of the non-Bank funded projects did not find enough interest from generation utilities. For this project, detailed Environmental Audit Due Diligence (EADD) and Rapid Social Assessment (RSA) studies have been completed for R&M of units/plants in West Bengal and Maharashtra. The recommendations from the EADD studies have been included in the technical design prepared by design consultants. An action plan for implementation of recommendations from the RSA study as well as steps for mitigating additional plant level environmental concerns has been agreed with these utilities. Assessment of environmental and social aspects of Panipat power plant in Haryana is being carried out.

• Upfront preparation of a detailed strategy for handling surprises on opening the machines for R&M implementation. The strategy includes a list of possible surprises, ensuring availability of parts to minimize delays, addressing upfront the likely contractual aspects of additional supplies and works, and establishing a clear decision making framework.

• In terms of initiating steps to address some of the sector level barriers to R&M in India, ESMAP funds have been used for pursuing a “Study of Options for Regulatory Treatment of Rehabilitation Projects in India”. The first part of the study has been completed and is being disseminated to stakeholders. Another key sustainability risk from the past projects has been the lack of adequate capacity and incentives for proper operations and maintenance (O&M) of the rehabilitated units. ESMAP funds have been used for undertaking a “Study of O&M practices at Koradi and Bandel”. The study which is now in the final stages of completion also brings out a plan for strengthening O&M practices at these power plants.

• Phasing of implementation of pilot projects to allow transfer of learning from one pilot to the next.

6. Alternatives considered and reasons for rejection

34. Selection of pilot states and plants / units: The pilot states and plants/units were selected based on a review of all the plants/units identified by the Central Electricity Authority for R&M. The selection was made in discussions with Ministry of Power, Government of India, and was

12

based on the willingness of concerned utilities to comply with the criteria specified in GEF Project Brief, i.e. (a) carry out energy audits to prepare a baseline performance for the unit; (b) install the required measurement systems and submitting information on a timely basis to the Bank; (c) develop and implement, to the satisfaction of the Bank, EE R&M scheme design; (d) follow all fiduciary and safeguard requirements of the Bank; (e) demonstrate that O&M practices would be (made) adequate; (f) demonstrate financial and economic viability of the scheme.

35. Financial Intermediation Option: In preparing this project, the team explored the option of channeling IBRD/GEF funds through an intermediary such as Power Finance Corporation (PFC). However, GOI rejected this option as a result of an unsatisfactory response from state generation utilities to a similarly structured ADB project. Therefore, it was decided to shift to the standard mechanism of on-lending to state generators through the government system, so as to lower transactions costs and be more hands-on with regard to issues such as project and technical design, incorporation of energy efficiency approaches, procurement strategy, implementation support, and transferring lessons learned for a wider national program.

36. Use of a Central Agency as Project Implementation Unit: Another alternative was to consider using a central agency, such as the Central Electricity Authority (CEA), to act as the project implementation unit (PIU) which could potentially streamline the implementation arrangements and reduce the risk facing state utilities. However, the CEA is neither designated nor structured to implement projects although it will act as the nodal agency at the national level for planning and monitoring rehabilitation of power plants in India as well as for dissemination purposes.

37. Repeater Projects Option: The use of repeater projects at the state level was also considered but was rejected by GOI who wants to use this as a national demonstration project and was concerned about the transaction costs of doing multiple repeater projects within a short time period. In addition, the project includes a technical assistance component to be implemented at the national level to address barriers to EE R&M and disseminate lessons learned which could not easily fit into a state-level project.

38. Use of GEF grant for Technical Assistance only: The team also explored possibilities for GEF to be used purely for TA and barrier-reduction activities that would not involve direct financing of investment. It was found that there was no appetite in India for operational involvement that would not include investment support. There was also a consideration of not using GEF at all, but instead using other sources of technical assistance and possibly carbon finance to complement the IBRD financing. However, GEF was assessed to be a much better fit for working on front-end barrier reduction and for supporting pilots to demonstrate energy efficiency renovation techniques and technologies. Once risks are thus brought down, output-based approaches such as clean development mechanism (CDM) could be a more suitable financing instrument.

C. IMPLEMENTATION

1. Partnership arrangements

39. GEF Grants: GEF will provide US$ 45.4 million to the project to finance (i) additional cost of energy efficiency approaches in demonstration projects for EE R&M of 640 MW of

13

capacity, and (ii) technical assistance to support additional EE R&M design studies and capacity building at the generation utilities.

40. Partnership with KfW: The Bank team is coordinating closely with KfW which is preparing a similar project aimed at rehabilitation of coal-fired generation units across three utilities – WBPDCL, MSPGCL and DVC (Damodar Valley Corporation). Similar to the Bank project, in addition to demonstrating EE R&M approaches in three generation units, KfW project would also provide technical assistance support for design studies of additional units. Together, KfW and Bank would be assisting design studies for more than 10 generation units, thus creating a pipeline of R&M projects and ensuring sustained replication. Since both the agencies would be working with WBPDCL and MSPGCL, coordination of institutional capacity building efforts is envisaged. The Bank and KfW teams are also coordinating efforts at creating increased awareness on regulatory issues and addressing other barriers, by organizing symposia and workshops on these issues.

41. Collaboration with ECO-Asia (USAID) Clean Development and Climate Program (ECO-Asia CDCP): ECO-Asia is partnering with the Bank team in pursuing issues related to removal of policy and regulatory barriers to large scale rehabilitation of power plants. It is also providing the services of its regional coal advisor to work closely with the Bank team, local consultants, and State Power Generation Utilities (e.g. personnel at the Bandel / Koradi / Panipat plants) in design of R&M projects. Eco-Asia also organized a workshop in September 2008 on scaling-up R&M in India, in partnership with NTPC, CEA and the World Bank, where all the key stakeholders participated.

42. PHRD Grants: During project preparation, the Japanese Government provided a PHRD grant of US$1 million which was used for (i) initial project design consultancies (residual life assessment, energy audit, technical design and support during bidding process and bid evaluation) and (ii) environmental and social assessment studies, for Bandel and Koradi power plants.

43. ESMAP Funding: ESMAP Grant funds of US$880,000 have been used for: (i) a study of Regulatory Aspects of EE R&M projects, and (ii) a study of Operations and Maintenance practices in the states of West Bengal and Maharashtra.

44. The GEF, PHRD and ESMAP grant facilities are being managed by the Bank team working on the project.

2. Institutional and implementation arrangements

45. Role of Ministry of Power (MOP), Government of India: MOP is the key counterpart in formulation of this project as well as the formulation of the overall R&M program and policy for the country as a whole. It has been closely involved in the selection of EE R&M demonstration units and is also the key counterpart for discussions aimed at identifying measures to address barriers to R&M in India and rolling out a national program if the pilot proves successful.

46. Role of Central Electricity Authority (CEA): The Central Electricity Authority (CEA) is the technical advisory, program planning and implementation / performance monitoring agency under MOP. The CEA would be directly involved in developing the barrier reduction strategy for the roll-out of larger R&M program. It is planned that a significant part of the technical assistance funding aimed at barrier reduction and institutional capacity building would be

14

utilized in close coordination with the CEA. In addition, the CEA is responsible for sector level monitoring of power plant performance and overseeing the progress in implementation of broader R&M program in the country. The Bank team will interact closely with CEA for dissemination of the experience from demonstration projects and promotion of EE R&M approaches throughout the country.

47. Arrangements for Implementation of Project Investments: The investment component of the project will be implemented through the selected generation utilities – WBPDCL (West Bengal), MSPGCL (Maharashtra) and HPGCL (Haryana). Reputed consultants under the R&M Design assignment shall be responsible for energy audit, residual life assessment, identification of various design options, support in selection of optimal R&M design option based on a detailed cost-benefit analysis, and support in preparation of bid documents and selection of contractors. A team of staff from corporate and plant offices of the utility would be responsible for managing these activities. To supplement existing project monitoring capacity, project implementation consultants would be appointed by each utility during the implementation phase. In addition, independent third-party quality assurance consultants would be appointed to confirm achievement of project milestones and adherence to quality plan. Details of the implementation arrangements are discussed in Annexes 6, 7, and 8 (Implementation Arrangements; Financial Management and Disbursement; and Procurement, respectively).

48. Implementation Arrangements for Technical Assistance: The vast majority of technical assistance will be implemented by the state generation utilities. This includes (i) design and safeguard studies for Bank funded EE R&M pilots and for additional pipeline of R&M projects, (ii) project implementation consultancy support, (iii) support for addressing barriers to EE R&M, and (iv) capacity building aspects in the areas of O&M, corporate governance, financial management and others for enhanced sustainability and replication of EE R&M initiatives. Technical assistance for which the impact is broader than a single state utility, such as policy studies and information dissemination, and support for formulation of a wider R&M program, will be implemented by the Central Electricity Authority, Ministry of Power, Government of India. Annex 6 provides additional details.

49. Funds-Flow Arrangements: The Bank will provide the funds (IBRD loan and GEF grant) to the Government of India which will pass them to the state generating utilities /implementing agencies through the state governments, except for the relatively small part for technical assistance implemented by the Central Electricity Authority, Ministry of Power. The GOI has agreed to pass-on the loan terms for the IBRD amount and grant terms for the GEF amount to the concerned states on a back-to-back basis. The Bank would enter into a loan agreement and a grant agreement with GOI. The Bank will also enter into three project agreements, one for each implementing utility and the corresponding state government, where applicable. In addition to these agreements, the state governments will sign with the state generation utility, a sub-project agreement (or an equivalent document) acceptable to the Bank which would define the on-lending and repayment terms for the loan and terms for the grants, and the contractual obligations of each party under the EE R&M Project.

3. Monitoring and evaluation of outcomes/results

50. The outcomes / results of the project would be monitored through information gathered by the participating generation utilities, CEA and the relevant consultants as well as by regular

15

implementation progress review missions by the Bank. Information to be provided will include quarterly progress and financial management reports, annual audits of project accounts, external monitoring reports from consultants, and other such information as the Bank may reasonable require. Progress in implementation of the EE R&M demonstration pilots would be monitored based on information from the participating utilities. The post R&M energy efficiency performance of generation units would be measured through utility data as well as information provided by energy audit consultants. Reduction of barriers to EE R&M would be measured through the number of units where procurement process is initiated for R&M implementation.

51. The key project development objective (PDO) indicators are (i) Reduction in Specific Coal Consumption (adjusted to normalize calorific value of coal to 4200 kcal/kg) and (ii) Reduction in Specific Oil Consumption. The Global Environment Objective (GEO) indicator is Annual Reduction in CO2 emissions as a result of energy efficiency R&M (million TCO2) in plants financed under this project. Additional unit performance indicators such as (i) Unit Heat Rate, (ii) Unit Availability, (iii) Auxiliary Consumption, and (iv) Unit Load factor would also be monitored and shared with the Bank as a part of the regular supervision. The baseline data Unit-5 Bandel and Unit-6 Koradi is based on the detailed project reports prepared by qualified consultants. For Haryana, the baseline is indicative (based on data reported by utility in their annual report to CEA) which be updated based on the energy audit to be completed by September 2009.

52. The monitoring and evaluation results will provide critical inputs to GOI for decisions on adjustments of national policies and regulations and set up benchmarks and good practices for replication in the rest of the country. The evaluation of results and impacts of various pilot programs will be managed by CEA, MOP to ensure ownership and replication. GEF grants will be used to support the evaluation and replication under the project.

4. Sustainability

53. Sustainability of the project interventions needs to be assessed at three levels: (i) R&M Unit and Plan level, (ii) Utility level, and (iii) Program level.

54. Sustainability at Plant Level: The Project will ensure sustainability at the plant level by requiring that generation utilities demonstrate: (i) appropriate O&M capacity to sustain efficiency investments, and (ii) financial viability of investments.

55. Sustainability at Utility Level: The technical assistance component of the project would also support strengthening of institutional capacities at the participating state utilities for improved corporate management practices for wider replication of R&M projects12 and better plant management practices.

56. Sustainability at Program Level: The lessons learnt from the policy studies and demonstration projects financed under the Project will be made available widely through the outreach and information dissemination activities implemented as part of the TA component of 12 Institutional capacity strengthening would be important in Maharashtra which has the largest fleet of power plants requiring R&M among Indian states (four such units are included in the pipeline supported by the TA component). Similarly, in West Bengal, it is likely that several old units (at least 8 units of 100MW and less have been identified by the utility) would be replaced by new more efficient units. In Haryana, strengthening capacities would be critical for better O&M of plants.

16

the project. Government officials, technical consultants, plant managers (from the successful projects) will participate in workshops targeting sector stakeholders including managers of plants in other states where efficiency R&M have not yet been conducted.

57. In addition to the above, a study on options for regulatory treatment of R&M projects is being carried out, which is now in an advanced stage. The study is expected to sensitize the regulators to the various barriers (and risks) constraining R&M in India, thus enabling the regulators to allow appropriate sharing of R&M benefits between generation and distribution companies to ensure mitigation of regulatory barriers.

58. GOI plans to replicate the experience of these pilots and energy efficiency approaches for barrier reduction through the entire R&M program backlog. The focus on 110/210 MW units which are in large number in the country (about 18,500 MW already identified as requiring R&M), would help in easier replication.

5. Critical risks and possible controversial aspects

59. The overall risk rating (including reputational risk) for the project is substantial.

60. The key governance and accountability (GAC) issues are three-fold. One arises from the technical aspects of the project – i.e. the difficulty in assessing a priori the exact scope of what physical activities need to be carried out, since this cannot be fully determined until after the contractor opens up the machine, and the consequent difficulty of accurately defining technical specifications in the bid documents and assessing project costs. A second issue pertains to the level of participation in the bidding process and the risk in terms of higher than anticipated price discovery. The third revolves around weak client capacity and the inadequate decision-making framework during implementation, especially in view of possible ‘surprises’ upon opening the machines which may require contract modifications and price increases. The details on project level risks are provided in the GAAP (Annex-15) and a summary is presented below:

Risk factors

Description of risk

Ratinga of

risk

Mitigation measures

Ratinga of residual

risk Technical/design Inadequate assessment of

R&M requirements. Since design of R&M is based on energy audits and residual life assessment studies conducted several months ahead of plant shut down, a need for additional repairs may be discovered when the unit is opened during shutdown. Energy efficiency gains are not fully realized after R&M work is conducted. Deterioration in coal quality (calorific value as well as ash content) may affect environmental performance, power output and life of the

High Substantial Substantial

Participatory and thorough assessment of R&M requirements carried out by external consultants, utility personnel, and sector experts to ensure good technical design of R&M. Contracts will be designed to build flexibility to cover additional components / works that may be required for handling surprises after the opening of the plant. Same as the para above. R&M design would be based on inferior quality of coal than what is being supplied to the plant at present.

Substantial Moderate Moderate

17

Risk factors

Description of risk

Ratinga of

risk

Mitigation measures

Ratinga of residual

risk rehabilitated unit.

Project Cost Escalation

Project costs may significantly increase due to the following: (i) higher market prices due to supply constraints; (ii) impact of commodity price variation on supplies at the time of manufacture compared to contract prices; and (iii) “Surprises” discovered once the unit is opened that increases the scope of work.

Substantial

Adequate provision for price and physical contingencies has been made in the cost estimates. In addition, scenario analysis shows great resilience of decision to undertake R&M even with 20% higher project costs. (See Annex 9). GEF grant component will help mitigate the Borrower’s financial risk resulting from cost escalation.

Moderate

Regulation If actual costs are above the estimates approved by the state regulator, this will require new approvals by the regulator which may delay contract award. Regulator may not approve increase in costs and therefore the state utility will not award the contract

Substantial Substantial

Since the implementation for each state is staggered, it is anticipated that the overall project implementation period will be sufficient to accommodate several month delay for the first two states. Cost estimates for the third state could be revised to reflect the latest market prices in the original regulatory filing. The cost benefit analysis to examine viability of R&M even with increased cost will be shared with the Regulator. Substitute with another unit, if required (Maharashtra has a ready pipeline of an additional four units).

Moderate Moderate

Implementation duration, capacity and sustainability

R&M implementation period may be longer due to non-availability of key components, surprises on opening the machines and longer time to undertake the works. Limited implementation monitoring capacity of the utility may delay project implementation, or it may affect the quality of implementation. The decision making process for course correction after the machines are opened may be slow because of limited capacity of the utility staff. Weak O&M practices may

High High High

The design consultants have prepared a detailed implementation plan, which would be suitably modified/ endorsed by the selected supplier. Supplies of all key components would be ensured prior to commencement of works to reduce unit shut down periods. Key additional components to handle surprises would also be arranged based on past experiences. Liquidity Damages shall be introduced for contractor delays. Appropriately experienced implementation consultants shall be appointed to support the Utilities on technical and commercial issues through the implementation process. The decision making process at the implementing utility would be defined upfront before the start of procurement process. Also, various scenarios of possible surprises would be examined upfront to lay down the likely course of action in each case. An experienced consultant has been

Moderate Moderate Substantial

18

Risk factors

Description of risk

Ratinga of

risk

Mitigation measures

Ratinga of residual

risk adversely affect the sustainability of efficiency gains achieved as a result of R&M. Inadequate O&M may also result from insufficient funds.

appointed (funded by ESMAP) for evaluation of O&M practices and capacities at Koradi and Bandel. An O&M capacity strengthening plan is being prepared in consultation with each of these utilities (Maharashtra and West Bengal). The O&M action plan would be implemented through technical assistance funding provided by GEF. Similar approach would be adopted for Panipat (Haryana) also.

Financial management

Inadequate financial management systems may affect the ability of the utilities to provide proper accounting and reporting of project resources and expenditures.

Substantial An action plan is being prepared for improving existing FM systems in all three generation utilities to ensure greater transparency. The Bank team would continue to monitor the implementation of the FM action plan.

Moderate

Procurement Limited supplier interest in R&M projects due to the large demand for green-field power plant units across the world, which are more standardized and entail lower implementation risk than R&M projects Risk of rebid and ensuing delay due to incorrect specifications or improper qualification requirements (QR). Requirement of performance guarantees may pose a risk to the project as suppliers may not be willing to provide them. Contractual disputes due to changes in scope of work, delays on part of supplier (in supplies or works) or the client (providing shutdown, regulatory concurrence, decision making in event of surprises) and performance demonstration etc.

Substantial High High High

Pre-bid information sessions were organized, where various aspects of R&M contract structuring, functional guarantees and delivery timeframe were discussed with the twelve supplier companies that participated. Enhanced participation would be sought through wider dissemination and International Competitive Bidding. The bidding documents would consider measures to adequately balance the risks between supplier and owner. Bidders for the main BTG package to be brought on par on technical basis through two-stage bidding process. Examine QR carefully. The two-stage bidding would help assess the bidders’ feedback on the required guarantees and the opportunity would be there to adjust these to the market conditions. Strategy for handling surprises prepared in advance. Prevention of disputes through early resolution of potential issues. Definition of a clear decision making framework during implementation, including system to get an early attention from Utility senior management on potentially difficult issues. Dispute Resolution Mechanism would be specified in bid documents. Bid documents to provide clear segregation of responsibility between

Substantial Moderate Substantial Substantial

19

Risk factors

Description of risk

Ratinga of

risk

Mitigation measures

Ratinga of residual

risk Risk of possible disagreement between Bank Guidelines and regulations / orders of the Independent State Regulators. For example, West Bengal Regulations require at least two active bidders to establish adequacy of competition.

Moderate

supplier and client for shouldering residual risks. Dialogue has been initiated with the Forum of Regulators under the Regulatory Study to bring out the barriers to EE R&M emanating from regulatory treatment of such projects. Specific issues would need to be addressed in course of implementation of EE R&M projects. However in Bank funded procurement Bank’s guidelines will be applicable.

Moderate

Social and environmental safeguards

Failure of plants as a whole (as against specific units undergoing R&M) to achieve emission standards in terms of particulates and other parameters, even though efficiency gains are made. Although this project is a rehabilitation project and improvements will be made to the plants, the Panipat plant has received negative media attention in the past for its environmental and social impact on nearby villages.

Substantial Substantial

Social and environmental safeguards policies are being examined in the three power plants selected. The Bank would continue to monitor the implementation of these policies. Adopt progressive emission reductions over the project implementation period for each of the power plants to ensure compliance with the National Ambient Air Quality Standards (NAAQS). In addition to monitoring implementation of social and environmental safeguards, the Bank team has put together an environmental and social due diligence report for the Panipat plant, and will continue to closely monitor these aspects with help from the Bank’s External Affairs team

Moderate Moderate

II. Overall Risk (including Reputational Risks) Substantial a Rating of risks on a four-point scale – High, Substantial, Moderate, Low - according to the likelihood of occurrence and magnitude of potential adverse impact.

6. Loan/grant conditions and covenants

61. In addition to the standard Bank covenants on project and financial management, audit and reporting requirements, and procurement, the following are the key covenants under the project:

1. Eligibility criteria and Terms & Conditions required for Bank funding of sub-components under component-1 of the project:

a) Submission of a Detailed Project Report (DPR) satisfactory to the Bank, by the participating utility, for Energy Efficiency Renovation and Modernization (EE R&M), which should be based on energy audit by qualified consultants.

20

b) Endorsement and disclosure by the participating utility of Environmental Audit and Due Diligence (EADD) and Rapid Social Assessment (RSA), satisfactory to the Bank, for the power plant where EE R&M generation unit is located and the adoption of a Corporate Social Responsibility (CSR) policy by the participating utility.

c) Implementation by the participating utility of satisfactory financial management arrangements, submission of an action plan to improve corporate governance and financial accountability (CGFA) satisfactory to the Bank and initiation of steps for implementation of the CGFA Action Plan satisfactory to the Bank.

d) Submission by the participating utility of a report satisfactory to the Bank on detailed review of operations and maintenance (O&M) practices including a proposed O&M improvement action plan prepared by independent consultants in consultation with the participating utility.

e) Submission by the participating utility of a Project Implementation Plan (PIP), satisfactory to the Bank, incorporating inter-alia: (a) Governance and Accountability Action Plan (GAAP); (b) Strategy to Handle Surprises; (c) Corporate Governance and Financial Accountability Action Plan; (d) Environment Mitigation Action Plan for the plant; (e) Corporate Social Responsibility (CSR) Policy; (f) O&M Action Plan proposed by consultants, and (g) Funding Plan for the EE R&M investments.

f) Submission by the participating utility of a Procurement Plan satisfactory to the Bank for the EE R&M investments.

g) Signing of a sub-project agreement (or an equivalent document) satisfactory to the Bank, by the participating utility and the relevant state government, defining on-lending and repayment terms for the loan and terms for the grants, and the contractual obligations of each party under the EE R&M project.

2. Adherence to Project Implementation Plan: Each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will take all necessary measures to adhere to the respective Project Implementation Plans (PIPs), including in particular, the following plans/documents: (a) Governance and Accountability Action Plan (GAAP); (b) Strategy to Handle Surprises; (c) Corporate Governance and Financial Accountability Action Plan; (d) Environment Mitigation Action Plan for the plant; and (e) Corporate Social Responsibility (CSR) Policy.

3. Prioritized O&M Improvement Action Plan: Within one year of loan effectiveness, each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will adopt through board approval a Prioritized O&M Improvement Action Plan (including institutional capacity strengthening), and will subsequently take all necessary measures to adhere to the plan.

4. Air Pollution: Each of the three state generation utilities (WBPDCL, MSPGCL and HPGCL) will take all necessary measures to maintain post rehabilitation particulate emissions at a level not exceeding 150 mg/Nm3 for the unit which is being renovated, while striving to achieve less than 100 mg/Nm3.

5. Liquidity/Financial Sustainability of Generation Utilities: WBPDCL and MSPGCL will maintain a minimum debt service coverage ratio of 1.1.HPGCL will maintain a minimum

21

debt service coverage ratio of 1 for the financial years 2009-10 and 2010-11 and a minimum debt coverage ratio of 1.1 thereafter.

6. Sub-project agreement for CEA: Within one month of loan effectiveness, Ministry of Power Government of India and the CEA would sign a Grant Implementation Agreement satisfactory to the Bank, defining terms for the grants and the contractual obligations of each party under the EE R&M project.

D. APPRAISAL SUMMARY

1. Economic and Financial Analysis

62. The economic and financial analysis has been carried out for Unit-5 of Bandel Thermal Power Plant (BTPS) based on energy audit data and detailed project design options provided by the independent R&M design consultants. For Unit-6 of Koradi Thermal Power plant (KTPS), the energy audit studies and preparation of detailed project report (DPR) is currently underway. It is expected that the DPR would provide the detailed financial and economic analysis for various R&M options (including comparison with replacement option). Analysis for Units 3 & 4 of Panipat Thermal Power Plant (PTPS) or any other plant to be considered for the pilot program would be carried out subsequently, when inputs from design consultants are available. Rehabilitation of these units is phased out by more than one year from the Bandel and Koradi rehabilitation.

Unit-5, Bandel Thermal Power Plant

63. Economic and Financial Analysis of Project Options The analysis compares the incremental costs and benefits for the ‘R&M’, ‘New BTG (Boiler, Turbine, Generator) at Adjacent Site’ and ‘Replacement’ options with the ‘No Project’ case (continue to operate the plant as such for the remaining plant life). Technical studies carried out by WBPDCL with the assistance of technical design consultants have concluded that, the option of ‘New BTG at Adjacent Site’ is not possible for technical reasons, including space constraints at the plant. The key parameters and economic and financial rates of return for each case are provided in the table below.

Table-4: Economic and Financial Comparison of Design Options for Unit-5, BTPS

No Project R&M New BTG at Adjacent Site

Complete Replacement

Plant Life 7 years 15 years (plus 2 years

prior to R&M)

25 years (plus 3 years

prior to project)

25 years (after

commissioning) Shutdown Duration 0 months 6 months 3 months 36 months Cost per MW Nil Rs.22 million Rs.30 million Rs.45 million Capacity 210 MW 215 MW 250 MW 250 MW Unit Heat rate 2872

kcal/kWh 2456

kcal/kWh 2400

kcal/kWh 2400

kcal/kWh EIRR* - 29% Not an option 15% FIRR (Existing Tariff ) - 16.6% Not an option 13.6% * Economic benefit from increased availability of power is valued at long term marginal cost of generation from gas fired power plants.

22

64. Optimization of R&M Design. The design consultants have examined various R&M design options – including minimum essential scope, retrofit of turbine stages for improved energy efficiency and additional modifications for further enhanced energy efficiency. A detailed financial analysis has been undertaken to arrive at the most optimal technical solution for R&M.

65. Scenario Analysis. Viability of R&M project has been examined under various scenarios which include adverse implementation performance (cost escalation and time overrun) as well as adverse outcome performance (non-achievement of targeted plant performance in respect of heat rate, capacity, availability and plant life). Scenarios where adverse implementation performance and adverse outcome performance are coincident have also been examined. It is seen that with the existing tariffs, the financial rate of return varies between 8.8 percent and 16.6 percent and remains higher than the cost of capital of 8.5 percent even in the case where all adverse parameters are coincident. The economic rate of return under the same scenarios varies between 23 percent and 29 percent, and remains higher than the hurdle rate of 12 percent even in the worst scenario where all adverse parameters are coincident.

66. Regulatory scenarios. Given the uncertainty in regulatory treatment of rehabilitation projects (refer to Annex-1 for discussion on regulatory aspects), several tariff scenarios have been examined as a part of the financial analysis. The project is found to be viable under all tariff scenarios except in the cases of cost-plus tariff based on R&M design parameters (as against actual plant performance), where either the designed implementation parameters (project cost and time) or outcome performance parameters (plant life, availability, heat rate and auxiliary consumption) are not achieved. However, in the past regulators have usually considered revision of tariffs to accommodate justifiable deviations from design parameters. Therefore, this is an unlikely scenario.

67. Entity Level Financial Appraisal. The team has also carried out entity financial appraisal for the three generation utilities – WBPDCL, MSPGCL and HPGCL. Financial projections for the next 15 years have been reviewed, which indicate that the debt service coverage ratio for each of the three generation utilities is greater than 1.1 for the projection period. Details are available in Annex 9.

2. Technical

68. The project envisages using best practice designs for EE R&M schemes with energy efficiency, PLF improvement and life extension as primary criteria. Given the difficulty in designing technical specifications for EE R&M schemes, in part due to the risk of surprises upon opening the unit, significant upfront studies are being carried out to feed into the technical specifications for each plant. These include: residual life assessments, energy audits, detailed project reports (which also include the economic and financial analysis justifying the recommended design), and environmental audits (to ensure environmental compliance is included in the design).

69. The EE R&M scheme for the first pilot (Unit-5 in BTPS - West Bengal) has been developed by consultants well versed with international and national best practices and in consultation with the client Utility. The detailed project report prepared on this basis, have been

23

reviewed by the Bank team. All underlying studies have also been completed and technical specifications are being finalized by the client. For the second unit (Unit-6 in KTPS - Maharashtra), the environmental audit and energy audit have been completed and the final report accepted. The draft detailed project report (DPR) has been submitted by the consultants and is currently under review. In line with the staggered implementation approach, the studies for other pilots will be completed during the first year of project implementation.

3. Fiduciary

70. Financial Management WBPDCL and MSPGCL have financial management systems which are considered adequate, to account for and report on the project resources and expenditures accurately. However, these systems need to be further strengthened for meeting the needs of the entities as detailed later. Action plans for enhancing corporate governance and financial accountability (CGFA) arrangements for the two companies have been prepared and agreed as a part of the preparation of this project (refer Table-6 in Annex-7). Actions have been initiated on some of the critical issues and the balance will be implemented during the implementation of the project. HPGCL’s financial management systems, corporate governance and financial accountability arrangements are in the process of being assessed and a detailed time-bound action plan will be mutually agreed thereafter, for strengthening and enhancing these arrangements. Agreement on action plan and initiation of steps for implementation of the action plan will be an eligibility condition for the component implemented by HPGCL.

71. All R&M related project costs and expenditures will be paid for and recorded in the books of the respective state utilities (MSPGCL, WBPDCL and HPGCL) in accordance with their accounting policies and procedures. The technical assistance, in form of consultancies (about six in number) will be paid by CEA, in line with the accounting policies and procedures detailed in their operations manual.

72. Under this project, the Bank will finance four large Renovation & Modernization (R&M) contracts for each of the three coal fired generation plants.13 The number of transactions under the project is expected to be few, but large and bulky. All contractual payments will be made after due verification of the bills in accordance with the procedures laid down by the companies in the project implementation plans and their delegation of powers. There would be an independent implementation support consultant and a quality assurance consultant - both to be employed by each of the three companies. The implementation support consultant would strengthen the contract management and project monitoring capabilities of the utilities. The quality assurance consultants would verify the achievement of contractual milestones to enable and certify payment to suppliers. Under the project the companies will prepare separate project financial statements, which will help in distinguishing costs financed by the proposed loans.

73. The project funds (IBRD and GEF grant) will flow from World Bank to GOI. In line with normal practices, an appropriate budgetary line item will be established by DEA (CAAA) for external funds, and similarly appropriate arrangements will be made on the expenditure side for

13 HPGCL has expressed a preference to go for a single large package instead of four, though this would be finalized after the Detailed Project Report (DPR) is finalized and the final packing decision would also reflect the experience from WBPDCL and MSPGCL where four packages would be procured.

24

transfer of these proceeds to the states (by way of regular channel of ‘Additional Central Assistance’). GOI will pass on these funds to the respective states (West Bengal, Maharashtra and Haryana) on terms and conditions (interest rates, repayment terms, foreign currency exchange rate risk) which mirror the IBRD and GEF terms (i.e. on a back-to-back basis) within two weeks of receipt of funds. The states will also transfer, within two weeks of receipt, these proceeds to the respective utilities (WBPDCL, MSPGCL, HPGCL) on terms which mirror the IBRD/GEF terms, including the interest rates, repayment terms and the foreign currency exchange rate risk. The respective state governments will also need to make suitable budgetary provisions on receipt / expenditure side to receive/ make transfer of these moneys. WBPDCL and MSPGCL have expressed preference for direct payments by the Bank for R&M contracts. The remaining entities – CEA and HPGCL have preference for forecast based advance and replenishments, although direct payment options will be available to them.

74. Disbursements would be made by the Bank on the basis of quarterly Interim Unaudited Financial Reports (IUFRs), which would forecast the expenditures for two quarters and report the actual for past quarter and cumulative till date. IBRD/GEF funds for R&M contracts will be disbursed on a pro-rata basis, and the equity component will also be brought in by the company on a pro-rata basis. The report would also provide contract-wise details of the financial progress and the physical progress under the project.

75. Designated Account: An account (denominated in USD) will be established in RBI by Government of India (GOI) to receive the Bank funds. The generating companies shall established separate bank accounts for these rehabilitation projects. The project’s financial arrangements would be largely handled by finance staff at corporate headquarters with assistance from the relevant units. The IBRD/GEF financed project will be subject to internal audit (under agreed terms of reference) and its reports will be available to the IBRD, on request. The three utities will submit (i) audited entity accounts and audit reports and (ii) audited project financial statements and audit report to the Bank which will be audited by an independent firm of chartered accountants, acceptable to the Bank, under agreed terms of reference. CEA will submit audited project accounts in respect of component 2(d). The audited project financial statements would separately identify each component under the project, its progress and the funding sources for each of the contracts.

76. Procurement. The Project will support rehabilitation and modernization of selected coal-fired power generating stations in the States of West Bengal, Maharashtra and Haryana. In addition, technical assistance support would also be provided to Central Electricity Authority (CEA) for addressing barriers to R&M in India and capacity building at CEA. The procurement will be for goods, equipments and services related to R&M of power stations. Procurement for the proposed project would be carried out in accordance with the World Bank’s “Guidelines: Procurement under IBRD Loans and IDA Credits” dated May 2004 and revised October 2006, and “Guidelines: Selection and Employment of Consultants by World Bank Borrowers” dated May 2004 and revised October 2006, and the provisions stipulated in the Legal Agreement.

77. The procurement of goods and equipment for power stations in Unit-5 Bandel (West Bengal) and Unit-6 Koradi (Maharashtra) is envisaged to be covered in four separate contracts covering the entire power station, i.e. one for main plant area (boiler, turbine and generator (including auxiliaries) – BTG package), and one each for coal handling area, ash handling area

25

and electrical system. For Units 3 & 4 Panipat (Haryana) the utility has expressed a preference for a single contract encompassing of these, though the final packaging would be decided after the detailed project report (DPR) is prepared by the design consultants. All these contracts for procurement of goods and equipment for power stations will be on “plant design, supply and install” basis. The value of contract packages for goods to be procured on “supply and install” contract basis will range from USD 5 million to USD 82 million (USD 98 million in case Units 3 & 4 Panipat are taken up under a single contract). Procurement will be done following international competitive bidding (ICB) procedures of the Bank and using the Bank’s Standard Bidding Documents (SBD) for procurement of Plant Design, Supply and Installation (April 2008 and as agreed with the Bank).

78. Each of the participating states may procure services for design consultant for R&M contracts, consultants to provide services for environmental / social audits, implementation support and quality assurance consultants and those for institutional capacity building etc. In addition, CEA would be procuring consultants for implementation of R&M barrier reduction, evaluation of pilots and capacity building activities. Short lists of consultants for services estimated to cost less than $500,000 equivalent per contract may be composed entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines. The Bank's Standard Request for Proposal Document (December 2008 and as agreed with the Bank) will be used as a base for all procurement of Consultancy services to be procured under the Project.

79. The three participating states and CEA have developed detailed procurement plans for the complete project giving estimated value, method of procurement and the year of procurement, which provides the basis for the procurement methods.

80. Procurement activities will be carried out by each of the three state generation utilities and the CEA. An assessment of the capacity of WBPDCL, MSPGCL and HPGCL to implement procurement actions for the project has been carried out by the procurement specialist of the Bank during preparation and appraisal of the project and is captured in Annex 8. The overall project risk for procurement is substantial.

4. Social

81. The Project does not have any loss of immovable assets and is anticipated to have very limited adverse social impacts. The renovations will be carried out at the existing power plant locations and therefore there will be no land acquisition and displacement. However, Rapid Social Assessment (RSA) was carried out at both Koradi (Maharashtra) and Bandel (West Bengal) thermal power stations which helped in documenting the adverse health impacts on the community and crop losses due to the power station’s operations. The findings also showed that there is no existing formal communication channel between the power stations and the community. The RSA identified various needs of the community and documented the facilities that are presently being extended by the power stations such as accessibility to schools, hospitals, cooperatives, banks, post office and for drinking water. Both the power stations have generated direct and indirect employment and engage contract laborers in operation and maintenance of the power station. Based on the results of social assessment and in-depth discussion with the power station officials, Corporate Social Responsibility (CSR) policy has also been prepared which will help the power stations to communicate with the communities in a structured manner. The CSR

26

will also bring in more resources for local area development which will enhance the reputation and image of the entities and help in smooth execution of the project and later operations.

82. The terms of reference for RSA, communication strategy and CSR for Panipat Thermal Power station has been shared with the client. As part of the phased implementation strategy for the project, the EE R&M investment for Units-3&4 at PTPS will be prepared during the 12-18 months of project implementation, including the RSA. As such, the disclosure of an acceptable RSA will be a loan covenant under the project.

5. Environment

83. Environmental Issues: The project has been assigned “Category B” reflecting limited environmental impacts. Environmental Audit Due Diligence Reports (EADDs), acceptable to the World Bank, were prepared for Bandel and Koradi thermal power stations, covered under Component 1. The EADDs include Environmental Management Action Plans (EMAPs) for implementation. Relevant public consultations were carried out to address environmental issues associated with the current operation of these plants and the in-country disclosure of EADD reports and disclosure at Bank’s Infoshop is completed. The EADD/EMAP for Panipat thermal power station will be completed during project implementation and will be a disbursement condition under the project.

84. During rehabilitation, the major issues would be dust, noise and disposal of waste from new equipment containers, and scrap materials from the removal of equipment that is to be replaced. During operation, the rehabilitated units with proposed investments would improve energy efficiency and environmental performance, both locally (reduction in dust emissions, wastewater discharges, and increases in ash utilization at the unit level) and globally (reductions in emission intensity of the plant – carbon dioxide emissions per kWh of power generation). BTPS and KTPS have agreed to address the plant and unit level environmental issues through agreed EMAPs recommended in EADDs for respective plants. The key issues agreed to be addressed include: (i) non-compliance with NAAQS and PPAH guidelines on particulate emissions, although the air pollution control mechanisms are in place; (ii) lack of adequate systems for monitoring of mass water balances reducing the opportunities for efficiency improvements; (iii) inadequate importance for Environment, Health, and Safety (EHS) systems; and (iv) further scope to minimize the wastes through recycling and reuse. In case of PTPS, as concluded in World Bank’s initial environmental due diligence, there are perceived community impacts including health impacts due to air emissions, and impacts on agricultural productivity due to water emissions and water logging due to seepage from ash pond. HPGCL/PTPS has agreed to conduct EADD in order to assess the unit level, plant level and community impacts, and to implement necessary mitigation measures. The procurement process for conduct of EADD is currently ongoing. Annex 10 provides summary of environmental issues as well as environmental management measures that are agreed with BTPS and KTPS. Annex 10 also summarizes the issues to be addressed as part of EADD for PTPS.

85. Environmental Management: Based on the outcome of the EADDs, environmental management measures are integrated in EMAPs under three categories: (i) unit level improvement of environmental regulatory compliance with improved boiler particulate emission control systems; (ii) plant level environmental performances improvement including common facilities such as cooling water discharges, and wastewater effluent management, control of

27

fugitive dust emissions from Coal Handling Plant (CHP), and improvement to increased utilization of fly ash and possible recycling of ash slurry water; and (iii) overall improvements to EHS including institutional set up for sustained environmental performance. Annex 10 provides the details on proposed interventions for Bandel and Koradi Plants. Points (i) and (ii) referred above are being integrated as part of the technical specifications of the proposed rehabilitation contract packages. Point (iii) will be included as part of the institutional strengthening component of the project.

86. Monitoring: The EADD outcomes have suggested monitoring parameters and indicators for monitoring the environmental performance of the rehabilitated units as well as plant level monitoring. The monitoring has been integrated with the ongoing environmental compliance monitoring. The necessary institutional arrangements for monitoring have been included as part of overall institutional strengthening component. The current budgets for regulatory compliance monitoring would be sufficient to provide effective monitoring.

6. Safeguard policies

Safeguard Policies Triggered by the Project Yes No Environmental Assessment (OP/BP/GP 4.01) [X] [ ] Natural Habitats (OP/BP 4.04) [ ] [X] Pest Management (OP 4.09) [ ] [X] Physical Cultural Resources (OP/BP 4.11) [ ] [X] Involuntary Resettlement (OP/BP 4.12) [ ] [X] Indigenous Peoples (OD 4.20, being revised as OP 4.10) [ ] [X] Forests (OP/BP 4.36) [ ] [X] Safety of Dams (OP/BP 4.37) [ ] [X] Projects in Disputed Areas (OP/BP/GP 7.60) [ ] [X] Projects on International Waterways (OP/BP/GP 7.50) [X] [ ]

Environmental Assessment OP 4.01: No significant adverse environmental impacts are expected under the Project. Indeed, the Project will result in major positive environmental benefits, in terms of improved energy efficiency, reduced local and global air pollutants, which will be measured and quantified during the project. Hence the environmental safeguard category of the project is B. The EADDs recommend detailed measures for addressing the priority environmental issues.

Projects on International Waterways (OP/BP 7.50): BTPS draws water from river Hooghly for cooling water requirements. The Hooghly River is part of Ganga basin which extends to Bangladesh. The river branches out to Bangladesh at the Farakka Barrage and BTPS is located about 80 km downstream of Farakka. Because the plant is located on a river which is part of an international water basin, OP/BP 7.50 is triggered.

It is noted, however, that paragraph 7 of OP 7.50 provides for an exception to external notification to other riparians “For any ongoing schemes, projects involving additions or alterations that require rehabilitation, construction, or other changes that in the judgment of the Bank (i) will not adversely

28

change the quality or quantity of water flows to the other riparians; and (ii) will not be adversely affected by the other riparians’ possible water use.”

Bank management has approved the applicability of the exception to external notification to other riparians for this project for the following reasons:

(a) The project would not adversely affect the quality or quantity of the water flows to other riparians, because:

(i) The quantity of water required by the project after rehabilitation is estimated to remain below the originally sanctioned quantity of 1.7 Mil m3/day for BTPS.

(ii) Most of the above water (>99%) is discharged back into the river after using for “once through” cooling purposes. The same pattern would be maintained after rehabilitation. Thus, from the above points (i) and (ii), the water flows to other riparians will not be affected

(iii) The temperature difference between inlet and discharge water (the key water quality parameter relevant here) would continue to be maintained below 3 degrees Celsius, complying with World Bank Guideline as well as West Bengal Pollution Control Board Guidelines, both before and after rehabilitation of Unit-5.

(b) The proposed rehabilitation works are mainly aimed at improving the energy efficiency (coal consumption per kilo-watt-hour of power generation) of the selected unit, and restoring the performance of the plant (capacity, availability etc) to close to original design parameters through renovation and modernization efforts. There are no major alternations or change in the nature or scope of the plant envisaged.

7. Policy Exceptions and Readiness

87. No exceptions to Bank policies are required by this project.

29

Annex 1: Country and Sector Background

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

1. The Government of India (GOI) has identified the power sector as key to achieving its goals of high and sustainable economic growth and accelerated poverty alleviation. However, the sector is currently poorly positioned to support these goals. It is characterized by power shortages (peak deficit of 15.2 percent and energy deficit of 9.0 percent14), low level of electricity access (According to 2001 census, 44.2 percent of households lacks access), high level of transmission and distribution losses15, and poor collection efficiency.

2. Under the Constitution, electricity is a “concurrent” subject with Central and state governments being responsible for key aspects of its supply. The Central government, having laid the legal and policy foundation to further strengthen existing organizations and to expand private participation, is better positioned to respond to new demands on the sector than it was five years ago. At the state level, several states have used national laws and policy to advance the restructuring of their power sectors towards making them more efficient, accountable and demand-responsive.

3. National Energy Policy. India’s National Electricity Policy (NEP), notified on February 12, 2005, has the following objectives, to be met by the year 2012: (i) providing electricity access to all households; (ii) fully meeting the power demand; (iii) supplying reliable and good quality power efficiently and at reasonable rates; (iv) doubling per capita electricity consumption to 1000 kWh per annum; and (v) achieving financial turnaround and commercial viability of the electricity sector. This policy aims to fully meet existing energy and peaking shortages while also aiming to achieve financial viability of the electricity sector. Meeting the “power for all” target requires an estimated 80,000 MW of new capacity to be added during the 11th plan (2007 – 2012), through new generation capacity but also other measures, including renovation and modernization of power plants, energy conservation and efficiency, efficient energy technology R&D. The policy provides for closing down plants that are too old, decrepit, and dirty to be turned around by renovation.

4. Challenges in Electricity Sector. In August 2006, the NEP was supplemented by the Integrated Energy Policy, which is intended to address the question of how India can meet the rapidly rising demand for energy and sustain a high economic growth rate. Concerns about energy security and high costs of energy imports drive the proposed measures aimed at reducing non-essential or inefficient energy consumption. However, the remaining challenges in the electricity sector are daunting, given the following issues: (i) low levels of connectivity, particularly in rural areas; (ii) high coping costs of industry, with 60 percent of Indian firms relying on captive or back-up generation; (iii) limited grid supply infrastructure, with about 25 percent of capacity in need of rehabilitation; limited capacity for inter-regional trade; and under-maintained state distribution systems that cannot meet demand; (iv) weak utility governance in most states resulting in high system losses; (v) unpredictable fuel supply and costs, particularly for gas; and (vi) contribution to 50 percent of India’s carbon emissions, with coal based generation continuing to play a major role in emissions.

14 Source: Ministry of Power Annual Report 2007 - 2008. 15 The previous cited Annual Report mentioned Transmission and Distribution losses (T&D Losses) of 29.89% for 2006 - 2007.

30

Challenges in Coal-Fired Generation Sub-Sector. India depends on 76,000 MW of coal-fired, base-load power plants representing 53 percent of total installed capacity (143,000 MW), but much of this does not perform well. The central sector National Thermal Power Corporation (NTPC) owns a third of this capacity which are generally efficient with station heat rates (SHR) of about 2,500 kcal/kWh (i.e. close to design value). NTPC plants also have good plant availability with average plant load factors (PLF) of about 92 percent. The remaining coal-fired plants are owned largely by state government utilities. Most of these generation plants that are owned by state government utilities (except some states such as Rajasthan, Karnataka, Punjab, Maharashtra, Tamilnadu and Andhra Pradesh) are in a relatively poor shape – with an average PLF of about 70 percent, with some plants having PLFs lower than 55 percent and SHR of about 3,000 kcal/kWh and above, (sometimes up to 4,000 kcal/kWh in many cases). 5. India was able to keep pace with needed rehabilitation or Renovation and Modernization (R&M) investments through the better part of the 7th, 8th and 9th Five-Year Plans, covering the fifteen years until 2002. Since then R&M requirements have increased rapidly and implementation of R&M schemes has slowed down. The 10th Plan (2002-2007) R&M target was not fully met – especially by the state generation utilities and nearly 8000 MW spilled over into the 11th Plan, which now has an R&M requirement of nearly 27,000 MW (about a third of the total installed coal-fired generation capacity in the country). Also, in the case of past R&M investments, plant availability has tended to decline back to the pre-R&M levels within a few years due to poor O&M practices at many state government utilities. More importantly, for the past and planned R&M, the primary criteria is often PLF enhancement and life extension, and any energy efficiency improvements (SHR and other parameters) achieved is usually incidental and not a primary criteria for R&M project design.

Table-1.1: Need for Rehabilitation of Old Coal Fired Units during XI Plan Period (2007-12)

Size of unit <100 MW

100~200 MW

200~210 MW

500 MW

Total MW

Spillover from X Plan Period NTPC (including DVC) 0 0 3880 4000 7880State Generation Utilities 194 1480 5400 1000 8074TOTAL 194 1480 9280 5000 15954Additional Rehabilitation for XI Plan Period NTPC 0 800 2910 3000 6710State Generation Utilities 193 760 3320 0 4273TOTAL 193 1560 6230 3000 10983Total Rehabilitation Requirement for XI Plan Period NTPC 0 800 6790 7000 14590State Generation Utilities 387 2240 8720 1000 12347GRAND TOTAL 387 3040 15510 8000 26937

Source: Data collected from Central Electricity Authority Note: (i) Spill-over includes works that were initiated but could not be completed within the X Plan.

(ii) NTPC follows a rolling plan for R&M and although a large spillover is indicated here, significant works have been completed within the X Plan period.

6. Large fleet of coal-fired plants is due for rehabilitation. As shown in the table above, many of the old coal-fired power plants (NTPC as well as state utility owned plants) are now due for rehabilitation and life extension. These plants offer opportunity to add low cost power to the

31

starving grid and improve their operational efficiencies in a shorter time span16 through a well designed renovation and modernization (R&M) program. In addition to lower costs and positive environmental impacts, the R&M presents fewer challenges since (i) land is already in possession; (2) transmission facilities already exist; and (iii) coal, water and other linkages are available.

7. Barriers to Implementation of Renovation and Modernization Program. The key unanswered question is why R&M investments are not materializing despite prevailing power shortages and potential for low cost capacity augmentation. Based on extensive stakeholders consultations17, the following barriers to R&M in India have been identified:

a. Difficulty in securing long plant shutdown needed for R&M. Many of the best candidates for R&M are owned by states which are facing severe power shortages and are therefore reluctant to have them out of service for the length of time required for R&M. The additional cost of arranging energy during shut down periods, for these fully depreciated plants is a significant burden on the utilities as well as the States.

b. Regulatory issues. There is significant uncertainty about whether the full R&M capital expenditure will be passed through to the rate base of the generation companies and on the sharing of benefits of R&M between generators and consumers.

c. Limited institutional capacity at the utility to take up R&M projects. Most generation utilities in India have plans for large green-field capacity addition over the eleventh five year plan period (2007-12). Utilities tend to accord a higher priority to green-field capacity addition over R&M projects, since the latter are perceived to be more risky, require much greater preparatory effort and the utility’s institutional capacity to implement projects is limited.

d. Lack of energy efficiency orientation. In the past, Indian power generation utilities and planning agencies have been primarily concerned with capacity enhancement and life extension of coal-fired generation and not the efficient operation of these facilities.

e. Time and cost overruns and contract management difficulties in the past. Utilities are discouraged from taking up R&M schemes by the implementation delays, cost escalations (due to surprises when machines are opened up) and contractual difficulties during implementation.

f. Poor O&M practices and internal management capacity have resulted in the long-term benefits from past R&M being unsustainable. Most state government generators, with a few exceptions, have very poor capacity in terms of skills for operating and maintaining plants.

g. General financial distress of state power utilities. The poor financial situation in the state power sector results in limited debt servicing ability. Available financing usually gets used to firefighting, ad-hoc investment or politically motivated schemes instead of

16 A new coal based thermal plant takes about 36-42 months after the contract award, while well planned Renovation & Modernization work could be completed in 24-30 months with around six months plant down time. 17 A two day workshop was conducted in September 2005 involving key stakeholders including state generators, NTPC, PFC, CEA, external donors, the GOI and state governments. In addition, detailed discussions were carried out with various stakeholders separately. Stakeholder consultations on barriers to R&M were held again in a workshop organized in May 2008 to discuss options for regulatory treatment of R&M.

32

schemes with long payback and short-term costs, i.e., R&M. Even when R&M is financed, usually the lowest capital expenditure option is considered first.

8. GOI Initiatives for Improved Performance of Generation Plants at the State Level. With regard specifically to rehabilitation of coal-fired generation, the National Electricity Policy states that “Renovation and modernization for achieving higher efficiency levels needs to be pursued vigorously and all existing generation capacity should be brought to minimum acceptable standards.” The National Tariff Policy also encourages the development of R&M projects and states that a multi-year tariff (MYT) framework may be prescribed which includes capital investments and an incentive framework to share the benefits of efficiency improvements between the utilities and beneficiaries.

9. In addition, GOI launched a program called “Partnership In Excellence (PIE)” in August 2005 with the objective of enhancing the performance of under-performing power stations (with less than 60 percent Plant Load Factor) in the country. Under the PIE program, some of the well-performing generation utilities (such as NTPC Ltd and Tata Power)18 partnered with 16 under-performing power stations, while another four power plants implemented O&M improvement steps on their own. The PIE program was focused on improvement of power plant availability – the primary objective being to improve plant load factor in PIE stations which were originally operating between 40- 60 percent to more than 60 percent. The program was broadly successful in achieving this objective, though significant scope for further improvements remains.

State Context: West Bengal

10. West Bengal is a state in eastern India, with the third largest state economy in India. An agriculture-dependent state, West Bengal occupies only 2.7 percent of India’s land area, though it supports over 7.8 percent of India’s population and is one of the most densely populated states in India. Although agriculture is the leading occupation, the service sector is the largest contributor to the gross domestic product of the state, contributing 51 percent of the state domestic product compared to 27 percent from agriculture and 22 percent from industry.

11. West Bengal is a relatively better performing state in terms of availability of power. It faces an energy shortage of 2 percent and peak shortage of 3 percent. It currently earns around Rs.10, 000 million annually by trading power. The per capita consumption of power is 266 kWh which is lower than the all India average of around 704 kWh. It is estimated that peak demand in West Bengal by the end of the eleventh plan will be 6,472 MW against an availability of 7,190 MW (including the state’s share of central sector generation), with a peaking surplus of 11.1 percent and an energy surplus of 42.2 percent.

12. West Bengal Power Development Corporation Limited (WBPDCL) has a total generation capacity of 2820 MW across six thermal power plants located at Bandel (4x80+1x 210 MW), Bakreshwar (5x210MW), Kolaghat (6x210 MW), and Santhaldih (4x120 MW). WBPDCL plans to add 2230 MW over the eleventh plan period. In addition, three plants of 1270 MW which were scheduled to be commissioned in the tenth plan are delayed and now scheduled for

18 The program was shouldered primarily by NTPC who partnered 15 of the 20 power stations.

33

commissioning in the eleventh plan. . During 2007-08, WBPDCL generated 16,805 MUs of energy and achieved an aggregate PLF of about 68 percent.

State Context: Maharashtra

13. Maharashtra, located in western India, is the country’s third largest state in area, second largest in population, second most urbanized (42 percent) and has one of the highest per capita incomes among large states. It is a heavily industrialized state and contributed nearly 15 percent of the country's industrial output and 13.2 percent of its GDP in year 2005-06.

14. Maharashtra state has been facing severe power shortages. The peak deficit of around 13,575 MW in 2007-08 has resulted in severe load shedding in almost all parts of the state. It faces an energy shortage of around 18 percent and a peak shortage of around 23 percent. The per capita consumption of power is 609 kWh which is close to the all India average of around 704 kWh. The state generation utility has estimated that peak demand in Maharashtra by end of Eleventh Plan will be 21,954 MW against an availability of 18,400 MW (including the State’s share of central sector generation), with a peaking shortage of 16.2 percent and a marginal energy surplus of 0.9 percent.

15. Maharashtra State Power Generation Company Limited (Mahagenco) is the second largest power generation utility in India after NTPC, and has a total installed capacity of 9,972 MW, of which coal-fired generation is 6830 MW. The thermal plants are located at Bhusawal (475 MW) Chandrapur (2290 MW), Khaparkheda (840 MW), Koradi (1,080 MW), Nasik (910 MW), Paras (305 MW), Parli (930 MW). By 2013 Mahagenco plans to add 7000 MW of additional capacity.

States Context: Haryana

16. Haryana is a state in northern India and surrounds Delhi on three sides. The state of Haryana is one of the richest, leading in agriculture and most industrialized states in the country. Haryana has seen its power shortages grow in recent years, with peak-time deficits about 1200-1500 MW and off-peak deficits about 400-600 MW, which translates to 10 percent to 30 percent of installed capacity of 4680 MW. The per capita consumption of power is 715 kWh which is higher than the all India average of around 704 kWh.

17. At present, the existing generation capacity within Haryana takes care of only about 40 percent of the total power requirement of the state, while the remaining is secured from central sector generation utilities and surplus neighboring states such as Himachal Pradesh. Since Haryana relies heavily on power purchase from external generators and is also faced with significant power shortages, it has planned capacity additions and power procurement from Independent Power Producers (IPPs) of 7,182 MW during the XI plan to meet the demand–supply gap. The state utility has projected peak demand by end of XI Plan to be 6,839MW against peaking capacity of 5,409MW with a peaking shortage of about 21 percent. However, the state is expected to have an energy surplus of about 1.7 percent with an availability of 39,054 MU against a requirement of 38,417 MU.

34

18. Haryana Power Generation Company Limited (HPGCL) has a total thermal generation capacity of 2,195 MW, comprising of Faridabad Thermal Power Station (3x55MW), Panipat Thermal Power Station (4x110MW, 2x210MW, 2x250MW) and Deenbandhu Chottu Ram Thermal Power Plant (2x300MW). In addition, the company also has 64 MW of hydropower capacity at Yamunanagar. During the XI five year plan HPGCL plans to add another 1800 MW of thermal generation capacity.

Regulatory Aspects of R&M

19. At the concept stage for this project, a number of barriers were cited as reason for very little R&M taking place in India. However, little was known about how the regulatory framework may need to be altered to improve the investment climate for R&M. Discussions at the state and national level (with state level regulators, utilities, CERC, CEA, etc.) found a strong appetite for a comprehensive assessment and suggestions for an appropriate regulatory framework for R&M. As a result, the Bank has embarked on a substantive work stream with policy makers at the national and state level with the objective of highlighting possible options for treatment of R&M proposals. The engagement is centered on a study carried out by a consortium of international and Indian consultants (IPA & KPMG India) funded by ESMAP. The terms of reference for the study were discussed and agreed with the Indian Forum of Regulators or FoR (an official group comprising the Chairmen of the central and state electricity regulatory commissions of India).

20. The predominant form of tariff regulation in generation and distribution across India is a form of cost-plus. The regulator determines which costs incurred by the generator can be charged to buyers through the tariff. The generating company will normally have some clarity ex-ante on the extent to which it can recover its cost of capital and operating costs from consumers via the published tariff determination process (‘Terms and Conditions of Tariff Regulations’ as notified by the concerned regulatory commission). Allowed operating costs (referred to as “norms”) are often based on known costs for other plants that may be of similar vintage and superior performance or newer plant. In this way, the regulator can ascertain the costs that a well run plant should be incurring. The generator is automatically penalized for inefficient operation, as any costs above the norms must be absorbed by the generator. Prior to incurring large capital expenditures (such as for carrying out R&M), the generating company will normally request ex-ante approval to be able to pass these extra costs through to the consumer via the tariff. The regulator normally uses what is known as a viability test to determine whether or not to allow the capital costs. Through its determinations on treatment of operating and capital costs, the regulator plays an important role in determining whether an investor finds an R&M investment viable or not.

21. Indian states are now moving to tariffs being set for approximately 3-5 years under what is known as a Multi-Year Tariff (MYT) framework rather than annual determinations. Additionally, the National Tariff Policy requires that power should be procured competitively by distribution licensees except in cases of expansion of existing projects or where there is a State controlled/owned company as an identified developer, in which case tariff would be determined based on norms (as is the case with the Bank/GEF project). The result is that within a state, there can be a mix between cost-plus methods of determining the tariff and forms based on market-

35

determined tariffs. The regulatory framework is in a state of evolution across India and the treatment an R&M investment will receive can vary depending on the state.

22. Several barriers arising from the existing regulatory framework were identified by the study. These include:

� Regulators have limited technical and economic capacity to evaluate proposals for investment (for carrying out a proper viability assessment on investment proposals).

� There is lack of clarity over the conditions under which the regulator will allow the generator to recover capital costs incurred for R&M from consumers.

� There is uncertainty over regulatory treatment of operating norms, especially whether they would be held appropriately high after investment has taken place to allow the investor to recoup the necessary returns.

� Whether recovery of fixed costs would be jeopardized by reduced plant availability due to outage during rehabilitation.

� Lack of clarity as to how the regulator would treat cost escalations, time delays and any contractual difficulties that the generating company or supplier of R&M may incur.

� Uncertainty over what the regulatory framework will be, as regulatory arrangements are in a state of flux in a number of states.

23. Apart from addressing these barriers, the regulatory framework can also help address wider barriers to R&M. These include energy shortages and ensuing short-term high costs of outage for rehabilitation, limited institutional capacity at the utility to take up R&M, weak O&M practices and financing constraints in the sector. Several of these barriers create risks that could be reduced or better allocated through a regulatory framework that is cognizant of these issues.

24. The study conducted by IPA and KPMG India assesses the regulatory framework to consider how investment risks can be reduced and returns can be better aligned with the risks. To gather wide sector input on initial findings of the study, a workshop was held in Delhi in May 2008. Attendees included state regulatory chairmen, members and senior officials of the CERC, senior management of state utilities and private sector investors. The objective of the workshop was to disseminate draft findings from the study and to initiate a dialogue between different stakeholders on the need for improving incentives/reducing risks. The workshop was successful in increasing awareness. There was considerable input from across the different stakeholders. While a number of issues were brought up in the study, the two most important issues discussed during the workshop were:

� In carrying out the viability test (discussed above), regulators currently tend to assess the viability of R&M based on the engineering costs of the R&M and how this compares with ad hoc proxies for costs per MW of new capacity that a generator “should be” incurring. Such an assessment fails to incorporate and value a number of benefits of carrying our R&M and would not offer the correct result. Regulators should consider the financial, or preferably, the economic viability of the investment. In a financial evaluation, the project would be accepted if the financial benefits outweighed the financial costs. A full economic evaluation would consider all the options available to the distribution company for meeting its power generation needs which would include the cost of short-term purchases due to a plant shutdown as well as any revenue it would forgo due to un-delivered energy during the extra construction period that would be required if the plant were replaced instead of being rehabilitated.

36

� Analytical work carried out to assess the risks and returns of options suggested by the study find that the generator currently (under the cost-plus method) passes on a disproportionately high return to the distribution company in relation to the risk it faces in carrying out the investment. This balance would need to be re-adjusted in favor of the generator to increase generator incentives to invest in R&M.

25. The final study report put forward a menu of options for addressing the risks beginning with simple modifications to the current cost-plus option leading through to more advanced versions of cost-plus and versions based partly or wholly on market based tariff determinations. To deal with institutional weaknesses, the options include variants that allow the private sector to invest and gather returns from R&M. The menu of options offers different solutions for different levels of market involvement, allowing the options to apply across the many states or many situations within a state. The options offer progressively better alignment of risks-responsibilities-rewards across different stakeholders and potentially, higher returns.

26. Further work on disseminating the findings of the study will be carried out together with initial discussions about how to implement the suggested options. The following documents are included in the project file for reference:

• Policy note to the Government of India: Improving regulatory incentives to invest in rehabilitation of coal-fired generating plants in India. June 2008.

• IPA Energy + Water Consulting and KPMG India Regulatory study to encourage energy efficiency through investments in rehabilitation of coal fired generation plant in India September 2008.

27. The financial analysis for this project incorporates scenario analyses for different possible tariff treatments and investment returns, based on different tariff decisions the regulators in question may take. The viability of the investment is dependent on this regulatory treatment. For this reason, project preparation has included detailed discussion with the concerned regulators and the regulatory cells within the utilities. Whilst the state regulatory commissions are independent bodies and we cannot second guess their rulings, our understanding from these discussions is that investments under the project are likely to receive regulatory approval and will be allowed to charge tariffs that allow the utility to recover their costs of R&M over time. Investment returns under a range of possible regulatory treatments is included in the financial analysis for this project.

37

Annex 2: Major Related Projects Financed by the Bank and Other Agencies

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

WORLD BANK AIDED PROJECTS IN THE ENERGY SECTOR

Project Name Status Board Approval

IP rating

DO rating

Sector Issues Addressed

IN: Power System Development Project – IV

Supervision 18 March 2008 S S Strengthen India’s electricity transmission system to increase reliable power exchange between regions and states.

IN: Rampur Hydropower Project

Supervision 13 September 2007

S S Address power shortages, Institutional Strengthening of SJVNL, Develop 412 MW hydropower project

IN: Power System Development Project – III

Supervision 19 Jan 2006 S S Improvement of outcome-orientation and institutional development of POWERGRID

IN: Power System Development Project – II

Closed 3 May 2001 S HS Improve grid and power system commercial operations. Independent regulation.

IN: Renewable Energy II/ Energy Efficiency

Closed 27 June 2000 S S Develop small hydro resources through private sector investments. Promote Energy Efficiency investments.

IN: UP Power Sector Restructuring

Closed 25 April 2000 S U Sector sustainability problems due to high losses. Independent regulation, sector reforms.

IN: Rajasthan Power Sector Restructuring Project

Closed 18 January 2001

MS MS Sector sustainability problems due to high losses. Independent regulation, sector reforms.

IN: Nathpa Jhakri Hydro Power Project

Closed 2 March 1989 S S Power shortages, strengthen HPSEB operations, and strengthen institutional capacity development of hydropower.

IN: Orissa Power Project Closed 14 May 1996 U U Sector sustainability problems due to high losses. Independent regulation, sector reforms

IN: Haryana Power Sector Restructuring Project

Closed 15 January 1998

U U Sector sustainability problems due to high losses. Independent regulation, sector reforms.

IN: Andhra Power Sector Restructuring Project

Closed 18 February 1999

S S Sector sustainability problems due to high losses. Independent regulation, sector reforms. High untargeted subsidy to agricultural consumers.

Ratings: HS= Highly satisfactory; S=Satisfactory; MS=Moderately Satisfactory; MU=Moderately Unsatisfactory; U=Unsatisfactory; HU=Highly Unsatisfactory; NA=Not Applicable; NR=Not Required

INTERNATIONAL FINANCE CORPORATION AIDED PROJECTS IN THE ENERGY SECTOR

Project Type Project Board Date

Company Objective

Tata Mundra Project

Loan 8 April 2008 Coastal Gujarat Power Limited To finance the first ultra mega project -- India’s first 800 MW unit supercritical technology thermal power plant, which is likely to be the most energy-efficient, coal-based thermal power plant in the country

IHDC (Dodson-Lindblom Hydropower Private Ltd)

Loan 25 July 2005 Dodson-Lindblom Hydropower Private Limited (DLHPPL) and Ascent Hydro Projects Limited (Ascent) merged into one company, Indian Hydropower Development Corporation (IHDC)

To develop Mini Hydro Power Plants in India

AD Hydro Power Limited

Loan 31 Oct 2003 Allain Duhangan Power Company Ltd. (ADPCL) will be jointly owned by Rajasthan Spinning & Weaving Mills Ltd., HEG Limited and Malana Power Company Ltd.

To help meet peak and energy shortages through construction of a 192MW run-of-the-river hydroelectric power plant in Himachal Pradesh

Tala Transmission

Loan 31 Jul 2003 A joint venture between Tata Power Company Ltd. and Power Grid Corporation of India Ltd. to establish the Tala Transmission project.

Promotion of the first public private joint transmission project in India; Expansion of inter-regional transmission capacity and evacuation of power from the 1,020 MW Tala Hydroelectric Project in Bhutan.

38

ASIAN DEVELOPMENT BANK (ADB) AIDED PROJECTS IN THE ENERGY SECTOR

Project Name Type Approval Date Executing Agency

Sector Issues

Himachal Pradesh Clean Energy Development Investment Program (MFF)

Loan 23 October 2008 Himachal Pradesh Power Corp. Ltd., Himachal Pradesh State Elec. Board

Increased production and use of clean energy in a financially sustainable manner through run-of-the-river hydropower schemes.

National Power Grid Development Investment Program (MFF)

Loan 28 March 2008 Power Grid Corporation of India Limited

Upgrading transmission corridor from Uttaranchal.

Madhya Pradesh Power Sector Investment Program (MFF)

Loan Project-1: 4 April 2007 Project-2: 4 April 2007 Project-3: 21 Aug 2007 Project-4: 21 Aug 2007

Madhya Pradesh Power Transmission Company Limited

Improvement in operational efficiency, voltage profile and power delivery capacity of Madhya Pradesh.

Uttaranchal Power Sector Project (MFF)

Loan 30 March 2006 Project-1: 2 January 2007

Uttaranchal Energy & Irrigation Department

Expansion of the northern grid and increase the pace of economic development in less-developed regions in Uttaranchal state

Power Grid Transmission (Sector) Project

Loan 21 December 2004 Power Grid Corporation of India Ltd.

Strengthen India’s national transmission grid to improve system reliability, facilitate power transfers and reduce losses

Assam Power Sector Development Program (Project Loan)

Loan 10 December 2003 Assam State Electricity Board

Strengthening of transmission and distribution systems

Assam Power Sector Development Program

Loan 10 December 2003 Government of Assam

Improvement of financial viability of sector, and assistance in development of legal and regulatory framework for sector growth

State Power Reform Project Loan 12 December 2002 Power Finance Corporation Ltd. (PFC)

Line of credit for power sector financing.

Madhya Pradesh Power SDP (Project Loan)

Loan 6 December 2001 Madhya Pradesh Electricity Board

Facilitate the restructuring of the power sector to improve sector efficiencies.

Madhya Pradesh Power Sector Development Program

Loan 6 December 2001 Government of Madhya Pradesh

Facilitate the restructuring of the power sector to improve sector efficiencies.

39

Annex 3: Results Framework and Monitoring

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

Results Framework PDO Outcome Indicators Use of Outcome Information

Improve energy efficiency of selected coal-fired power generation units through R&M and improved O&M

Reduction in fuel (coal and oil) consumption per unit of power generation after completion of R&M

To review detailed monitoring reports prepared by the generating units; Find causes and work out remedial action plan of technical and managerial actions in case of unsatisfactory improvements

Global Environment Objective Reduction of greenhouse gas emissions per kilowatt of electricity generated by improving energy efficiency of coal-fired power generation units.

• Percentage reduction in carbon dioxide emissions per kilowatt hour as a result of energy efficiency R&M in selected coal-fired power generating units

• Reduction in carbon dioxide emissions as a result of energy efficiency R&M in selected coal-fired power generating units.

Dissemination of benefits of proposed Renovation and Modernization design approach; Reporting to Government of India and determining actions required for further replication

Intermediate Results Results Indicators for Each Component Use of Results Monitoring Component 1 Energy Efficient Renovation and Modernization implemented for select generation units

• Number of contracts awarded • Capacity rehabilitated and modernized with

focus on energy efficiency, financed directly under this project

Gauge implementation of Energy Efficient Renovation and Modernization, and take corrective actions including, raising outstanding issues with utility management, state government or at government of India level

Component 2 Barriers to implementation of Energy Efficient Renovation and Modernization projects reduced

• Number of Units for which R&M procurement process is initiated at the National Level

• Number of energy audit reports with baseline performance information for generation units requiring R&M

• Number of Detailed Project Reports produced with investment plans optimized for energy efficiency for generation units requiring R&M

• Number of barrier reduction studies / technical assistance interventions undertaken by CEA under Bank project.

• Number of Utilities in which implementation of agreed O&M and Institutional Strengthening Programs is completed

Monitor progress at the national R&M program level. Gauge progress on indicators to take suitable remedial measures in case of delays in implementation; workshop evaluation (including feedback from participants) and follow-up to ensure increased awareness by generation company staff

40

Arr

ange

men

ts fo

r R

esul

ts M

onit

orin

g T

arge

t Val

ues

Dat

a C

olle

ctio

n an

d R

epor

ting

In

dica

tors

U

pdat

ed

Bas

elin

e fr

om

Ene

rgy

Aud

it3

Yr

1Y

r 2

Yr

3 Y

r 4

Yr

5 F

requ

ency

an

d R

epor

ts

Dat

a C

olle

ctio

n In

stru

men

t R

espo

nsib

ility

PD

O I

ndic

ator

s

Uni

t-5,

Ban

del T

herm

al P

ower

Pla

nt, W

est B

enga

l1 �

Red

uctio

n in

Spe

cifi

c C

oal C

onsu

mpt

ion

(Kg/

kWh)

2 �

Red

uctio

n in

Spe

cifi

c O

il C

onsu

mpt

ion

(ml/

kWh)

U

nit-

6, K

orad

i The

rmal

Pow

er P

lant

, Mah

aras

htra

1 �

Red

uctio

n in

Spe

cifi

c C

oal C

onsu

mpt

ion

(Kg/

kWh)

2

�

Red

uctio

n in

Spe

cifi

c O

il C

onsu

mpt

ion

(ml/k

Wh)

U

nit-

3, P

anip

at T

herm

al P

ower

Pla

nt, H

arya

na1

�

Red

uctio

n in

Spe

cifi

c C

oal C

onsu

mpt

ion

(Kg/

kWh)

2

�

Red

uctio

n in

Spe

cifi

c O

il C

onsu

mpt

ion

(ml/k

Wh)

U

nit-

4, P

anip

at T

herm

al P

ower

Pla

nt, H

arya

na1,

�

Red

uctio

n in

Spe

cifi

c C

oal C

onsu

mpt

ion

(Kg/

kWh)

2

�

Red

uctio

n in

Spe

cifi

c O

il C

onsu

mpt

ion

(ml/k

Wh)

1

A=

pre-

R&

M;

B=

R&

M P

repa

ratio

n; C

=po

st R

&M

. Nil

valu

es a

re g

iven

dur

ing

shut

dow

n pe

riod

. 2 A

djus

ted

to n

orm

aliz

e ca

lori

fic v

alue

of c

oal (

4200

kca

l/kg)

3 F

or P

anip

at, t

he b

asel

ine

figur

es h

ave

been

put

in b

rack

ets

to

indi

cate

that

thes

e ar

e ba

sed

on d

ata

repo

rted

by

utili

ty in

th

eir

annu

al r

epor

t to

CE

A. E

nerg

y au

dit f

or P

anip

at u

nits

3&

4 w

ill b

e co

mpl

eted

by

year

2 o

f pro

ject

impl

emen

tatio

n

0.68

4 2.

5 0.

703

2.27

[0

.825

]3 2.

4 [0

.825

] 3

2.5

B

- - A

- - A

- - A

- -

B

- - B

- - A

- - A

- -

C

- - B

- - B

- - B

- -

C

12%

20

%

C

14%

12

%

B

- - B

- -

C

12%

20

%

C

14%

12

%

C

18%

17

%

C

18%

20

%

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Ann

ual

For

Coa

l C

onsu

mpt

ion:

M

easu

rem

ent a

t co

al fe

eder

/ E

nerg

y A

udit

on R

&M

co

mpl

etio

n F

or O

il C

onsu

mpt

ion:

M

easu

rem

ent a

t Oil

flow

met

er /

Ene

rgy

Aud

it on

R&

M

com

plet

ion

Gen

erat

ion

Com

pany

GE

O I

ndic

ator

R

educ

tion

in C

O2

emis

sion

inte

nsity

for e

ach

of th

e ge

nera

tion

units

aft

er c

ompl

etio

n of

R&

M (%

) R

educ

tion

in C

O2

emis

sion

s as

a re

sult

of e

nerg

y ef

fici

ent R

&M

(mill

ion

TC

O2)

�

in p

lant

s fi

nanc

ed u

nder

this

pro

ject

�

othe

r pla

nts

0%

0 0

- -

- -

- -

10%

0.

25

-

10%

0.

43

0.30

Ann

ual

Ann

ual

Ann

ual

Cal

cula

tion

of

Em

issi

on R

educ

tions

as

per

agr

eed

form

at

Gen

erat

ion

Com

pani

es

and

CE

A

41

T

arge

t Val

ues

Dat

a C

olle

ctio

n an

d R

epor

ting

In

dica

tors

B

asel

ine

Yr

1Y

r 2

Yr

3 Y

r 4

Yr

5 F

requ

ency

an

d R

epor

tsD

ata

Col

lect

ion

Inst

rum

ent

Res

pons

ibili

ty

Inte

rmed

iate

Out

put I

ndic

ator

s

Com

pone

nt-1

�

Num

ber

of c

ontr

acts

aw

arde

d �

Cap

acity

reh

abili

tate

d an

d m

oder

nize

d w

ith f

ocus

on

ener

gy e

ffic

ienc

y, f

inan

ced

unde

r th

is p

roje

ct (

MW

, cu

mul

ativ

e)

0 0

4 0

8 0

9 0

9 420

9 640

Ann

ual

Ann

ual

Rep

orts

sub

mitt

ed to

th

e B

ank

Gen

erat

ion

Com

pani

es

Com

pone

nt-2

�

Cum

ulat

ive

num

ber

of U

nits

for

whi

ch R

&M

pr

ocur

emen

t pro

cess

is in

itiat

ed a

t the

Nat

iona

l L

evel

�

Cum

ulat

ive

num

ber

of e

nerg

y au

dit r

epor

ts w

ith

base

line

perf

orm

ance

info

rmat

ion

�

Cum

ulat

ive

num

ber

of R

&M

det

aile

d pr

ojec

t rep

orts

(D

PRs)

with

inve

stm

ent p

lans

opt

imiz

ed f

or e

nerg

y ef

fici

ency

�

Cum

ulat

ive

num

ber

of b

arri

er r

educ

tion

stud

ies

/ te

chni

cal a

ssis

tanc

e in

terv

entio

ns u

nder

take

n by

C

EA

und

er B

ank

proj

ect.

�

Cum

ulat

ive

num

ber

of U

tiliti

es in

whi

ch

impl

emen

tatio

n of

agr

eed

O&

M a

nd I

nstit

utio

nal

Stre

ngth

enin

g Pr

ogra

ms

is c

ompl

eted

N.A

. N

.A.

N.A

. N

.A.

N.A

.

1 1 0 0 0

2 3 1 0 0

4 5 3 3 2

6 7 5 3 3

8 8 8 4 3

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Ann

ual

Rep

orts

sub

mitt

ed to

th

e B

ank

Rep

orts

sub

mitt

ed to

th

e B

ank

Rep

orts

sub

mitt

ed to

th

e B

ank

R

epor

ts s

ubm

itted

to

the

Ban

k R

epor

ts s

ubm

itted

to

the

Ban

k

CE

A

Gen

erat

ion

Com

pani

es

Gen

erat

ion

Com

pani

es

CE

A

Gen

erat

ion

Com

pani

es

NO

TE

: The

Clie

nts

will

be

mon

itori

ng a

long

er li

st o

f in

dica

tors

incl

udin

g pe

rfor

man

ce p

aram

eter

s su

ch a

s un

it he

at r

ate,

aux

iliar

y co

nsum

ptio

n, u

nit a

vaila

bilit

y, e

tc. f

or e

ach

of th

e un

its w

here

EE

R&

M p

ilots

are

und

erta

ken.

The

Ban

k w

ill r

evie

w th

ese

addi

tiona

l in

dica

tors

as

part

of

supe

rvis

ion.

42

Annex 4: Detailed Project Description

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT 1. The Coal-Fired Generation Rehabilitation project is aimed at demonstration of energy efficient renovation and modernization of relatively old coal-fired power generation units in three pilot states and facilitating replication through mitigation of barriers, supporting design studies and dissemination of learnings from demonstration projects. The project would also facilitate strengthening of institutional capacity of the concerned generation utilities for improved operation and maintenance practices and better monitoring and evaluation of plant performance.

2. The proposed project will have the following components:

� Component 1: Energy Efficiency R&M Pilots (US$295.9 million) � Component 2: Technical Assistance (US$7.5 million)

3. The project will be financed by IBRD loans, GEF grants and generators own equity funds as shown in the table below. Additional leverage is expected to come from follow-on projects of the same type, based on the demonstration of benefits achieved in the GEF program and financed by commercial loans and generators own funds.

Table-4.1: Financing Plan Financing Plan Component Indicative

Costs GEF IBRD Equity Total Energy Efficiency R&M Pilots 295.9 37.9 180.0 78.0 295.9Technical Assistance 7.5 7.5 - - 7.5Total 303.4 45.4 180.0 78.0 303.4

(All figures in US$ million) 4. A detailed description of the project components is as follows:

Component 1: Energy Efficiency R&M Pilots (US$295.9 million)

5. This component would provide financing for rehabilitation of 640 MW of old coal-fired generation capacity to demonstrate energy efficient rehabilitation approaches. The GEF grant would facilitate implementation of necessary safeguard measures as required by the World Bank.

Approach for Energy Efficient R&M

6. Energy efficient R&M of generation units would go beyond restoration of original generation capacity, life-extension and improved availability. It would also include modifying (or replacing) some equipment and systems to enable the unit to operate at higher outputs with lower required fuel inputs. Accordingly, the design of energy efficient R&M is driven by the following objectives:

� Extension of life of generation unit by at least 15 years � Improvement of availability of the generation unit to at least 85 percent � Sustained achievement of near-design (or better) maximum continuous rating (MCR) � Improvement in energy efficiency of boiler, turbine, generator and auxiliaries, resulting in

improvement of unit heat rate to about 2500 kcal/kWh � Achievement of lower specific oil consumption through reduction in number of trippings,

faster start-up and stable combustion at even lower levels of load

43

� Overcome the problem of aging of critical components (leading to lower reliability and shorter residual life) and non-availability of critical spares (due to obsolescence)

� Incorporation of advanced control and instrumentation systems with several additional features (such as upgraded interlock and protection system) for sustained and safe operation of the generation unit

� Provision for handling possible degradation of coal quality � Compliance with latest environmental norms and reduction in emissions � Improvement in operating environment through suppression of noise and dust � Facilitate improved operations and maintenance practices

7. Based on the above design objectives, the typical measures for energy efficient rehabilitation of coal-fired generation units are provided in Table-7.

Table-4.2: Typical Energy Efficient Renovation and Modernization Measures

Plant System Typical EE R&M Measures

Boiler and related auxiliaries

� Improving combustion by replacing burners and mill internals � Arresting air leakages by replacing worn-out ducts and plugging all leaks in the furnace

and penthouse area � Reducing dry flue gas heat loss by introduction of additional heat transfer area � Reducing leaks in air heater by providing improved seals � Reducing auxiliary consumption using variable frequency drives and replacement of boiler

feed pump cartridges with energy efficient models � Replacing high pressure valves with problems / replacing internals of high pressure valves � Replacement of high pressure parts and tubes with advance design and materials.

Turbine and related auxiliaries

� Replacement / modification / retrofit with reactive blading of HP, IP and LP turbines � Making entire regenerative system operational � Modification of cooling water pumps and condensate extraction pumps. � Improving heat transfer in condensers, heaters and other heat exchangers.

Generator � Increase of generator rating by using better insulation, improved cooling and better sealing

Control and Instrumentation Systems

� Replacement of entire C&I system with distributed digital control (DDC) system. � Advanced control systems for (i) Furnace safeguards supervisory system, (ii) Automatic

turbine run-up system, including electro-hydraulic governor controls, (iii) Turbine protections, and (iv) HP, LP by-pass system.

� New steam and water analyzer (SWAS) system complete with wet and dry panels for online information of chemical condition of steam and water.

� New uninterrupted power supply (UPS) system to establish reliability of power supply for new DDC, Furnace Safeguard Supervisory System, etc.

Balance of Plant

� Enhancing capacity of coal handling plant, replacing idlers for conveyors, augmenting stacking capacity etc.

� Strengthening and expanding Ash handling system � Fire detection and protection system � Demineralized water system, service water system

Environmental and Social Considerations

� Advanced control systems with auto-rapping mechanism shall be retrofitted. � Suppression of dust in coal handling plant – water sprinkler system to suppress dust at

transfer points in coal handling plant will be incorporated. � Ash handling plant – water recirculation system to recover water from ash dyke area. � DM plant – complete piping and valve will be replaced with HDPE.

44

Participating States 8. The Bank and GOI have agreed to focus on 110MW and 210MW units which are in urgent need for R&M in India. The pilots would cover 640 MW of total capacity across three states, with two generation units of 210 MW, and the another two of 110 MW. A detailed study of all the eligible generation units (20-25 years age, state utilities owned and 210MW/110MW size) in the country was carried out. The following generation units have been selected for participation in the project:

i) Unit-5, Bandel Thermal Power Plant, West Bengal (210 MW) ii) Unit-6, Koradi Thermal Power Plant, Maharashtra (210 MW) iii) Units-3 & 4, Panipat Thermal Power Plant, Haryana (110 MW each)

9. The selection of states for pilot interventions has been done in discussion with the Ministry of Power, based on the scale of R&M requirement in the state as identified by CEA and the scope for achieving better energy efficiency and environmental performance by the utility going forward. Most importantly, each participating state utility has demonstrated its willingness to comply with the criteria specified in GEF Project Brief, i.e. (a) carry out energy audits to prepare a baseline performance for the unit; (b) install the required measurement systems and submitting information on a timely basis to the Bank; (c) develop and implement, to the satisfaction of the Bank, EE R&M scheme design; (d) follow all fiduciary and safeguard requirements of the Bank; (e) demonstrate that O&M practices would be (made) adequate; (f) demonstrate financial and economic viability of the scheme.

10. The project would involve phased implementation of R&M activities in these three states, starting with Bandel Unit-5, followed by Koradi Unit-6 and finally Panipat Units 3&4. Accordingly, the project preparation activities in the three states would also be phased, as indicated in the figure below. While the preparation activities are in an advanced state in West Bengal and Maharashtra, it is expected that status of project preparation in Haryana would be measured against criteria defined in Section-C6 of the main PAD prior to any disbursement for the state.

Indicative R&M Preparation and Implementation Timelines

Calender Year →Quarter → 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4Unit-5, Bandel, West BengalEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&MUnit-6, Koradi, MaharashtraEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&MUnits 3&4, Panipat, HaryanaConsultant ProcurementEnergy Audit and R&M DesignProcurementLead-Time for SuppliesUnit Shutdown for R&M

2007 2008 2009 2010 2011 2012 2013 2014

45

Unit-5, Bandel Thermal Power Station (BPTS), West Bengal 11. Bandel Thermal Power Station (BTPS) has five generation units – four of them of 82.5 MW capacity each (commissioned in late 1965-66), and the fifth of 210 MW (commissioned in 1982). The first four units are planned for replacement with a new unit of at least 500 MW capacity, and the fifth unit is covered under the Bank project for EE R&M.

12. Unit-5 of Bandel Thermal Power Station is operating with a heat rate of 2872 kcal/kwh against design value of 2424 kcal/kwh. The oil consumption is also high at about 20 ml/kwh against a design value of 5 ml/kwh. The unit is based on modified sub-critical Rankine cycle with one reheat and seven regenerative feed-water heating stages (3 High Pressure heaters, 4 Low Pressure heaters and deaerator). The turbine is of three-cylinder reheat, condensing type. This plant employs direct cooling system for condenser. It has a boiler of ABL make and turbine of BHEL (LMZ) make. Generator is supplied by BHEL. Boiler is a single drum, water tube, natural circulation type with super heaters and reheaters. It has a front firing system with six ball and race mills. Boiler is designed for coal with 35 percent ash and calorific value of 4445 kcal/kg.

13. Performance of Unit-5 is constrained by lower than designed calorific value of coal, because of which all the six mills have to be in operation. Induced Draft (ID) fans and Primary Air (PA) fans also operate at full capacity without any margin. Also there is leakage in High Pressure (HP) turbine parting plane. Combustion control of the unit does not operate in auto mode. Condensate extraction pumps are not able to meet the requirements of scheduled load. A comprehensive energy audit and R&M design consultancy has been conducted by M/S STEAG. The basic scope of the assignment includes Energy Audit, Baseline Mapping and Remnant Life Assessment/Condition Assessment.

Unit-6, Koradi Thermal Power Plant, Maharashtra 14. Koradi Thermal Power Station (KTPS) has seven generation units. (Units 1 to 4 of 105 MW each, Unit 5 of 200 MW, and Units 6 & 7 of 210 MW each). Unit 6 is covered under Bank Project for EE R&M.

15. Unit-6 of Koradi Thermal Power Station achieved PLF of 72.2 percent during 2007-08 and had availability of 91 percent. Unit 6 is of natural circulation reheat type. Boiler, turbine and generator are of BHEL make. It employs bag filters to assist performance of ESP. Comprehensive RLA studies and energy audit studies have been completed by design consultants – STEAG. Work on finalization of technical specifications based on the selected design option is in progress.

Units-3 & 4, Panipat Thermal Power Plant, Haryana 16. Panipat Thermal Power Station (PTPS) has 8 generation units, first four of 110MW, the next two of 210MW and the two latest units of 250 MW. Units 3 and 4, under consideration for EE R&M under the project, were commissioned in the year 1985 of 1987, respectively.

Units 3&4 of PTPS are operating at heat rates of about 3465 kcal/kWh against design heat rate of 2529 kcal/kWh. The PLF for these units was 77.57 percent and 67.4 percent respectively during 2007-08. The boilers of units 3&4 are radiant, dry bottom, water wall tubes, single drum, tangentially fired, natural circulation, direct pulverized coal fired with a balanced draft. Boiler is provided with 6 Nos. bowl type mills. Both boiler and turbine are supplied by BHEL. Turbine is of impulse type, SKODA make, 26 stages, 3 cylinder, horizontal condensing, reheat, regenerative type. Generator is hydrogen cooled with terminal voltage at 11 KV. While the boiler was designed for burning coal of caloric value of 4800 kcal/kg, the coal supplied from Dhori and South Karanpura in Bihar has calorific value of around 4000 kcal/kg. The poor quality of coal, coupled with poor operation and

46

maintenance practices have resulted into rapid wear and tear of plant which operated now in circle deviation to design values. HPGCL had appointed M/S STEAG to conduct R&M, RLA studies of units 3 during 2002. Similar studies for unit 4 were awarded to Central Power Research Institute. Based on these studies and findings in energy audit to be carried out, HPGCL along with consultants will finalize the scope of R&M.

Component 2: Technical Assistance (US$7.5 million)

17. As described in Section A1, implementation of EE R&M at state-level in India is inhibited by several barriers. While Component 1 (Energy Efficiency R&M Pilots) would support the demonstration of EE R&M approaches across three states and 640 MW of generation capacity, Component 2 aims at measures to address several of these barriers through studies, workshops, capacity building and support to more EE R&M initiatives. A description of the various measures contemplated to address barriers to R&M, on which the project design have been based, is provided in the table below.

Table-4.3: Measures contemplated to overcome barriers to Energy Efficient R&M

Barrier Measures contemplated

Energy Shortages. Due to the prevailing generation shortage in the country, and the relatively low cost of generation from old plants (since these are fully depreciated), utilities find it difficult to take old generation units out for major R&M. Taking plants off-line for longer periods of time to do major work is politically risky and economically damaging.

� The project aims to reduce the plant outage to the minimum possible by conducting detailed RLA & Energy Audit studies of the plant to minimize surprises at the time of opening the machines.

� Detailed Design studies of the plant also enable to systematically plan the shutdown and ensure that all the required equipments are available at the time of shutdown. Detailed studies would also help reduce the risk of surprises on opening of machines.

� Possibility of short term allocation of power supplies from GOI’s unallocated share of 15 percent of total central sector generation is being explored with GOI with a view to encourage EE R&M.

Regulatory issues. There is little regulatory incentive to invest in R&M, even as there is uncertainty whether full R&M capital expenditure will be passed through in generation tariff. In the prevailing cost-plus tariff regime, it is likely that benefits of the R&M investment would be passed through entirely to the customers by means of generation tariff reduction. Even though the National Tariff Policy announced in 2006 provides for a multi year tariff framework to cover inter-alia the capital investments necessary for R&M, and suggests sharing of benefits of efficiency improvements, the

� As a part of the project, a study on options for regulatory treatment of R&M projects has been undertaken with funding from ESMAP. The study has been conducted in close coordination with several state electricity regulators. The findings of the study have been disseminated through a workshop. (see Annex 1)

� Capacity building measures under Technical Assistance include support to generators and regulatory staff on regulatory aspects of R&M.

� The team would continue dialogue with GOI on implementation of relevant provisions of National Tariff Policy, 2006.

47

modalities for implementing the same remain unclear.

General financial distress of state power utilities. The poor financial situation in the state power sector results in limited debt servicing ability of the companies. Available financing is usually consumed in fire fighting or inadequately planned schemes instead of schemes with long payback and short-term costs, such as R&M. Even when R&M is financed usually the lowest capital expenditure option is considered first.

� The project does not directly address the financial distress in the power sector. However, each sub-project proposed for financing will be subject to financial and economic appraisal wherein eligible projects will have to demonstrate adequate financial viability including future O&M budgets.

� With efficiency increases resulting from EE R&M and a part of the resulting benefits being passed to the generation utilities, the financial health of these utilities would be strengthened.

� As part of the Project a Financial Management Plan was prepared which aims at improving the financial management performance (corporate governance, financial accountability aspects) of the clients.

Lack of energy efficiency orientation. In the past Indian generators and the Indian government system had been primarily concerned with improving availability, life extension and capacity enhancement in designing rehabilitation of coal fired generation units. There has been little focus on energy efficiency improvement, in part attributable to the administered pricing (till mid-90s) and relative abundance of coal in India. This tendency has also been enhanced by PLF linked performance monitoring and incentives rather than heat rate linked incentives. However over the last few years GOI is laying emphasis on improving energy efficiency in power generation.

� The project requires measurement of energy efficiency performance and incorporation of energy efficiency as a primary criterion for R&M project design

� The team proposes to work with the Central Electricity Authority to incorporate energy efficiency parameters in the regular reporting requirements of all generators.

Inadequate O&M practices and internal management capacity. Most state government generators, with a few exceptions, have weak capacity in terms of skills for operating and maintaining plants. This has resulted in the long-term benefits from past R&M being unsustainable. Measurement and monitoring systems prevalent are outdated and often highly inadequate. Accountability for performance in this environment is generally low.

� Under ESMAP funding the Bank has hired consultants for BTPS (West Bengal) and KTPS (Maharashtra) for strengthening the current O&M practices and procedures. A similar study is proposed for PTPS (Haryana). It is also proposed to hire additional consultants to implement the recommendations. These will be funded with TA resources.

� In addition, the M&E system to be put in place by this project will improve accountability.

� The Partnership for Excellence program addresses this by requiring under performing generators to work with NTPC (and other strong generators) to improve their O&M practices before design of

48

R&M project and sanction of financing.

Lack of long-term financing for R&M. The Capital Expenditure for R&M needs to be managed in such manner as to reduce the short-term increase in power cost from the generator. However, the financing traditionally available for R&M has been of relatively short tenor of up to 7 years thereby increasing the cash outflows of the generators and hence their tariff requirement.

� Demonstration of EE R&M approaches and sustained improved performance of plants under long term funding from the World Bank would allow local financial institutions and other international agencies to offer better long-term funds

Policy barrier to energy efficiency. While there has been a general recognition of the importance of R&M investments there has not been a comprehensive policy thrust for R&M in the past. Recently the National Electricity Policy (2005) and the National Tariff Policy (2006) have made appropriate enabling provisions to allow development of comprehensive regulatory and financing frameworks.

� Bank, in its dialogue with GOI, highlighted the fact that the thrust on ensuring energy efficiency as an important criterion in R&M project design needs to be increased.

� An agreement has been reached that the Project will demonstrate the framework and modality of doing the same and will work closely with states for timely and satisfactory implementation.

18. Accordingly, the technical assistance component of the project is aimed at supporting – (i) design of Energy Efficiency R&M projects, (ii) implementation of demonstration EE R&M investments funded under Component 1 of the project, (iii) measures to address barriers to replication of EE R&M projects in India, and (iv) strengthening of overall institutional capacities of the generation utilities and other relevant sector entities. Accordingly, sub-components for the technical assistance program have been formulated as follows:

19. Sub-component-1: Support for Design of Energy Efficiency R&M (US$2.5 million). This sub-component would support Design Studies (including Energy Audit, Residual Life Assessment, Preparation of DPR, Technical Specifications and Conducting Bid Process), Environmental Assessment and Social Assessment studies for a pipeline of R&M sub-projects with a focus on energy efficiency. Studies are already underway for Unit-5, Bandel and Unit-6, Koradi with funding from PHRD grants. Similar studies for Units 3 & 4, Panipat would be undertaken under this sub-component.

20. In addition, this sub-component would also cover additional generation units which are not included for financing under Component 1 (EE R&M Pilots) of the project. It would finance the design and safeguards preparation for EE R&M of about 840 MW of additional capacity in Maharashtra, thus creating a pipeline of such projects. The additional plants in Maharashtra include Units 1 & 2 of Chandrapur Thermal Power Plant, Unit -2 of Bhusawal Thermal Power Plant and Unit- 3 of Parli Thermal Power Plant. It is expected that this technical assistance would lead to implementation of EE R&M approaches in at least an additional 840 MW (5 percent) of 18360 MW of old 110MW/210MW capacity in the country.

21. Sub-component-2: Support for Implementation of Pilot EE R&M Investments (US$1.5 million). This sub-component would support the hiring of consultants for monitoring the implementation of EE R&M investments funded under Component 1 of the project in the three

49

pilot states. This would include hiring of implementation support consultant (owner’s engineer) and quality assurance consultants. The implementation support consultant will assist the utility through the entire implementation phase (from selection of vendor to completion of R&M activity) and ensure that R&M works are executed as per the schedule. The quality assurance consultant will ensure that there is no compromise in quality of supplies and works, and would also certify completion of milestones for release of payments.

22. Sub-component-3: Measures to Address Barriers to EE R&M Projects (US$1.1 million) Under the sub-component GEF grant funds are being made available for technical assistance to CEA aimed at addressing barriers to R&M in India, expanding supplier/consultant interest, reviewing experience from pilot R&M interventions, and strengthening institutional capacities at CEA.

� Assistance to CEA in development of wider R&M program in India through several consultancy studies, including inter-alia:

o Reduction of Barriers to R&M interventions through studies that address the identified barriers and examine more barriers to enable a wider R&M program to be taken up successfully. This could include preparation of technical paper on “surprises” in R&M and strategies to deal with them.

o Developing market for implementation of R&M in India by organizing workshops/ road shows to elicit greater participation by design consultants and suppliers in R&M projects in India and exploring Public Private Partnership (PPP) models.

o Reviewing experience from pilot R&M interventions to extract learnings on procurement, R&M implementation and improved O&M practices in World Bank and Kfw financed pilot projects.

� Institutional Capacity Strengthening at CEA: The aim of this exercise is to identify measures to strengthen the functioning of CEA, especially in respect of R&M program in the country. This would include benchmarking CEA with other comparable International and Domestic agencies, examining expectations of the customers of CEA, reviewing the organization structure and skills and finally preparing and implementing the capacity strengthening interventions.

23. Sub-component-4: Support for Strengthening Institutional Capacities of Generation Utilities (US$2.4 million)

Under ESMAP funding Bank has hired consultants for BTPS (West Bengal) and (KTPS) Maharashtra for strengthening the O&M practices and procedures. A similar study needs to be conducted for PTPS (Haryana). Consultants need to be hired to conduct more detailed O&M studies and help implement solutions like conducting a performance improvement program, introducing/ strengthening MIS, adherence to the operations manual through systematic checks and introduction of measures to expedite decision making, increase accountability and promote use of control systems. In addition, this component would also support initiatives for strengthening overall corporate governance and management systems to allow smoother implementation of more R&M projects going forward, and enable better management practices for improved operation of the plant. 24. A summary of the four sub-components is presented in Table-9 below.

50

Table-4.4: Summary of Technical Assistance Component

Ser Description Estimated Cost

(USD)

Implementing Agency

Timeline / Status

Support for Design of Pipeline of Energy Efficiency R&M Interventions 1 Units 3&4 Panipat (Haryana) 500,000 HPGCL Procurement of consultants already

initiated in January 2009 2 Units 1&2 Chandrapur (Maharashtra) 1,000,000 MSPGCL Procurement of consultants already

initiated in September 2008 3 Unit-2, Bhusawal (Maharashtra) 500,000 MSPGCL Procurement of consultants already

initiated in November 2008 4 Unit-3, Parli (Maharashtra) 500,000 MSPGCL Procurement of consultants already

initiated in November 2008 Sub-Total 2,500,000

Support for Implementation of Pilot EE R&M Interventions 1 Unit-5, Bandel (West Bengal) 500,000 WBPDCL Procurement of consultants would be

initiated by end February 2009 2 Unit-6, Koradi (Maharashtra) 500,000 MSPGCL Procurement of consultants would be

initiated by end March 2008 3 Units 3&4, Panipat (Haryana) 500,000 HPGCL Procurement of consultants would be

initiated by end June 2010 Sub-Total 1,500,000

Support for Addressing Barriers to EE R&M Projects 1 Assistance to CEA in development of

R&M Program through about 3~4 studies. (Areas include: (i) Consultancy Support for Implementation of TA sub-component; (ii) Reduction of barriers to R&M in India; (iii) Developing Markets for Implementation of R&M in India; and (iv) Review of Experience from Pilot R&M Interventions).

750,000 CEA Procurement of consultants for the first assignment would be initiated by June 2009. The procurement of consultants for the other assignments would follow thereafter. Reports from other ESMAP funded assignments would also be shared with CEA.

2 Institutional capacity strengthening at CEA 350,000 CEA Institutional Capacity Strengthening Program to be finalized during appraisal.

Sub-Total 1,100,000 Support for Strengthening Institutional Capacity of Implementing Agencies

1 Institutional capacity (including O&M practices) strengthening at MSPGCL

800,000 MSPGCL Activities to be carried out between Mar 2009 and Sep 2011

2 Institutional capacity strengthening (including O&M practices) at WBPDCL

800,000 WBPDCL Activities to be carried out between Mar 2009 and Sep 2011

3 Institutional capacity strengthening (including O&M practices) at HPGCL

800,000 HPGCL Institutional capacity assessment studies to be carried out between Jul 2009 and Jun 2010. Action Plan to be implemented between 2010 and 2013.

Sub-Total 2,400,000 GRAND TOTAL 7,500,000

51

Annex 5: Project Costs

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

Foreign US$ million Project Cost By Component

Local US$

million IBRD GEF

Total US$ million

Component 1: Energy Efficiency R&M Pilots

a. Unit-5, BTPS, West Bengal Plant and Equipment 1.6 47.6 10.0 59.2 Erection and Commissioning 13.2 0.0 0.0 13.2 Total Baseline Cost 14.8 47.6 10.0 72.4 Physical Contingency 1.7 5.5 1.2 8.4 Price Contingency 1.8 5.8 1.2 8.8 Total Project Cost 18.3 58.9 12.4 89.6 Interest During Construction 7.2 0.0 0.0 7.2 Front End Fee 0.0 0.1 0.0 0.1 Total Financing Required 25.5 59.0 12.4 96.9

b. Unit-6, KTPS, Maharashtra* Plant and Equipment 1.6 47.6 10.0 59.2 Erection and Commissioning 13.2 0.0 0.0 13.2 Total Baseline Cost 14.8 47.6 10.0 72.4 Physical Contingency 1.7 5.5 1.2 8.4 Price Contingency 1.8 5.8 1.2 8.8 Total Project Cost 18.3 58.9 12.4 89.6 Interest During Construction 7.2 0.0 0.0 7.2 Front End Fee 0.0 0.1 0.0 0.1 Total Financing Required 25.5 59.0 12.4 96.9

c. Units 3&4, PTPS, Haryana* Plant and Equipment 1.8 50.0 10.5 62.3 Erection and Commissioning 13.8 0.0 0.0 13.8 Total Baseline Cost 15.6 50.0 10.5 76.1 Physical Contingency 1.8 5.7 1.2 8.7 Price Contingency 1.9 6.1 1.3 9.3 Total Project Cost 19.3 61.8 13.0 94.1 Interest During Construction 7.6 0.0 0.0 7.6 Front End Fee 0.0 0.2 0.0 0.2 Total Financing Required 26.9 62.0 13.0 101.9

Summary Totals for Component 1 Total Baseline Cost 45.2 145.2 30.6 221.0 Physical Contingency 5.2 16.7 3.5 25.4 Price Contingency 5.5 17.7 3.8 27.0 Total project Cost 55.9 179.6 37.9 273.4 Interest During Construction 22.1 0.0 0.0 22.1 Front End Fee 0.0 0.4 0.0 0.4 Total Financing Required 78.0 180.0 37.9 295.9

52

Foreign US$ million Project Cost By Component

Local US$

million IBRD GEF

Total US$ million

Component 2: Technical Assistance a. Support for Design of Energy Efficiency

R&M (for about 1000MW capacity) 2.5 2.5

b. Support for Implementation of Demonstration EE R&M Investments

1.5 1.5

c. Measures to Address Barriers to EE R&M Projects

1.1 1.1

d. Support for Strengthening Institutional Capacities for R&M Implementation

2.4 2.4

Total Financing Required 7.5 7.5

Grand Total Financing Required 78.0 180.0 45.4 303.4

* Cost Estimates for Unit-6 KTPS are based on the draft Detailed Project Report provided by the Design consultants. Cost Estimates for Units 3&4 PTPS are provisionally based on the detailed project report for Unit-5 BTPS.

53

Annex 6: Implementation Arrangements

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

1. Arrangements for Implementation of Project Investments: The investment component of the project will be implemented through the selected generation utilities – WBPDCL (West Bengal), MSPGCL (Maharashtra) and HPGCL (Haryana). Reputed consultants under the R&M Design assignment shall be responsible for energy audit, residual life assessment, identification of various design options, support in selection of optimal R&M design option based on a detailed cost-benefit analysis, and support in preparation of bid documents and selection of contractors. A team of staff from corporate and plant offices of the utility would be responsible for managing these activities. To supplement existing project monitoring capacity, project implementation consultants would be appointed by each utility during the implementation phase. In addition, independent third-party quality assurance consultants would be appointed to confirm achievement of project milestones and adherence to quality plan.

2. Implementation Arrangements for Technical Assistance. The vast majority of technical assistance will be implemented by the state generation utilities. This includes (i) design and safeguard studies for Bank funded EE R&M pilots and for additional pipeline of R&M projects, (ii) project implementation consultancy support, (iii) support for addressing barriers to EE R&M, and (iv) capacity building aspects in the areas of O&M, corporate governance, financial management and others for enhanced sustainability and replication of EE R&M initiatives. Technical assistance for which the impact is broader than a single state utility, such as policy studies and information dissemination, and support for formulation of a wider R&M program, will be implemented by the Central Electricity Authority, Ministry of Power, Government of India.

3. Role of Ministry of Power (MOP), Government of India: MOP is the key counterpart in formulation of this project as well as the formulation of the overall R&M program and policy for the country as a whole. It has been closely involved in the selection of EE R&M demonstration units and is also the key counterpart for discussions aimed at identifying measures to address barriers to R&M in India.

4. The Central Electricity Authority (CEA), which is an attached office of the Ministry of Power, would be responsible for sector level monitoring of power plant performance and overseeing the progress in implementation of broader R&M program in the country. This is consistent with the mandate given to the CEA by Government of India. The Bank team would be interacting closely with CEA for dissemination of the experience from demonstration projects and promotion of EE R&M approaches throughout the country.

5. Implementation of Operations and Maintenance Strengthening Measures: As a part of the O&M workshops held in May 2008, an “Executive Overview Committee” has been constituted at the corporate level in Maharashtra and West Bengal, which would review the overall O&M strengthening program. In addition, plant level or corporate level champions have been identified for design, implementation and review of various specific O&M strengthening interventions.

54

6. Tie-in with arrangements for sector reforms and institutional capacity building: There is an ongoing sector reforms and capacity building program in each of the select states, where the World Bank is involved through other lending and non-lending engagements.

a) Government of West Bengal is undertaking a comprehensive program for power sector restructuring and institutional capacity building with support from the Department for International Development (DfID), Government of United Kingdom and the World Bank (Project No. P109176 – Non-lending Technical Assistance support). Under the program, the process of sector unbundling has been completed and detailed plans for policy reforms and strengthening institutional arrangements have been drawn. Government of West Bengal (GoWB) maintains an oversight on the design and implementation of these measures. While the focus so far has been on Transmission and Distribution sub-sectors, it has now turned its attention to generation utilities in the state. GoWB is overseeing the plan for institutional capacity development at the company which is founded on three pillars – Improved Governance, Enhanced Operational Performance and People Excellence.

b) MSPGCL is the second largest power generation company in India, and has embarked on a very large capacity augmentation program comprising of greenfield capacity addition, replacement of very old plants and R&M where economically attractive. MSPGCL has prepared a detailed institutional capacity development program and has proposed the use of GEF grants for conducting studies on Updating of Accounting and Procurement manuals, Strengthening of MIS systems etc.

c) The Bank is engaging in the Haryana power sector through this project in the generation sub-sector and through a separate project in the transmission and distribution sub-sectors. The overall sector development issues are being discussed across these two projects with the ministry of power of Haryana government. In addition, the institutional capacity strengthening aspects will be implemented through the generation utility with the concurrence of the government.

55

Annex 7: Financial Management and Disbursement Arrangements

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

Summary of Financial Management (FM) Assessment

1. The coal fired generation rehabilitation project (the project) involves the rehabilitation and modernization of three thermal power plants (i) Unit 5 - Bandel owned by West Bengal Power Development Corporation Limited (WBPDCL), (ii) Unit 6 - Koradi owned by Maharashtra State Power Generation Company Limited (MSPGCL/ Mahagenco) and (iii) Units 3 & 4 Panipat owned by Haryana Power Generation Corporation Limited (HPGCL). The project would be funded through IBRD loan of USD 180 million and GEF grant of USD 45.4 million. The technical assistance component of GEF grant includes technical support to Central Electricity Authority (CEA). The Annex covers financial management and accountability arrangements at the project and implementing entity levels. While the FM assessment of WBPDCL, MSPGCL and CEA is completed, the assessment of HPGCL will be completed in the first year of the project..

2. WBPDCL was incorporated in 1985 as a private limited company under the Indian Companies Act, 1956 wholly owned by the Government of West Bengal (GoWB) primarily as a generating company. MSPGCL was incorporated in 2005 as a result of restructuring of the erstwhile Maharashtra State Electricity Board (MSEB) into four companies19. HPGCL was incorporated in 1997 as a result of unbundling of the erstwhile Haryana State Electricity Board (HSEB)20. CEA21 will receive funds for the technical assistance aggregating USD 1.1 million.

3. WBPDCL and MSPGCL have financial management systems which are considered adequate, to account for and report on the project resources and expenditures accurately. However, these systems, for meeting the needs of the entities need to be further strengthened as detailed later. Action plans for enhancing corporate governance and financial accountability (CGFA) arrangements for the two companies have been prepared and agreed as a part of the preparation of this project (refer Table 6 later in the Annex). Actions have been initiated on some of the critical issues and the balance will be implemented during the implementation of the project.

4. HPGCL’s financial management systems, corporate governance and financial accountability arrangements are in the process of being assessed and a detailed time-bound action plan will be mutually agreed thereafter, for strengthening and enhancing these arrangements. Agreement on the action plan and initiation of steps for implementation of the action plan will be eligibility criteria for this component under the project.

19 MSEB was restructured into four companies (i) MSEB Holding Company, (ii) Maharashtra State Power Generation Company

Limited (MSPGCL/ Mahagenco), (iii) Maharashtra State Electricity Transmission Company Limited (MSETCL) and (iv) Maharashtra State Electricity Distribution Company Limited (MSEDCL).

20 HSEB was restructured into two companies (i) Haryana Power Generation Corporation Limited for the generation business and (ii) Haryana Vidyut Prasaran Nigam Limited for the transmission and distribution business. In the second transfer scheme the distribution business was transferred from HVPNL to Uttar Haryana Bijli Vitran Nigam Limited and Dakshin Haryana Bijli Vitran Nigam Limited respectively 21 CEA’s roles and responsibilities are defined under the Electricity Act 2003. .

56

Financial Management Strengths, Weaknesses and Mitigating Arrangements

5. The strength of the project in the area of financial management is that budgeting, accounting and reporting systems are operational which will be used for accounting and generating the required financial reports under the project. However both WBPDCL and MSPGCL have not received any IBRD loan in the past and thus do not have any experience of the Bank’s FM policies and procedures although WBPDCL has implemented projects that have been externally funded (eg. JBIC funded projects since 1997). There is some awareness of IBRD procedures among some senior serving officials of HPGCL since the erstwhile HSEB had earlier implemented a Bank financed project.

6. During the project preparation, the Bank team conducted a high level review of financial management, corporate governance and financial accountability arrangements of WBPDCL and MSPGCL22 which has indicated that the companies have institutionalized certain cardinal principles, in areas like accounting, auditing, internal control, budgeting and reporting which have laid the foundation for a basic financial accountability and corporate governance framework. However there is a need to further improve these arrangements since the two state-controlled companies are not under any corporate governance mandate and the financial systems and procedures are largely governed by decades old rules and regulations which in some cases are yet to be revised and updated. The review of HPGCL has been initiated and the CGFA report once completed will identify the areas that require further improvements together with the action plan. Initial assessment of HPGCL points toward the need for overall strengthening of all aspects of financial management and CGFA arrangements.

7. The FM and CGFA reviews undertaken during project preparation have identified a few areas23 where WBPDCL and MSPGCL need to take actions and an action plan for strengthening CGFA arrangements has been discussed with WBPDCL and MSPGCL to further develop FM capabilities in these areas. Several actions have been initiated during preparation of the project. In case of WBPDCL they include appointment of independent directors, constitution of an audit committee, conversion into a public limited company, strengthening internal audit function and in-year financial reporting. In case of MSPGCL the actions include migrating from accounting based on the Electricity Act to that prescribed under the Companies Act, updated delegation of powers, plans to update financial manuals, revamp internal audit function, appointment of an independent director and set up an audit committee. The preliminary review of HPGCL finds the need for overall strengthening of FM arrangements.

22 A report on “Corporate Governance and Financial Accountability (CGFA) arrangements” prepared by the Bank for these two

companies is available in the project files. Additionally, Bank also conducted a study in 2006, which reviewed the financial accountability arrangements of selected state level entities in power sector, and recommendations of which have been taken into account while conducting these CGFA reviews.

23/ Most importantly there is a need to strengthen further the internal audit framework and there is a need to develop finance manuals.

57

Table-7.1: Financial Management Risk Rating Previous

Risk Assessment

Risk Mitigating Measures Residual Risk

Inherent Risks Country level (India)

M India country level rating relevant only to the extent of funds transfer between GOI and the states on back-to-back basis

M

Entity level (at MSPGCL, WBPDCL)

H

MSPGCL & WBPDCL - Action plan to improve corporate governance and financial accountability has been agreed; Internal audit arrangements are being strengthened; Independent directors have been appointed in WBPDCL; Independent directors to be inducted in the Board of MSPGCL in sufficient numbers (only one has been appointed); Both companies have taken action on updating financial management manuals. HPGCL – significant improvements required in FM and CGFA arrangements for which action plan will be prepared and agreed with management with credible actions on the ground in critical areas serving as an eligibility criteria

S

Project level S Only 4 contracts expected to be financed for R&M component in each company which would result in a few large & bulky payment transactions as per contractual terms. To enhance internal control and independent oversight, an independent supervision consultant/ quality assurance consultant (appointed under terms of reference acceptable to the Bank) will conduct the technical and financial verification of contractual progress and milestones achievement before payments are released

M

Overall Inherent Risk M Control Risks Budgeting S Few WB financed transactions could be separately tracked

by creating separate budget codes. Institutional capacity will be enhanced for planning and budgeting.

M

Accounting S Separate General Ledger codes for WB financed contracts will be maintained to separately track these items.

M

Internal Controls S Independent third party monitoring arrangements will be put in place to assist in contract management. Invoices will be certified by this third party monitoring agent after verifying the contractual milestones, before payments are made. Adequate internal controls (including internal audit) are being put in place for WB financed project. A detailed project implementation plan will lay down project FM structure, delegation of powers, detailed procedures for receipt and expenditure of project funds, periodic reporting on project progress in an agreed format and audit (internal and annual) terms of reference. Annual project audited statements will be disclosed on the website of the

M

58

respective entities. Funds flow S Too many layers for the funds to pass through to

implementing entities. Direct payment options will be preferred. Contractual payment milestones will be designed in a manner that helps establishing clear linkages between physical outputs and the level of progress achieved. Counterpart funding will be made available

M

Financial Reporting

M Interim unaudited financial reports (IUFRs) will include additional reconciliations of contract wise expenditures

M

Auditing S Independent auditor, acceptable to the Bank, with agreed terms of reference for WB financed project

M

Overall Control Risk M Residual Risk Rating Moderate

8. Although the FM risk from a fiduciary perspective for this project is rated at Moderate, there are significant corporate governance and FM capacity issues at an institutional level in the implementing entities for which an action plan24 has been agreed upon for MSPGCL and WBPDCL. A similar action plan will be agreed for HPGCL during implementation of the project.

Arrangements for Oversight and Accountability

9. WBPDCL, MSPGCL and HPGCL will be responsible for the FM arrangements of the project handled by them. WBPDCL is wholly owned by GoWB. A registered Private Limited Company under the Companies Act, 1956 it converted into a Public Limited Company on June 16 2008 and on December 12 2008 four independent directors were appointed to its Board. WBPDCL’s Board of Directors (Board) comprises a Chairman (a Minister in GoWB), Managing Director (MD), three government nominee directors, three independent directors and three full-time functional directors – technical, operations and finance. The board meets, on an average five times in a year. WBPDCL plans to set up an audit committee with independent directors.

10. MSPGCL is wholly owned by GoM and is responsible for generation of electricity in the state of Maharashtra. It is registered as a Private Limited Company under the Companies Act, 1956. By virtue of being a private limited company and wholly owned by GoM, MSPGCL has limited financial and operational autonomy with regard to decision making. MSPGCL has plans to convert into a Public Limited Company at the opportune time and bring in greater transparency and accountability although no time frame has yet been specified. MSPGCL’s Board comprises a Chairman (part-time), MD, one government nominee director, a recently-appointed independent director and three full-time functional directors (finance, operations and projects). The Board meets twice a month on an average.

11. HPGCL is a Government Company under the Companies Act 1956. HPGCL has a ten-member Board comprising Chairman (FC&PS Power GoH); MD; three part-time directors25; two

24 Due to small loan size relative to the investment requirements of these companies, the extent of leverage under the present loan in influencing entity level reform actions is limited. However in spite of this, the companies have agreed to undertake several reform oriented actions (as detailed in later sections of this Annex) to strengthen transparency, corporate governance and accountability reflecting the ownership on these issues. 25 These directors are MDs of the unbundled utilities – HVPNL (transmission) and UHBVNL and DHBVNL (distribution)

59

full-time functional directors (projects, technical) and two independent directors (nominated by PFC and CEA). The Board meets on a monthly basis. There is a functioning audit committee, without independent directors.

12. The implementation arrangements for the project, which is institutionalized at different levels of hierarchies of the three organizations, are discussed in detail in Annex 6 of the PAD. MSPGCL, WBPDCL and HPGCL shall provide the fiduciary assurance to IBRD over proper and efficient use of loan proceeds. The mainstream FM systems of WBPDCL, MSPGCL and HPGCL (after strengthening), housed as a part of their general accounting and financial systems will be used to generate the financial and other progress reports under the project.

Project Costs

13. The total project cost is estimated at around USD 303.4 million. All R&M related project costs and expenditures will be paid for and recorded in the books of the respective implementing entities in accordance with their accounting policies and procedures. In addition to the three state generation utilities, a part of the Technical Assistance component (USD 1.1 million dollars – tentatively six consultancies) will be implemented by and paid through CEA, in line with the accounting policies and procedures detailed in the Operations Manual submitted by CEA. All of these will be prior review contracts and will follow the Bank procurement guidelines.

14. Under this project, the Bank will finance four large Renovation & Modernization (R&M) contracts for each of the three thermal generation plants at Koradi (MSPGCL), Bandel (WBPDCL) and Panipat (HPGCL) procured under the project. The number of transactions under the project is expected to be few, but large and bulky. All contractual payments will be made after due verification of the bills in accordance with the procedures laid down by the companies in the project implementation plans and their delegation of powers. There would be an independent quality assurance consultant to be employed by each of the three companies who would verify the achievement of the contractual milestones to enable and certify payment. Under the project the companies will prepare separate project financial statements, which will help in distinguishing costs financed by the proposed loans. The utility capacity building activities under the TA component will include consultancy support in the areas of O&M, corporate governance, financial management and others.

Funds Flow

15. The Project funds (IBRD of USD 180 million and GEF grant of USD 45.4 million) will flow from World Bank to GOI. In line with normal practices, an appropriate budgetary line item will be established by DEA (CAAA) for external funds, and similarly appropriate arrangements will be made on the expenditure side for transfer of these proceeds to the states (by way of regular channel of ‘Additional Central Assistance’). GOI will pass on these funds to the respective states (West Bengal, Maharashtra and Haryana) on terms and conditions (interest rates, repayment terms, foreign exchange rate risk) which mirror the IBRD and GEF terms (i.e. on a back-to-back basis) within two weeks of receipt of funds.

16. The states will also transfer, within two weeks of receipt, these proceeds to the respective utilities (WBPDCL, MSPGCL, HPGCL) on terms which mirror the IBRD/GEF terms, including the interest rates, repayment terms and the foreign exchange rate risk. The respective state governments will also need to make suitable budgetary provisions on receipt / expenditure side to receive/ make transfer of these monies.

60

17. The funds flow options for the loan project are (i) direct payments by the Bank to the supplier/ contractor/ consultant in foreign currency and/ or rupee payments above a threshold limit based on bills that are duly approved and authorized for payment and (ii) funds flowing through GOI to the project via Ministry of Power / the state governments (GoWB, GoM, GoH) as appropriate. In the latter case, the project will open a separate bank account in a Commercial Bank to receive the initial advance (based on forecasts for next six months) under the funding arrangements followed by periodic replenishments based on next two quarters’ forecasts as reflected in the interim unaudited financial reports (IUFRs). WBPDCL has expressed its preference for direct payments by the Bank for the investment component of the project. CEA has also expressed preference for direct payment to the consultants by the Bank for the Technical Assistance component. The remaining entities – MSPGCL and HPGCL have preference for forecast based advance and replenishments.

Impact of procurement arrangements

18. The contracts being funded under the project for each of the implementing entities are limited as laid out in the procurement section. R&M contracts will be first initiated by WBPDCL, to be followed by MSPGCL and thereafter by HPGCL. As these R&M contracts are not routine (being based on turnkey principles) for these companies, for allowing good contract management there will be a need for close interaction between the procurement/ engineering staff and the finance staff.

Disbursement Arrangements

19. Disbursements would be made by the Bank on the basis of quarterly IUFRs26, which would forecast the expenditures for two quarters and report the actual for past quarter and cumulative till date. IBRD/ GEF funds for R&M contracts will be disbursed on a pro-rata basis, and the equity component will also be brought in by the company on a pro-rata basis. The report would also provide contract-wise details of the financial progress and the physical progress under the project. Supporting documentation including completion reports, certificates and other documentation, will be retained by the companies and made available to the Bank during project supervision. These documents shall be audited as a part of annual project financial statements audit.

20. Designated Account: An account (denominated in USD) will be established in RBI by Government of India (GOI) to receive the Bank funds. The generating companies shall established separate bank accounts for these rehabilitation projects.

21. Retroactive Financing: Retroactive financing up to an amount of not exceeding 10 percent of the loan amount will be available under the project, for payments made within 12 months prior to the expected date of the legal agreement. To be eligible, the activities should be procured in line with the Bank guidelines on procurement.

22. Allocation of Loan Proceeds: The allocation of Loan proceeds by disbursement category and allocations will be made as indicated in Table7.2 below:

26 The suggested formats have been provided. WBPDCL/ MSPGCL/ HPGCL will have the flexibility of furnishing reports earlier (say on a monthly basis) to seek early replenishments wherein they could also provide forecasts for a shorter period than six months.

61

Table 7.2: Allocation of Loan Proceeds

Category Amount of the Loan Allocated

(Expressed in USD)

Amount of GEF Grant Allocated

(Expressed in USD)

Percentage of Expenditures to be financed (inclusive of

taxes) (1) Goods and ‘Supply and Installation’

a. Unit-5, BTPS, West Bengal b. Unit-6, KTPS, Maharashtra c. Units 3&4, PTPS, Haryana

58,852,500 58,852,500 61,845,000

12,450,000 12,450,000 13,000,000

74%27

(2) Consultants’ Services a. Unit-5, BTPS, West Bengal b. Unit-6, KTPS, Maharashtra c. Units 3&4, PTPS, Haryana d. Ministry of Power (CEA)

1,300,000 3,300,000 1,800,000 1,100,000

100 %

(3) Front End Fee 450,000 Amount payable

pursuant to the Loan

Agreement (4) Premia for Interest Rate Caps and Interest Rate

Collars 0 Amount

payable pursuant to the

Loan Agreement

Total Amount 180,000,000 45,400,000

Budgetary Control

23. WBPDCL prepares annual unit-wise budgets and forwards them to WBERC based on which annual tariff order is issued by WBERC in June/ July. The annual tariff order is construed as the budget. The corporate expenses are allocated to the units in the tariff order. Funds disbursement to units and expenditure commitments are based on this budget. There is no revision of budgets during the year and there is no formal periodical monitoring of budget performance. To exercise effective cost control, there is a need for strengthening regular monitoring by management of actual performance against budget and analysis of variances for corrective action. MSPGCL prepares annual unit-wise budgets which are approved by the Board. Budgets are prepared on accrual basis and separate cash flow budget is also prepared. Accounts staff posted at various offices monitor the utilization of budget provisions. Monthly financial performance reports are prepared and discussed by the management at operating committee and project review meetings. In addition they also generate daily funds position report. HPGCL prepares annual budgets on commercial principles. The annual revenue requirements approved by the regulatory authorities serve as the organization’s budget. There is no formal system of periodic reporting on budget performance and variance analysis

24. WBPDCL and MSPGCL are taking steps for preparation of (i) detailed budgeting manual to further facilitate budgetary control and (ii) quarterly rolling cash forecasts for better 27 73.64% rounded off to 74%

62

management of funds, investments and returns. Action plan for improving budgetary control and funds management in HPGCL would be defined before disbursement begins.

25. During the implementation of the project, the entity budgets will reflect the annual project budget estimates based on physical work plans by means of a separate budget code/ line item. Monthly monitoring of project budget and actual performance will be carried out along with variance analysis and corrective action for timely project implementation.

Financial Accounting, Policies and Procedures

26. In case of all the entities finance teams are located at the Corporate Office (CO), and at each plant. CO and plants operate as separate accounting units. WBPDCL maintains its accounts in Tally, an off-the-shelf accounting package with limited features. Quarterly trial balance and schedules are prepared by each accounting unit but consolidation takes place annually at CO using spreadsheets. WBPDCL’s financial restructuring as part of reforms resulted in GoWB writing-off Rs.27.2 billion of its past loans and interest to WBPDCL and reducing WBPDCL’s receivables to that extent28. As a result, WBPDCL’s receivables are current.

27. MSPGCL implemented financial accounting and budgetary control (FABC) system in 1993-94 at CO and nine power stations with COBOL (front end) and flat file (back end). Quarterly trial balances are prepared by each accounting unit and consolidated at CO. This accounting system needs enhancement to meet the growing information requirements of MSPGCL.

28. In HPGCL accounting is carried out manually. There are considerable delays in annual accounts preparation, audit and adoption by the AGM. Audited accounts for 2006-07 are yet to be adopted. The accounting units prepare monthly trial balances which are consolidated at HQ. Half-yearly accounts are prepared (without schedules).

29. The financial statements (Balance Sheet and Profit and Loss Account) of the entities are prepared in terms of the Electricity Act 2003 and applicable accounting standards referred to in the Companies Act 1956 which mandates the preparation of annual financial statements on full accrual principles applying accounting standards issued by the Institute of Chartered Accountants of India (ICAI)29. In the event of inconsistencies the provisions of Electricity Act prevail. Significant accounting policies are disclosed in the annual report of all the entities and reviewed by the statutory auditors.

30. Deviations from ICAI’s accounting standards are pointed out through audit observations. WBPDCL has resolved most of the observations of the auditors. However, in case of MSPGCL (which operated under a special statute as an Electricity Board until its restructuring in 2005 as a company) the statutory audit report contains several observations concerning deviations from the requirements of Accounting Standards prescribed under the Companies Act. MSPGCL decided to comply with Companies Act requirements in accounts maintenance with effect from FY 2007-08 and appointed external consultants to assist in the process of migration and also to develop a

28 This has improved the capital structure and makes it possible for WBPDCL to access competitive institutional funding to meet its future modernization and expansion needs. Along with the loan write-off an equivalent amount has been adjusted against outstanding dues to WBPDCL on account of sale of energy to GoWB owned WBSEB 29 As per the India - ROSC (A&A) dated December 2004, the Indian Accounting standards are modeled on International Financial Reporting Standards (IFRS) and except for some small revisions (required for customization to local circumstances and legal requirements) are largely in consonance.

63

suitable accounting manual containing guidelines to maintain accounts according to Companies Act requirements in the future. MSPGCL has addressed most of the issues concerning non-compliance with accounting standards however several other repeat observations still appear in the FY 2007-08 audit report which the company needs to address.

31. There are large numbers of significant audit qualifications/ observations in the statutory auditors’ reports of HPGCL30 which needs to be suitably addressed by the management.

Finance Manual

32. Since inception WBPDCL have been following procedures and guidelines applicable to government companies, particularly the erstwhile West Bengal State Electricity Board (WBSEB). There are no separate financial manuals in WBPDCL and the delegation of powers has not been updated. The company is considering developing manuals covering accounting and internal controls to bring them at par with industry best practices. WBPDCL’s restructuring plan also suggests internal controls enhancements through development of suitable manuals and guidelines for meeting corporate governance requirements.

33. In case of MSPGCL, as part of its internal control framework manuals, guidelines, chart of accounts and delegation of powers have been prescribed from time to time. While the financial manuals are old (1994/ 1996), the delegation of powers has been recently updated and there are plans for updating/ recasting the financial manuals. The accounting manual is under preparation and the company has prepared scope of work for preparation of the remaining components of finance manuals.

34. Rules and regulations drafted by HSEB are still in force in HPGCL. Amendments to these rules and regulations have been issued from time to time. However these are in fragmented form and have not been consolidated/ compiled/ updated. The delegation-of-powers is the only document that has been consolidated and updated (up to August 2006). The management of HPGCL appreciates the importance of up-to-date manuals and guidelines to assist in day to day operations under proper controls and is considering preparation of suitable FM manuals.

35. The proposed finance manuals31 will provide guidance for carrying out day-to-day financial management activities (also covering the proposed project), bring about uniformity and consistency in practices across the companies’ operations and form the basis for audits and improvements.

Financial Reporting

36. WBPDCL has plans to introduce half yearly reporting of unit wise financial results to the Board from 2009-10 and switch to quarterly reporting effective from 2010-11 with added features such as comparison with budgets and variance analysis. There is no regular financial 30 The observations cover fixed assets records maintenance and physical verification, reconciliation of general ledger balances with sub-ledgers, reconciliation of inter-unit accounts, non-compliance with accounting standards (AS-2 valuation of inventories, AS-6 depreciation accounting), debit and credit balances netting, accounting for scrap, non availability of some inventory and stores details, non provision of certain liabilities etc (to name a few). 31 The manual will cover the accounting policies and accounting activities relevant to the companies such as billing and receivables, purchase and payables, fixed assets and depreciation, capital work-in-progress, stores, payroll and other expenses, cash and bank, share capital, investments, deposits, loans and advances, periodical and annual closing and preparation of financial statements together with formats of documents and reports.

64

reporting to the Board of MSPGCL. There is monthly monitoring of financial performance at the level of MD along with operational performance. The financial figures are approximations. HPGCL prepares half-yearly accounts (without schedules) which are placed before the Board. MSPGCL plans to switch to quarterly reporting to the Board effective 2009-10 and HPGCL would need to follow suit.

37. During the currency of the loan project, IUFRs in agreed format will be required giving details of project expenditure incurred till date, planned expenditure, and projected funds requirement in the next two quarters. The report would also provide contract wise details of the financial progress and the physical progress under the project. The IUFRs will be prepared from information generated by the financial systems of the entities and submitted to both project management and IBRD. The annual project financial statements, which would be similar to the format of the IUFR would be audited and submitted to the Bank. During project execution, periodic reports on physical and financial progress would be generated for monitoring project progress and initiating timely action to ward off future disputes. It is expected that project monitoring software (eg Prima Vera) would be used during project execution to facilitate physical and financial progress reporting. Also the entities recognize that there is scope for improving financial reporting to management32 in light of the organizations’ growing requirements and the need to formalize a reporting system covering their entire operations to provide information needed for effective monitoring and control.

Depreciation and Fixed Assets

38. WBPDCL, MSPGCL and HPGCL being power sector entities are required to follow the Electricity Act, 2003 which has an overriding effect in case of any inconsistency with the Companies Act, 1956. The companies have been providing depreciation in accordance with Electricity Act (2003)33 which provides for rates lower than the Companies Act. MSPGCL has now switched to Companies Act rates for provision of depreciation. The industry practice with regard to depreciation provision varies with some entities providing depreciation as per Companies Act and some as per Electricity Act (2003) rates.

39. The auditors of all three entities have pointed out deficiencies in fixed assets accounting, the maintenance of fixed assets registers and physical verification of assets. This is primarily because as State Electricity Boards (SEBs), these entities were not required to maintain and update the fixed assets registers and records, as are required for companies under the Companies Act. All three entities have outsourced the work of assets verification and preparation of fixed assets registers. In case of MSPGCL the opening balance sheet as on June 6, 2005 was approved by MSEB Holding Company Limited on September 26 2006 and incorporated in MSPGCL’s books in FY2005-06. However the figures are still provisional as the approved final transfer scheme is yet to be notified by GoM. This issue (approval of final transfer scheme) needs to be resolved immediately to allow MSPGCL to initiate the reconciliation activities.

Costing System

32Including for example quarterly financial statements, budget variance and analysis reports covering periodic operating results, treasury management, working capital management, project management, and cost analysis reports. 33 Depreciation is provided only on fixed assets in existence at the beginning of the year and no depreciation is provided on additions and for retirements during the year.

65

40. The generation companies are subject to cost audit as required under the Companies Act, 1956. Cost records are being maintained by the companies34. The cost audit report of MSPGCL has pointed out several areas for improvement and also suggests that a separate costing cell should be set up under CGM. The entities are considering formalizing the system through a costing manual and integrating cost accounting with financial accounting for better monitoring and control of costs.

Billing and Tariff

41. Power generated by the generating companies is sold to the distribution companies in the respective states. Energy tariff is regulated by the respective state ERCs. Billing is based on scheduled energy details received from State Load Dispatch Centers (SLDCs). In case of WBPDCL billing for FY 2007-08 is Rs.27 billion. Payments against bills are said to be regular and debtors represent roughly one months billing35. The entire power generated is not sold as a part of it is used for auxiliary consumption. According to MSPGCL’s sale of power during 2007-08 was Rs.80 billion and receivables as on March 31 2008 were Rs.17.7 billion. The same numbers for HPGCL – based on unaudited annual accounts shared with the team – are sale of power at Rs. 63 billion and receivables at Rs. 27 billion (receivables are equivalent to five months of sales).

Staffing – Finance Function

42. The project’s financial arrangements would be largely handled by finance staff at CO with assistance from the relevant units. The CO project finance teams will coordinate with the Bank in respect of the loan project and be responsible for meeting all information requirements and providing reports in the agreed formats to the Bank. In case of WBPDCL, the responsibility for project FM will rest with a GM supported by two Assistant Managers and a Junior Manager at CO and the unit team headed by Senior Manager.. MSPGCL’s project management team would be headed by the CGM (Finance) at CO and the Joint CAO at unit level with need-based support. The project management structure for HPGCL is yet to be formulated.

43. WBPDCL’s Finance Department is headed by Executive Director (Finance) who is assisted by a group of officers36. All finance executives are professionally qualified (CA/ ICWA/ MBA). WBPDCL is currently facing capacity constraints at executive levels due to attrition, remuneration structure which is much lower compared to industry37 and restrictions on direct recruitment at senior levels. Direct recruitments have been possible only at assistant manager level. Against an estimated requirement of 50 executives at CO and units, the current strength is 35. The proposed HRD committee and remuneration committee is expected to address the capacity issues and also develop HR policies and procedures that will suitably address

34 The cost audit report of WBPDCL has not yet been shared with the Bank. 35 The receivables position has improved after the set off of Rs.27.2 billion of past GoWB loans against receivables on account of sale of energy to GoWB owned WBSEB. 36 It includes a General Manager (GM), a Deputy General Manager, a Senior Manager three Assistant Managers and two Junior Managers. The unit finance function is headed by a Senior Manager assisted by Assistant Managers and Junior Managers with a team of assistants 37 A recently introduced performance based incentive scheme has been successful

66

WBPDCL’s staffing needs (both numbers and skills level), recruitment, capacity building, performance evaluation and remuneration38.

44. At MSPGCL, the Finance & Accounts department is headed by Director Finance and assisted by Chief General Manager (Finance)39. According to MSPGCL, around 50 accounts staff are professionally qualified. MSPGCL has in house training facilities. It is in the process of developing training policies and undertaking training needs assessment by external agency to build staff capacity.

45. In HPGCL, Director (Finance) position is vacant and there are several vacancies at officer levels (roughly 18). Finance and Accounts at HQ is headed by an FA and a CAO supported by SAOs and AOs. The units (Panipat, Yamunanagar and Hissar) are each headed by an FA. (Faridabad unit does not have an FA post). In view of the vacancies, work is carried out with the help of Section Officers (there are vacancies here as well), Accountants and Accounts Clerks40. SAOs and AOs hold 3-4 charges each. A Staff Restructuring Plan has been approved by GoH (HPGCL to share with the World Bank). Direct recruitment is carried out by the state staff selection commission for Accounts Clerk, Accountant and Accounts Officer41 posts. Recruitment lead time is roughly one year.

FM and Other Information Systems

46. WBPDCL is implementing on a pilot basis, accounting, stores and purchase modules of Oracle ERP at its Kolaghat unit. There are several issues with the package and with staff capacity to operate an ERP. Plans for rolling out the ERP are on hold while the future of ERP implementation in WBPDCL is reviewed. The existing off the shelf package has limited features necessitating manual intervention and preparation of reports manually. WBPDCL is considering capacity building in IT through recruitment and training as well as the option of outsourcing ERP operations and maintenance in the short term through AMC. For improving operational effectiveness and to achieve its growth plans, WBPDCL requires systems that integrate its operations with suitable reporting features to meet reporting requirements of the government, regulator, lenders, funding agencies and the management.

47. MSPGCL implemented financial accounting and budgetary control (FABC) system in 1993-94 at corporate office and 9 power stations. Other computerized systems include payroll (1998), power plant management system (PPMS) partially implemented in nine power stations and operational since 2004 and coal accounting system (2001-02). A generation control room system is planned for centralized viewing of generation data. MSPGCL appointed external consultants to prepare an IT implementation road map in March 2006. The report pointed out that though the systems implementation brought about IT awareness in the organization and built up infrastructure, there has been lack of integration, implementation delays, and management’s reporting requirements are not met. A need has been expressed to replace current systems with proven, industry standard, commercial off-the shelf (COTS) software. The suggestion has been 38 WBPDCL plans to recruit 500 staff at the level of assistant manager in July 2008 (after local bodies’ elections are held in the State) of which 15 would be for finance. It is expected that these staff would be in place by December 2008. Till date six AMs have been recruited at unit level. 39 According to the Circular dated November 2, 2007 the revised sanction strength for MSPGCL (up to September 30 2007) for accounts cadre was 503. In addition, the sanctioned strength for major stores accounts cadre was 69. However there is no separate cadre for internal audit staff. 40 These positions do no require professional qualification 41 Incumbents have to be professionals (CA/ ICWA/ MBA)

67

accepted by MSPGCL42. In this context request for proposals for implementing ERP package has already been issued by MSPGCL and implementation support consultants have been appointed.

48. HPGCL has subcontracted computerization of (i) operations & maintenance systems and (ii) accounting systems to NTPC. NTPC has appointed TCS for developing the computerized systems based on HPGCL’s requirements/ specifications. The two-year project is in progress in Panipat (of which 18 months are already spent) and there are some delays reported in the progress of work.

Internal Control and Corporate Governance

49. The delegation of powers establishes the internal control environment within the companies. This also aids in segregation of duties within the organizations. WBPDCL has been following the erstwhile WBSEB’s delegation of powers since its inception. Thus there is a need to update the delegation of powers (DOP) based on an assessment of the organization’s needs for decision making and flexibility of operations to establish a proper internal control framework. A revised delegation of powers was drawn up nearly two years ago and is yet to be approved by the Board. This may also be in need of updating.

50. At WBPDCL contracts are issued by the Project Contracts Cell located at the units. The units are headed by DGM. Copies of these contracts are available with Finance Department at CO. All bills are approved by the Executive Engineer for value of work done based on measurement books. Statutory and other contractual deductions are incorporated in the bills by unit finance and after due verification, the bills are approved by GM Accounts at CO for payment. For IBRD funded project there will be a Board Resolution specifying the powers for according technical and financial approval on the bills and an independent supervision consultant will certify completion of payment milestone before actual payment. All original bills and documents will be kept in safe custody of the finance department. The physical custody of the assets created by the working agencies will be under the custody and control of the concerned unit head. These and other relevant project-specific FM guidelines will be documented in the project implementation plan of WBPDCL.

51. MSPGCL updated its delegation of powers in June 2007. Accounting and internal audit manuals are under preparation by consultants. The project-specific systems documented in the project implementation plan will ensure proper contracting and payments procedures including approval and authorization of bills prior to payment, adequate and credible documentary evidence of work done and payment, complete audit trail, and defined responsibilities for assets and documents custody etc.

52. HPGCL has updated its delegation of powers in 2006. Assessment of internal controls and procedures for project activities is yet to be completed.

53. The internal control framework of the entities will need to be in line with its size and scale of operations and documented in manuals – operations43 and finance. Although some

42 MSPGCL’s senior management team visited Tata Power’s Trombay Power Plant to review the implementation of SAP and was satisfied with the feedback. 43 For internal control to be effective across the organization it should cover all transactions from its origin/ inception to closure (and in case of assets, span its lifetime). Standard guidelines, policies and procedures should be laid down and its compliance monitored. These standards embodied in ‘operations manuals’ will bring about uniformity in controls and practices across the organization and form the basis for audits and improvements. FM manuals are considered as a part of an organization’s

68

processes to improve corporate governance and financial accountability have been initiated in WBPDCL and MSPGCL, further actions are underway (as detailed in the CGFA action plan in Table 6).

Corporate Governance

54. The department of public enterprises (DPE), Government of India has issued a code of corporate governance for Central Public Sector Undertakings irrespective of whether or not they are listed in the stock exchange44. There are no guidelines for corporate governance for the state run PSUs in West Bengal, Maharashtra and Haryana. However, both WBPDCL and MSPGCL are committed to follow proper corporate governance norms and practices. In the following table, the key components of a model code of corporate governance (applicable to CPSUs) and the present status in WBPDCL and MSPGCL is presented. HPGCL’s corporate governance arrangements are yet to be assessed.

Table-7.3: Status of Model Code on Corporate Governance

Draft model code Present status

WBPDCL: Current Board composition: Chairman; three government nominee directors; MD and three full-time functional directors; four independent directors recently appointed.

MSPGCL: Current Board composition: Chairman; one government nominee director; one independent director recently appointed; MD and three full-time functional directors46.

Board of directors shall have an optimum combination of functional, nominee and independent directors. The number of functional directors (including CMD/MD) should not exceed 50% of the actual strength of the board. The number of nominee directors shall be restricted to a maximum of two. In case of CPSEs listed in stock exchanges, the number of independent directors shall be at least 50% of board members. In case of CPSEs not listed in the stock exchanges at least one third of the board members shall be independent directors45.

HSPGCL: Current Board composition: Chairman; three part-time directors; two independent directors; MD and two functional directors

Qualified and independent audit committee shall be set up giving the terms of reference with minimum three directors as members; two thirds of the members shall be independent directors; the chairman

WBPDCL: There is no independent audit committee at present. It is proposed to be set up with independent directors recently appointed.

operations manual and cater to purely financial transactions leaving out of its ambit large chunks of activities that are performed outside the finance department. Procurement (specially of coal, contract execution and management, inventory control and fixed assets and project/ works management are some other areas of operations where standards and guidelines would enhance the overall internal control environment for the loan project. The implementing entities need to focus on the aspect of developing appropriate operations manuals as well. 44 The aim is to institutionalize good corporate governance practices that are broadly in conformity with SEBI guidelines (clause 49 of the Listing Agreement), in CPSUs as ultimately, these CPSUs would approach the financial markets for its requirements. 45 Nominee directors appointed by an institution which has invested in or lent to the company shall be deemed to be independent directors 46 MSPGCL plans to source funds from the financial markets in the near future which will automatically subject it to corporate governance requirements as set out under clause 49 of SEBI which mandates, among others, appointment of independent directors 47 Other prescribed norms for audit committee: All members of audit committee shall have knowledge of financial matters of company and at least one member shall have good knowledge of accounting and related financial management expertise. Audit

69

MSPGCL: There is no independent audit committee at present. It is proposee to be set up with the independent director as the chairman.

of the audit committee shall be an independent director47.

HPGCL: There is an audit committee WBPDCL: The restructuring plan lays down a framework for risk management. It lists certain risks and mitigation measures which can be further developed by WBPDCL and implemented. The annual report of WBPDCL incorporates risks and concerns relating to quality of coal supplies.

Risk management strategies and their oversight shall be one of the main responsibilities of the board and management48.

MSPGCL & HPGCL: There is no formal risk management system in place.

The guidelines provide a list of minimum information that is required to be placed before the Board49.

Half-yearly reporting to the Board by HPGCL & WBPDCL; no formal reporting to the Board by MSPGCL. The frequency may be increased to quarterly reporting to the Board by all the three entities.

55. Actions initiated for improving corporate governance: WBPDCL is a registered Public Limited Company with an amended Articles of Association since June 2008. Four independent directors have been appointed to its Board in December 2008. An independent audit committee is planned to be set up by June 2009 with full scope as required under the Companies Act which includes fixing the remuneration of the statutory auditors, coordinating their work and providing management responses to the audit observations, overseeing the internal audit framework and work plan, discussing and making recommendations on any matter relating to financial management.

56. MSPGCL is proposing to convert into a Public Limited Company and bring in greater transparency and accountability and also plans to set up an audit committee. Recently an independent director has been inducted in the Board and it is suggested that the independent director should be appointed as the chairman of the audit committee to ensure presence in some degree of external and impartial viewpoint. MSPGCL may consider appointing eminent person/s in the audit/ other organizational committees to inject an element of independence in the decision making.

57. Assessment of corporate governance arrangements and proposed action plan is yet to be completed for HPGCL.

58. In the area of risk management, the corporate governance framework requires entities to develop suitable strategies for risk identification, assessment and mitigation. Risk factors that

committees shall meet at least four times in a year and not more than four months shall elapse between two meetings. Detailed and elaborate role has been prescribed for audit committees. 48 Regarding risk management norms, the board shall ensure the integration and alignment of the risk management system with the corporate and operational objectives and also that risk management is undertaken as a part of normal business practice and not as a separate task at set times. The company shall lay down procedures to inform board members about the risk assessment and minimization procedures and periodically review them. Disclosure on risks and concerns shall from part of Director’s report. 49 The list includes quarterly results for the company and its operating divisions or business segments. The guidelines also provide a list of items to be included in the report on corporate governance in the annual report of companies and obtain a certificate from either the auditors or practicing company secretary regarding compliance of conditions of corporate governance as stipulated in the guidelines.

70

could have adverse bearing on the entities’ operations, performance and reputation should be identified and managed. Neither WBPDCL nor MSPGCL has a corporate plan formally laying down vision, mission, operational goals and strategies, business plans and risks and mitigation measures. Thus enterprise risks50 and suitable mitigation measures need to be developed, monitored and reported.

Internal Audit (IA)

59. WBPDCL does not have a separate internal audit department. Internal audit is carried out by external CA firms based on scope of work issued by WBPDCL. Internal audit is quarterly and separate internal audit reports for each unit and CO are submitted to Director (Finance). There in no formal system of tracking and closure of audit observations and no audit committee review. MSPGCL has a separate internal audit department headed by General Manager level officer reporting to Chief General Manager F&A. There are inspection teams based in the units. The inspection team comprises accounts officers, divisional accountants and UDCs. Internal audit reports are issued to management for comments and action. A track is kept of unsettled paras. In this case too there is no audit committee review.

60. The scope of internal audit of WBPDCL covers financial accounts, salaries & wages, fuel, physical verification of stores and inventories, purchase, services and works, sale of scrap, sale of energy etc. The focus of internal audit is primarily transactional and not systemic issues which need to be remedied. There is no internal audit manual and objectives and strategies of internal audit function have not been laid down. The statutory auditors of both the entities have observed that the internal audit system needs to be strengthened with regard to staffing, coverage and intensity, timely submission of audit reports etc to be commensurate with the size of the companies and nature of their businesses. WBPDCL has agreed to amend the scope of work of internal auditors for FY 2009-10 to focus on systems improvement and formalize follow up on audit observations.

61. MSPGCL has decided to completely overhaul the internal audit system and has issued scope of work to consultants for revamping the function. The scope of work covers detailed diagnostic of the function, identifying areas for improvement, developing a detailed internal audit manual and carrying out internal audit for FY 2007-08 for corporate office and three units and to submit unit-wise reports.

62. In HPGCL although there is an SAO in charge of internal audit, there is no support staff. Internal audit is not being carried out by HPGCL and this has been observed by the statutory auditors51. HPGCL has outsourced internal audit to a CA firm in August 2008 which has submitted a report to the audit committee. Internal audit would need to be significantly strengthened in HPGCL in line with organization’s needs and best practices. Action plan for strengthening internal audit of HPGCL is pending completion of the corporate governance and financial accountability assessment.

50 A major risk for MSPGCL is its inability to attain MERC parameters which has adverse impact on financial performance; for both WBPDCL and MSPGCL, there are project implementation risks in terms of time and cost over-runs; from commercial view point there is risk of reduced collection efficiency/ tariff may not fully cover costs; there are operational risks associated with quality and supply of coal; in the area of governance, inadequate financial and functional autonomy may be considered a risk. 51 The company has no internal audit system as no internal audit was done at units and Head Office (statutory auditors’ comments in reports for FY 2006-07, 2005-06, 2004-05)

71

63. Actions proposed for strengthening IA: WBPDCL and MSPGCL will set up audit committees and strengthen the IA function in tune with organizational requirements. They propose to lay down standard operating guidelines, improve reporting and follow-up and create an independent audit environment. The internal audit would be organization wide and oriented towards mitigating risks and improving/ strengthening relevant systems and controls for improved organizational performance. A robust mechanism for follow up of audit observations and resolution is required in which the audit committee will play an important role. Independence of the function needs to be assured. WBPDCL proposes to set up an internal audit cell. The internal audit cell/ department in all the implementing entities should report to the MD in view of their organization wide coverage and since they need to be independent of the departments they audit. An assessment of the required staff strength and training will be needed. An internal audit manual would be prepared to set out the objectives, scope and coverage of audit, the detailed methodology of review, audit questionnaires, and the required reporting and follow up.

64. The IBRD financed project will be subject to internal audit (under agreed terms of reference) and its reports will be available to the IBRD, on request

External Audit

65. Under Section 619(2) of the Companies Act, 1956, the Comptroller & Auditor General (CAG) recommends appointment of statutory auditors of Government owned companies. The auditor is usually selected for a period of four years. CAG also conducts a supplementary/ test audit under section 619(3)(b) of the Companies Act 1956. In addition CAG carries out proprietary audit of the entities and the reports are laid before the state legislature which then automatically stands referred to the Committee on Public Undertakings (COPU) for review and resolution of the audit observations. There are pending COPU paras in case of all the three entities.

66. In case of WBPDCL there were several statutory audit observations in the audit report of FY 2006-07 which were repeated from earlier years.52 WBPDCL have taken steps to address these observations and resolve them so that they are not repeated in subsequent audit reports53.

67. The statutory audit report of MSPGCL for FY 2006-07 contains several observations concerning deviations from the requirements of Accounting Standards prescribed under the Companies Act arising from MSPGCL’s adherence to ESAAR requirements over that of Companies Act requirements.54. In response to audit observations MSPGCL decided to comply 52 Like non confirmation of creditors/ deposit/ advance balances; deviations from accounting standards 2 (valuation of inventories), 15 (accounting for retirement benefits) and 22 (deferred tax liability/ asset); accounting treatment for freight not uniform; no reconciliation between general ledger and priced stores ledger etc. While the effect of some of the observations could not be quantified by the auditors, the impact from the quantifiable observations is a reduction in profit of around Rs.1 billion. 53 2007-08 audit report of WBPDCL has very few repeat observations. 54 Other comments include: non confirmation/ reconciliation of balances of sundry debtors, sundry creditors, loans and advances, other receivables and other debit/ credit balances including that of holding company and other subsidiary companies of holding company; cost of land not bifurcated into freehold and leasehold and amortization of leasehold land if any not done; CWIP and current liabilities are understated as central purchases are booked on payment basis at project divisions; value of scrap not included in inventories/ no provision made for slow moving, non-moving, obsolete, damaged stocks/ stocks of machine spares, lubricants and consumables not valued in most hydro power stations/ stock of steel and cement at project site not physically verified or reconciled with book stock; non maintenance of proper fixed assets records and fixed assets not physically verified; MVAT claims not set-off against capital assets/ inventories/ expenses and treated as miscellaneous income in contravention of ICAI guidance note; weaknesses in internal controls in compiling and maintaining party wise and age wise details of various liabilities and assets

72

with Companies Act requirements in accounts maintenance with effect from 2007-08. The statutory audit report for FY 2007-08 has fewer observations and these would need to be resolved. Regarding fixed assets record maintenance and physical verification all three entities have sought help of external consultants however the observations have not been fully taken care of.

68. In case of HPGCL there have been inordinate delays is completing statutory audits and adoption of annual accounts55. According to senior management, HPGCL expects to complete its audit back-log by September 2009 and be in compliance with Companies Act requirement of adoption of audited accounts within six months form the end of the financial year (September 30). There are large numbers of significant audit qualifications/ observations in the statutory auditors’ reports regarding fixed assets records maintenance and physical verification, reconciliation of general ledger balances with sub-ledgers, reconciliation of inter-unit accounts, non-compliance with accounting standards (AS-2 valuation of inventories, AS-6 depreciation accounting), debit and credit balances netting, accounting for scrap, non availability of some inventory and stores details, non provision of certain liabilities etc (to name a few). HPGCL’s response to the audit observations has not been shared with the Bank. HPGCL has completed the records and verification of fixed assets up to FY 2003-04 through outsourcing. It proposes to outsource the work again for the remaining period (2005-06 to 2007-08). HPGCL also proposes to outsource the work of reconciliation of balances in the current assets and current liabilities accounts including inter-unit accounts. In addition there are several COPU paras pending (to be shared with the Bank)

69. The implementing entities will submit (i) audited entity accounts and audit reports and (ii) audited project financial statements and audit report to the Bank. It is proposed that the project would be audited by an independent firm of chartered accountants, acceptable to the Bank, under agreed terms of reference. The audited project financial statements would separately identify each component under the project, its progress and the funding sources for each of the contracts. Thus the following audit reports will be monitored in the Bank’s Audit Reports Compliance System (ARCS):

Table 7.4: Audit Reports Monitoring

Agency Audit Report Audited by Due Date (for each year)

WBPDCL, MSPGCL and HPGCL

Annual entity audit reports and accounts as required under the Companies Act

Statutory Auditors appointed by CAG

30th September

55 Audit report of FY2004-05 is dated February 9 2007; FY2005-06 is dated December 24 2007; FY2006-07 is dated July 10 2008 but is yet to be adopted by the company. Audit of FY2007-08 is in progress.

73

WBPDCL, MSPGCL, HPGCL and Central Electricity Authority

Project audit report and accounts;

An independent firm of Chartered Accountants acceptable to the Bank in respect of WBPDCL, MSPGCL, HPGCL and CAG in respect of Central Electricity Authority

30th September

GOI Special account audit reports for IBRD and GEF funds

CAG 30th September

Right to Information, Transparency and Disclosure 70. Under Right to Information (RTI) Act, 2005 a public authority is required to maintain and make available detailed records to facilitate right to information. It envisages computerization of records and accessibility through network. The Act also requires every public authority to, designate required number of Public Information Officers, in all administrative units or offices under it and publish particulars of such officers to provide information to persons requesting for it under the Act.

71. MSPGCL has developed a separate RTI website. Information relating to the company, powers/ duties, rules and regulations etc has been posted on the website including names and contact information of public information officers/ appellate officer. According to the company, periodic returns are being submitted and officers are sensitized to the RTI requirements through training. During the period April – October 2008, information was provided against 55 applications and there were 40 pending applications. MSPGCL discloses the complete annual audited statement of accounts in the website. WBPDCL has a corporate website but no separate RTI website. Public Information Officer and Assistant PIOs have been identified as per requirement but not posted on the website. It has plans to post important documents/ circulars relating to recruitment, training, service regulations etc on the website. A new IT department is being set up and the MIS cell will be in charge of the web-site. Only the annual reports of the company are posted on the website (excluding audited accounts and auditors’ report). HPGCL has a corporate website and further details have been requested..

72. During project implementation the audited project financial statements and other pertinent project-related details would be disclosed in the website in a suitable manner.

Action Plans 73. Following are proposed action plans for (i) ensuring adequate FM arrangements for the project and (ii) improvements in corporate governance and financial accountability of the entity during the implementation of the project:

74

Table 7.5: Action Plan for adequate FM arrangements for the project

Sl No Area of Action Timeframe 1 Assess and fill vacancies in project FM at CO

and Units WBPDCL and MSPGCL have

identified appropriate staff, to be inducted/ assigned by

negotiation. HPGCL will do it after completion of FM

assessment 2 Appoint independent third party quality

assurance consultant with Bank approved TOR to check and authorize project expenditures, ensure proper procedures and monitor milestone achievements in terms of the project requirements

TOR for WBPDCL and MSPGCL finalized;

TOR to be included in the PIP which is a eligibility condition

for HPGCL

3 Project internal audit to be carried out by qualified auditors under Bank approved TOR and submit internal audit report to the Bank on quarterly basis Strengthen internal audit with proper manuals

TOR for WBPDCL and MSPGCL finalized;

TOR to be included in the PIP which is a eligibility criteria for

HPGCL As per CGFA action plan

4 Prepare detailed project implementation plan PIP for WBPDCL and MSPGCL

finalized; Eligibility condition (HPGCL)

Table 7.6: Action Plan for Improvements in Corporate Governance and Financial Accountability

Actions required for implementation with timeframe Area of Action

WBPDCL MSPGCL HPGCL Conversion into public limited company Complete registration formalities with ROC

Completed in June 2008

Currently being discussed in conjunction with plans for raising further equity

Internal audit Strengthen internal audit arrangements in line with own requirements and good industry practices and statutory auditors’ comments Set up internal audit department reporting to MD Develop internal audit manual

Issue revised TOR for internal audit for 2009-10 Set up IA department reporting to MD by September 2009 Finalize TOR for internal audit manual in consultation with audit committee by September 2009

Scope of work to strengthen IA issued. Implement recommendations during 2008-09 IA department being restructured Draft IA manual has been prepared ; To be finalized by June 2009

Actions required for implementation

75

Audit Committee Set up audit committee with independent directors and develop scope and coverage in line with Companies Act/ corporate governance requirements

Set up audit committee by June 2009 Finalize scope and coverage of audit committee by September 2009

Set up audit committee by March 2009 with independent director as Chairman and finalize scope and coverage of audit committee

Capacity building Strengthen HRD and recruit finance/ IT/ IA staff as per defined plan

Set up HRD and recruitment committees as decided in the EGM of April 17 2008 and commence filling of vacancies (recruitment commenced)

No immediate issues

Address repeat queries of statutory auditors Discuss observations of statutory auditors and clarify/ resolve objections

Resolve repeat audit objections during FY 2008-09 audit

Audit queries pertaining to non compliance with Companies Act provisions resolved in 2007-08. Remaining audit queries to be resolved in 2008-09

In-year reporting to management Introduce quarterly reporting of operating results to Board as per corporate governance requirements compared with budget and variance analysis

Half yearly results from 2009-10, Quarterly results from 2010-11

Half yearly results during 2008-09; Quarterly results during 2009-10

to be decided on completion of CGFA assessment

Cash forecasting Extend monthly cash forecasting to rolling cash forecasts on quarterly basis; link to budget and compare with actual cash flow

Monthly forecast exists; strengthen and Introduce quarterly rolling cash forecasts from April 2009

Commence in 2009-10

Enterprise Resource Planning package implementation Resolve ERP implementation issue and decide on an action plan for implementation

Decision on way forward for upgraded financial accounting system by March 2009

IT road map ready; Bids for SAP implementation received; Consultant for implementation support appointed. Commence implementation by March 2009

DOP and financial management manuals Update delegation of powers and develop manuals for a more formalized and systems oriented financial accountability and corporate governance environment covering (a) budgeting, (b) internal controls (c) accounting, (d) costing and (e) financial reporting

Issue TOR for updating DoP and preparing manuals by March 2009 DoP ready by June 2009 Commence work on the finance manuals by March 2009 and complete by September 2009

Revised DOP already in place Work on accounting and internal audit manual already started; Scope of work for remaining manuals prepared; Draft manuals by 2009-10

Actions required for implementation to be decided on completion of CGFA assessment

76

Develop Corporate Plan Develop Corporate Plan with organization’s vision, mission, long term objectives and strategies; corporate governance and risk management

Commence work by March 2009 (with external assistance if necessary)

Commence work by in FY 2009-10 (with external assistance if necessary)

Other reporting for MIS Review organization wide reporting requirements and develop suitable forms and instructions for their preparation and distribution.

Commence work by March 2009 (with external assistance if necessary)

Work combined with ERP implementation

Operations manuals Develop suitable guidelines for contract execution and management, fixed assets and inventories management to ensure smooth and uniform processes with adequate checks and controls

Take action in 2009-10 (with external assistance if necessary)

Scope of work for inventory management and procurement management prepared; Draft manuals by 2009-10

77

Annex 8: Procurement Arrangements

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

A. General

1. The Project will support energy efficient rehabilitation and modernization (EE R&M) of selected coal fired power generating stations in the States of West Bengal, Maharashtra and Haryana, consultancy support for strengthening operations and maintenance practices in these three stations, and technical assistance to Central Electricity Authority (CEA) for reduction of barriers to R&M in India. The procurement accordingly will be for goods, equipment and services related to the R&M of the power stations, consultancy for strengthening O&M practices, and consultancy towards barrier reduction. Procurement for the proposed project would be carried out in accordance with the World Bank’s “Guidelines: Procurement under IBRD Loans and IDA Credits” dated May 2004 and revised October 2006; and “Guidelines: Selection and Employment of Consultants by World Bank Borrowers” dated May 2004 and revised October 2006, and the provisions stipulated in the Legal Agreement. The general description of various items under different expenditure categories is described below. For each contract to be financed by the Loan, the different procurement methods or consultant selection methods, the need for prequalification, estimated costs, prior review requirements, and time frame are agreed between the Borrower and the Bank project team and indicated in the Procurement Plan. The Procurement Plan will be updated at least annually or as required to reflect the actual project implementation needs and improvements in institutional capacity.

Procurement of Works

2. There are no separate civil works envisaged to be procured under the project. The relevant civil works are included in the scope of the respective equipment are minor in nature such as grouting, modification of existing foundations, chipping, etc..

Procurement of Goods

3. The procurement goods and equipment for the selected power stations in West Bengal (Unit-5 Bandel) and Maharashtra (Unit-6 Koradi) is envisaged to be covered in four separate contracts covering the entire power station, i.e. one contract for Main Plant area (Boiler, Turbine and Generator, including Auxiliaries) and one contract each for coal handling area, ash handling area and electrical system. The contracts will be under "Supply and Install" basis. For R&M of selected power generation units in Haryana (Units-3&4 Panipat), the utility has expressed preference for a single contract. The utility feels that coordination and interfacing of four separate contracts may be difficult to manage, especially across two generation units in the same compound. The utility has successfully applied single contract approach to similar projects in the past56. The final decision on contract packaging in this case would be taken after the Detailed Project Report (DPR) has been finalized.

4. Based on estimated prepared by WBPDCL for Bandel Unit-5, which would be taken up first for EE R&M under the project, the largest contract for main plant is estimated to be Rs. 3600 million. The estimates for coal handling package, ash handling package, and electrical system package would be Rs.450 million, Rs.225 million and Rs.450 million, respectively. Individual estimates are yet to

56 HPGCL has undertaken the rehabilitation of Units 1 & 2 in the recent past under single package arrangements. These units are similar to Units 3 & 4 covered under the bank project.

78

be worked out by MSPGCL for its Koradi Unit-6 and HPGCL for its Panipat Units 3 & 4, as the R&M design studies are yet to be completed.

5. Procurement will be done following International Competitive Bidding (ICB) procedures of the Bank and using the Bank’s Standard Bidding Documents (SBD) of Procurement of Plant Design, Supply & Installation (April 2008 and as agreed with the Bank). The contract involving main plant area (Boiler-Turbine-Generator) will follow two-stage bidding while the other three contracts will follow single stage bidding.

Other Procurement Procedures

6. The project does not envisage any other procurement of goods except as stated above. However, considering the nature of the R&M projects and the possibility of additional items which could not be precisely identified through RLA studies, provision of procurement using national competitive bidding and direct contracting (for proprietary items) is included in the procurement arrangements.

7. National Competitive Bidding: Goods estimated to cost less than $500,000 equivalent per contract may be procured under contracts awarded on the basis of National Competitive Bidding procedures as per paragraph 3.3 and 3.4 of the Procurement Guidelines and the additional conditions as below:

• Only the model bidding documents for NCB agreed with the Government of India Task Force (and as amended from time to time) shall be used for bidding.

• Invitations to bid shall be advertised in at least one widely circulated national daily newspaper, at least 30 days prior to the deadline for the submission of bids;

• No special preference will be accorded to any bidder either for price or for other terms and conditions when competing with foreign bidders, state-owned enterprises, small-scale enterprises or enterprises from any given State;

• Except in exceptional circumstances, there will be no negotiations of price with bidders, even with the lowest evaluated bidder.

• Extension of bid validity: (a) for the first request for extension if it is longer than four weeks; and (b) for all subsequent requests for extension irrespective of the period (such concurrence will be considered only in cases of Force Majeure and circumstances beyond the control of the purchaser or employer).

• Re-bidding: the system of rejecting bids outside a pre-determined margin or ‘bracket ‘of prices shall not be used.

• The two-or-three envelope system will not be used.

• Rate contracts entered into with the Director General of Supplies and Disposals (DGS&D) are not acceptable as substitute for NCB procedures.

8. Direct Contracting: Goods which meet the requirements set forth in paragraph 3.6 of the Procurement Guidelines may be procured on the basis of Direct Contracting in accordance with provisions of paragraph 3.6 and 3.7 of the Procurement Guidelines.

Selection of Consultants

9. The states of West Bengal and Maharashtra have completed the procurement of consultants for R&M design, EADD and RSA studies for Bandel and Koradi stations using PHRD funding. Maharashtra is in the process of selection of design consultants and safeguard consultants for

79

Chandrapur, Bhusawal and Parli stations, while Haryana is procuring the same for Panipat station. All of these would be funded under the technical assistance component of the project. Each of the three participating states will also need to procure Implementation Support consultants and Quality Assurance consultants, estimated to cost about US$500,000 for each state. Further, consultant(s) will be procured for institutional strengthening on O&M. The technical assistance component for CEA envisages selection of consultants for reduction of barriers to R&M interventions in India and for strengthening institutional capacities at CEA, estimated to cost USD 1.1 million in all.

10. Short lists of consultants for services estimated to cost less than $500,000 equivalent per contract may be composed entirely of national consultants in accordance with the provisions of paragraph 2.7 of the Consultant Guidelines57. The Bank's Standard Request for Proposal (RfP) document (December 2008 and as agreed with the Bank) will be used as a base for all procurement of Consultancy services to be procured under the project.

Particular Methods of Procurement of Consultant Services

11. Quality and Cost Based Selection: Consultant Services may be procured under contracts awarded on the basis of Quality- and Cost-based Selection in accordance with the provisions of Section II of the Consultant Guidelines.

Other Procedures

12. Quality-Based Selection: Services under the Project which meet the requirements set forth in paragraph 3.2 of the Consultant Guidelines shall be procured under contracts awarded on the basis of Quality-based Selection in accordance with the provisions of paragraphs 3.1 through 3.4 of the Consultant Guidelines.

13. Selection Based on Consultants’ Qualifications: Services under the Project estimated to cost less than $100,000 equivalent per contract may be procured under contracts awarded in accordance with the provisions of paragraphs 3.1, 3.7 and 3.8 of the Consultant Guidelines.

14. Selection under Fixed Budget: Services under the Project estimated to cost less than $200,000 equivalent per contract may be procured under contracts awarded in accordance with the provisions of paragraphs 3.1, 3.5 of the Consultant Guidelines.

15. Single Source Selection: Services for tasks in circumstances which meet the requirements of paragraph 3.9 and 3.10 of the Consultant Guidelines for Single Source Selection, may, with the Bank’s prior agreement, be procured in accordance with the provisions of paragraphs 3.9 through 3.13 of the Consultant Guidelines.

16. Individual Consultants: Services for assignments that meet the requirements set forth in paragraph 5.1 of the Consultant Guidelines may be procured under contracts awarded to individual consultants in accordance with the provisions of paragraphs 5.2 and 5.3 of the Consultant Guidelines. Under the circumstances described in paragraph 5.4 of the Consultant Guidelines, such contracts may be awarded to individual consultants on a sole source basis.

B. Assessment of the agency’s capacity to implement procurement

17. Procurement activities will be carried out by generation utilities in each of the three states. An assessment of the capacity of the Implementing Agencies (MSPGCL and WBPDCL) to implement procurement actions for the project has been carried out by the procurement specialist of

57 Guidelines for Selection and Employment of Consultants by World bank Borrowers.

80

the Bank during preparation of the project. HPGCL’s response to questionnaire for assessment of procurement capacity has been received during appraisal.. Involvement of CEA had emerged recently and its procurement will be limited to a few consultancies. A satisfactory arrangement for procurement is under discussion.

Assessment of Procurement Capacity of MSPGCL

18. MSPGCL is registered under the Companies Act of India and is legally and financially autonomous with full power vested in the Board of Directors. It is already procuring plants, goods and equipments for its own use through a dedicated procurement unit in accordance with their respective procurement policy and Delegation of Powers. It prepares Bidding documents in accordance with its own procurement procedure for inviting tenders on open tender basis, following two envelop system. The concept of post qualification exists in the bidding process. Technical specifications are generally prepared in-house except in special cases where technical know-how is not readily available, in which case, it is done through consultants. It has well laid out pre-qualification conditions. The bid invitation time for open/advertised tenders is minimum three weeks and bid documents are issued without any filtration.

19. Bid opening committee opens the bids in presence of bidder’s representatives. Bids are evaluated internally by a multidisciplinary committee using services of consultants for new projects involving large investments.

20. Price negotiations for goods, works and consultancy are held as per the Delegation of Power with L-1 bidder. Counter-offer system is not used.

Assessment of Procurement Capacity of WBPDCL

21. WBPDCL is registered under the Companies Act and is legally and financially autonomous with full power vested in the Board of Directors. It is already procuring plants, goods and equipments for its own use through a dedicated procurement unit in accordance with their respective procurement policy and Delegation of Powers.

22. WBPDCL prepares bidding documents in accordance with its own procurement procedure for inviting tenders on open tender basis, following four envelope system (Part-I: EMD, Part-II: Pre-qualification criteria, Part-III: Techno-commercial, Part-IV: Price). In case of limited tendering, two envelop system is followed (Part-I: Techno-Commercial, Part-II: Price). The concept of post qualification exists in the bidding process. Technical Specifications are generally prepared in-house except in special cases where technical know-how is not readily available; in which case, it is done through consultants. It has well laid out pre-qualification conditions.

23. The bid invitation time for open/advertised tenders is around one month. For advertised tenders, bid documents are issued without any filtration. Bid documents are available for sale as advertised and sale remains open for a definite number of days. Assessment also found that bids are invited from pre-qualified bidders.

24. Price negotiations for goods, works and consultancy are held as per the Delegation of Power with L-1 bidder. Counter-offer system is not used.

Assessment of Procurement Capacity of HPGCL

25. HPGCL is registered under the Companies Act and is legally and financially autonomous with full power vested in the Board of Directors. HPGCL has the Materials Management Department for procurement of equipment and materials for the operation and maintenance of its existing power stations. HPGCL has also awarded the contacts for their Hissar and Yamunanager Power Projects

81

through the consultants appointed by them. The bidding documents for these projects and compete evaluation and award process was carried out by the consultants. .

26. Technical know-how is not readily available with HPGCL and Technical Specifications are generally prepared by the consultants. HPGCL, for their routine procurement follows two/three envelope system. Price negotiations are carried out with first three lowest evaluated bidders and counter offer system is followed.

27. Assessment establishes that for all the entities, the procurement staff are not fully familiar with Bank procedures, guidelines and SBDs for Bank-financed projects. MSPGCL had already sent two of its staff for training at ASCI on Bank funded procurement. HPGCL has deputed three officers to NIFM for procurement training. One day procurement training workshop was conducted by the Bank Staff in end Jan 2009 which was attended by several HPGCL staff. Similar training will be taken up for other participating utilities as well. WBPDCL is also planning to send two staff to undergo training at ASCI/ NIFM by April’ 2009. Further, the existing procurement system needs various re-alignment/changes to meet Bank’s requirement on complaint handling, disclosures and grievance handling.

28. The issue/risk concerning the procurement component for implementation of the project has been identified and listed below including the corrective measures which have been agreed.

Risks Rating Mitigation Measures Non familiarization of utility staff in Bank funded procurement, particularly single envelope bidding and policy of no negotiation.

Moderate Procurement Training has to be imparted by the Bank for each of the State utilities and refresher training will be arranged based on assessment done at the appraisal and further based on assessment at the end of each mission.

29. The overall project risk for procurement is Substantial.

C. Procurement Plan

30. All the three participating state utilities, as well as CEA have developed detailed Procurement Plans for procurement for the complete project giving estimated value, method of procurement and the year of procurement, which provides the basis for the procurement methods. These plans are under review. The plan agreed between the Borrower and the Project Team will be in IRIS and will also be available in the Project’s database and in the Bank’s external website. The Procurement Plan will be updated in agreement with the Project Team annually or as required to reflect the actual project implementation needs and improvements in institutional capacity.

D. Advance Procurement

31. Retroactive financing up to an aggregate amount not to exceed US$ 18 million equivalent (under loan) and up to an aggregate amount not to exceed US$ 4,540,000 equivalent (under grant) will be available under the project, for financing expenditures incurred after Feb 01, 2009 and before the Loan signing to procure eligible activities procured under agreed guidelines.

82

E. Frequency of Procurement Review Missions

32. Based on estimates of the contracts, all the contracts will be subject to prior review by the Bank. However, field visits to carry out post review of procurement actions will be taken up, if required.

83

D

etai

ls o

f th

e P

rocu

rem

ent A

rran

gem

ent i

nvol

ving

Int

erna

tion

al C

ompe

titi

on.

1.

Goo

ds a

nd "

Supp

ly a

nd I

nsta

ll" c

ontr

acts

.

(a)

Lis

t of

cont

ract

pac

kage

s w

hich

will

be

proc

ured

fol

low

ing

ICB

D

ET

AIL

S O

F T

HE

PR

OC

UR

EM

EN

T A

RR

AN

GE

ME

NT

FO

R W

OR

KS/

GO

OD

S

Sl.

No.

C

ontr

act D

escr

ipti

on o

f W

orks

/Goo

ds

Est

imat

ed

Cos

t (R

s. in

M

illio

n)

Est

imat

ed

Cos

t in

equi

v.

US$

Mill

ion

Met

hod

of

proc

urem

ent

ICB

/NC

B

P-Q

D

omes

tic

Pre

fere

nce

(Yes

/No)

Rev

iew

by

Ban

k (P

rior

/ P

ost)

Exp

ecte

d B

id

Ope

ning

dat

e C

omm

ents

1U

S$=R

s.44

1 W

est B

enga

l

1.1

Mai

n pl

ant

3600

81

.8

ICB

(S

+I)

No

Yes

Pr

ior

Apr

il, 2

009^

T

wo

Stag

e

1.2

Coa

l han

dlin

g

450

10.2

IC

B

(S+I

) N

o Y

es

Prio

r Se

ptem

ber,

200

9

1.3

Ash

han

dlin

g

225

5.1

ICB

(S

+I)

No

Yes

Pr

ior

Sept

embe

r, 2

009

1.4

Ele

ctri

cal

450

10.2

IC

B

(S+I

) N

o Y

es

Prio

r Se

ptem

ber,

200

9

2 M

ahar

astr

a

2.1

Mai

n Pl

ant

2500

* 56

.8

ICB

(S

+I)

No

Yes

Pr

ior

Aug

ust,

2009

^ T

wo

Stag

e

2.2

Coa

l Han

dlin

g

800*

18

.2

ICB

(S

+I)

No

Yes

Pr

ior

Dec

embe

r, 2

009

2.3

Ash

han

dlin

g a

nd

Bal

ance

of

Plan

t 70

0*

15.9

IC

B

(S+I

) N

o Y

es

Prio

r D

ecem

ber,

200

9

2.4

Ele

ctri

cal

300*

6.

8 IC

B

(S+I

) N

o Y

es

Prio

r D

ecem

ber,

200

9

3 H

arya

na

3.1

EE

R&

M

4484

101.

9 IC

B

(S+I

) N

o Y

es

Prio

r Se

ptem

ber,

2010

^T

wo

Stag

e

*: P

relim

inar

y E

stim

ates

^-

Dat

e of

Fir

st s

tage

Bid

Ope

ning

84

2.

C

onsu

ltin

g Se

rvic

es.

(a

) C

onsu

ltanc

y se

rvic

es e

stim

ated

to c

ost U

S$20

0,00

0 an

d ab

ove

per

cont

ract

and

Sin

gle

Sour

ce s

elec

tion

of c

onsu

ltant

s (f

irm

s) f

or

assi

gnm

ents

will

be

subj

ect t

o pr

ior

revi

ew b

y th

e B

ank.

In

addi

tion,

the

reco

rd o

f ju

stif

icat

ion

refe

rred

to in

par

agra

ph 5

of

App

endi

x 1

to th

e C

onsu

ltant

Gui

delin

es f

or e

ach

cont

ract

for

the

empl

oym

ent o

f in

divi

dual

con

sulta

nts

estim

ated

to c

ost t

he

equi

vale

nt o

f U

S$ 5

0,00

0 or

mor

e sh

all b

e su

bjec

t to

Prio

r R

evie

w b

y th

e B

ank.

All

othe

r co

nsul

tanc

y co

ntra

cts

shal

l be

subj

ect t

o th

e po

st r

evie

w.

(b)

Shor

t lis

ts o

f co

nsul

tant

s fo

r se

rvic

es e

stim

ated

to c

ost l

ess

than

US$

500,

000

equi

vale

nt p

er c

ontr

act m

ay b

e co

mpo

sed

entir

ely

of n

atio

nal c

onsu

ltant

s in

acc

orda

nce

with

the

prov

isio

ns o

f pa

ragr

aph

2/7

of th

e C

onsu

ltant

Gui

delin

es.

Sl

. N

o.

Des

crip

tion

of S

ervi

ces

Est

imat

ed

Cos

t (R

s. in

M

illio

n)

Est

imat

ed

Cos

t in

equi

v.

US$

Mill

ion

1US$

=Rs.

44

Met

hod

of

Sele

ctio

n R

evie

w b

y B

ank

(Pri

or

/ Pos

t)

Exp

ecte

d P

ropo

sal

Subm

issi

on

Dat

e

Com

men

ts

1 W

est B

enga

l

1.

1 Im

plem

enta

tion

Supp

ort C

onsu

ltant

15

.4

0.35

Q

CB

S

Prio

r M

ay, 2

009

1.2

Qua

lity

Ass

uran

ce C

onsu

ltant

6.

6 0.

15

QC

BS

Po

st

Aug

ust,

2009

1.3

O&

M C

apac

ity B

uild

ing

Con

sulta

nts

(Mul

tiple

Pac

kage

s)

35.2

0.

8 Q

CB

S

Post

O

ctob

er, 2

009

2 M

ahar

asht

ra

2.1

Con

sulta

ncy

for

Impl

emen

tatio

n Su

ppor

t for

K

orad

i TPS

15

.4

0.35

Q

CB

S Pr

ior

July

, 200

9

2.2

Con

sulta

ncy

for

Qua

lity

Ass

uran

ce f

or K

orad

i T

PS

6.6

0.15

Q

CB

S Pr

ior

Jan,

2010

2.3

O&

M C

apac

ity B

uild

ing

Con

sulta

nts

for

Kor

adi T

PS (

Mul

tiple

Pac

kage

s)

35.2

0.

8 Q

CB

S Po

st

Oct

ober

,200

9

2.4

Des

ign

Con

sulta

nts

for

Uni

t 1&

2 C

hand

rapu

r T

PS

40.7

0.

92

QC

BS

Prio

r A

pril,

2009

2.5

Con

sulta

ncy

for

Rap

id S

ocia

l Ass

essm

ent

(RSA

) fo

r U

nit 1

&2

Cha

ndra

pur

TPS

0.

55

0.01

Q

CB

S Po

st

July

,200

9

85

2.6

Con

sulta

ncy

for

EA

DD

for

Uni

t 1&

2 C

hand

rapu

r T

PS

2.75

0.

06

QC

BS

Post

Ju

ly,2

009

2.7

Des

ign

Con

sulta

nts

for

Uni

t 2 B

husa

wal

TPS

18

.7

0.42

Q

CB

S

Apr

il,20

09

2.

8 C

onsu

ltanc

y fo

r R

apid

Soc

ial A

sses

smen

t (R

SA)

for

Uni

t 2 B

husa

wal

TPS

0.

55

0.01

Q

CB

S Po

st

July

,200

9

2.9

Con

sulta

ncy

for

EA

DD

for

Uni

t 2 B

husa

wal

T

PS

2.75

0.

06

QC

BS

Post

Ju

ly,2

009

2.10

Des

ign

cons

ulta

nts

for

Uni

t 3 P

arli

TPS

18

.7

0.42

Q

CB

S Pr

ior

Apr

il,20

09

2.

11 C

onsu

ltanc

y fo

r R

apid

Soc

ial A

sses

smen

t (R

SA)

for

Uni

t 3 P

arli

TPS

0.

55

0.01

Q

CB

S Po

st

July

,200

9

2.12

Con

sulta

ncy

for

EA

DD

for

Uni

t 3 P

arli

TPS

2.

75

0.06

Q

CB

S Po

st

July

,200

9

3 H

arya

na

3.1

Des

ign

Con

sulta

ncy

18.7

0.

42

QC

BS

Prio

r A

pril,

2009

3.2

Env

iron

men

t Aud

it an

d D

ue D

ilige

nce

2.75

0.

06

QC

BS

Post

A

pril,

2009

3.3

Rap

id S

ocia

l Ass

essm

ent

0.55

0.

01

QC

BS

Post

A

pril,

2009

3.4

Ass

essm

ent o

f O

&M

Pra

ctic

es a

t Pan

ipat

6.

6 0.

15

QC

BS

Post

A

ugus

t,200

9

3.5

Impl

emen

tatio

n Su

ppor

t Con

sulta

nt

15.4

0.

35

QC

BS

Prio

r Ju

ne,2

010

3.6

Stre

ngth

enin

g O

&M

Pra

ctic

es

(Mul

tiple

Pac

kage

s)

28.6

0.

65

QC

BS

Prio

r A

ugus

t,201

0

3.7

Qua

lity

Ass

uran

ce C

onsu

ltant

6.

6 0.

15

QC

BS

Prio

r O

ctob

er,2

010

4 C

EA

4.1

Impl

émen

tatio

n Su

ppor

t 6.

6 0.

15

QC

BS

/FB

SPr

ior

July

200

9

4.2

Red

uctio

n of

Bar

rier

s to

R&

M I

nter

vent

ions

8.

8 0.

2 Q

CB

S /F

BS

Prio

r M

arch

, 201

0

4.3

Dev

elop

ing

Mar

kets

for

Im

plem

enta

tion

of

R&

M in

Ind

ia

8.8

0.2

QC

BS

/FB

SPr

ior

Mar

ch, 2

010

4.4

Rev

iew

of

Exp

erie

nce

from

Pilo

t R&

M

Inte

rven

tions

8.

8 0.

2 Q

CB

S /F

BS

Prio

r M

arch

, 201

0

86

4.5

Rev

iew

of

Inst

itutio

nal C

apac

ity a

t CE

A

6.6

0.15

Q

CB

S /F

BS

Prio

r A

pril,

2010

4.6

Stre

ngth

enin

g of

Ins

titut

iona

l Cap

acity

at

CE

A

8.8

0.2

QC

BS

/FB

SPr

ior

Mar

ch,2

011

87

Annex 9: Economic and Financial Analysis

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

A. PROJECT LEVEL ANALYSIS

1. Project level financial and economic analysis is conducted based on information provided in the Detailed Project Report (DPR) for the R&M interventions in the three selected power plants. Consistent with the phased implementation plan across the three plants, the DPR for Unit-5, Bandel has been received, whereas the DPRs for Unit-6, Koradi and Units-3&4 Panipat are expected by March 2009 and September 2010 respectively. Therefore, the project level analysis presented here is for R&M of Unit-5 Bandel only, whereas the analysis for Unit-6, Koradi and Units-3&4 Panipat would be carried out subsequently consistent with the eligibility criteria under loan covenants for the project. The following project level analysis is divided into four parts: (i) Options available to owners of old power plants; (ii) Economic Analysis; (iii) Financial Analysis; and (iv) Detailed Assumptions for Financial and Economic Analysis.

I. OPTIONS AVAILABLE TO OWNERS OF OLD POWER PLANTS

2. The units proposed for rehabilitation have a vintage of over 25 years and are performing below the original design parameters .For such units the concerned utility has the following options:

a) Do nothing (without Project case): In this case the unit continues to generate inefficiently for another 5-7 years (conservatively assumed to be 7 years for the subsequent analysis), and is subsequently scrapped. The power available during this period is unreliable due to increasing forced outages and the unit heat rate continues to be high (inferior).

b) Efficiency Integrated Renovation & Modernization (R&M): The utility undertakes the essential investments in the unit so that the unit can run at or close to its design parameters for the next 15 years. In addition, the selected design option enables significant reduction in heat rate – even beyond the original design parameters.

c) BTG Replacement: The utility replaces the Boiler Turbine Generator (BTG) of the unit at an adjacent piece of land so that the same balance of plant facilities as well as coal and water linkages can be used. This option allows the existing unit to generate even as new facilities are being built, thus minimizing the shutdown period. The new unit can run efficiently for the next 25 years.

d) Scrap the Unit: This consists of simply closing down the unit. As there are extreme power shortages the opportunity cost of power is high (surplus states can earn revenue from export of power to deficit states). Unless current unit performance is severely compromised, it is unlikely to be scrapped in the face of current supply shortages. The next option which allows the existing unit to be scrapped and a new unit commissioned at the same site is therefore a more viable option.

88

e) Complete Replacement: The existing unit is scrapped completely and a new generation unit is built on the same site using same coal and water linkages.

3. The following analysis consists of a comparison of the viability of each option (excluding that of scrapping of the units) with the base case, i.e. do nothing - the without project case. The costs and benefits of the options of R&M, BTG Replacement and Complete Unit Replacement are compared with the Without Project case to determine which is most viable. The following table sets out the key differences in cost and performance (benefits) for the options available.

Without

Project R&M New BTG at

Adjacent Site Complete Replacement

Cost per MW Nil Rs.22 million Rs.30 million Rs.45 million Life 7 years 15 years 25 years 25 years Capacity 210 MW 215 MW 250 MW 250 MW Project Duration 0 months 24 months 24 months 33 months Shutdown period (included in project duration)

0 months 6 months 9 months 33 months

Forced outages Increase Decrease Minimal Minimal 4. In the case of Bandel, according to the technical design consultants hired by WBPDCL, the BTG Replacement option is not possible for technical reasons and due to space constraints in the plant. Analysis is therefore carried out for R&M and Complete Unit Replacement relative to the Without Project base case. The main difference between R&M and Complete Unit Replacement is the upfront size of the capital cost, life extension, and time before the generation unit can become operational. In case of R&M the unit operates in its current state for the initial 18 months and is shut down for a period of 6 months after which it operates with improved performance. In case of Complete Unit Replacement, the unit is not operational for an initial 33 months, after which a new unit is commissioned.

II. ECONOMIC ANALYSIS

Calculation of Economic Benefits

5. The key economic benefits of R&M, BTG Replacement and Complete Replacement fall into the following categories:

a. Fuel cost reduction due to more efficient unit b. Increased generation from higher capacity, increased availability and life extension c. Increased reliability of electricity supply (reduced forced outages) d. Reduction in pollutant emissions

The above benefits are mutually exclusive. For economic analysis of various options, the capital cost in each case is deducted from the value of above economic benefits.

a. Benefit from Reduction in Fuel Cost

6. To value the coal savings due to increased energy efficiency, we calculate the value of coal saved under R&M and replacement. These savings are valued based on the prevailing international coal prices (adjusted for differences in quality between foreign and Indian coal). In

89

case of R&M, the unit’s heat rate, auxiliary consumption, and secondary oil consumption improve, leading to lower fuel cost per kWh of generation. In the first seven years the fuel cost is Rs.1.6 per kWh in the Without Project case and around Rs.1.3 per kWh in case of R&M.

b. Benefit from Increased Generation

7. Due to the prevailing power shortage in India (which is expected to continue over the next several years), customers are willing to pay more than the prevailing tariffs for regular and uninterrupted supply of power. Therefore the value of the extra generation is derived from an analysis of those who are using alternative sources of power (at higher cost) and those who have no current access to power (but are willing to pay for power). Accordingly, the value of increased generation V can be formulated as follows:

ECSCPosV SG }.)1({ βαβα −−++= (1)

where, Pos is the price of power sourced from alternate grid based generation sources

which is substituted by the increased generation from the project. Long term supplies would be typically sourced through long term contracts with gas or coal based generating stations (long term marginal cost of power). It could also be seen as a series of short-term supplies which are typically sourced from trading companies, power exchange or unscheduled interchanges from the grid.

CSG is the cost of self generation per kWh (usually from diesel generators). CS is the consumer surplus per kWh for those who were previously not

receiving power but benefit by now receiving it because of increased generation from the project.

α is the share of increased generation from the project that displaces power sourced from alternate grid based generation sources. (varies from 0 to 1)

β is the share of increased generation from the project that replaces self-generation. (varies from 0 to 1)

E is the quantity of increased generation of power as a result of the project. (1 - α – β) is the share of increased generation that is supplied to the segment of

population that does not currently have access to electricity. 8. In this analysis, for the base case, POS is taken as Rs. 3.62 per kWh which is the average cost of alternate supply from recent gas based thermal generation. The corresponding figure for coal based thermal generation is about Rs.2.30 per kWh. The weighted average sale price for power traded in India in 2007-08 is Rs.4.52 per kWh. Price of unscheduled interchanges can go up to Rs.10.00 per kWh. Although POS is taken as Rs. 3.62 per kWh in the base case, economic analysis has also been checked using price from coal based super critical generation.

9. The value of CSG – the cost of diesel based self generation has been estimated at Rs. 7 per kWh (excluding taxes). We conservatively only consider variable costs here, as it is assumed that consumers would continue to own diesel generators but would use them less frequently due to the extra generation capacity.

90

10. In terms of the consumer surplus from consumers that do not have access to power prior to the investment, it is conservatively assumed that the R&M investment would not lead to increased access by itself. This component is therefore assumed to be zero.

11. The increase in generation from post-R&M is a result of increased capacity, better availability (PLF), reduced auxiliary consumption and increased unit life. In Unit 5 of Bandel, R&M results in 2,640 MU of extra generation in the first seven years. This extra generation is due to increase in PLF from 67 percent to 85 percent, reduction in auxiliary consumption from 11 percent to 8.5 percent, life extension from 7 to 15 years (plus two years of pre-R&M operation) and an increase in capacity by 5 MW. The total extra generation over a period of 15 years is 16,900 MU.

12. The results of the analysis are given in the table below, which reports the IRR for different values of α and β for the options of R&M and Complete Unit Replacement.

ERR R&M Complete

Replacement α = 0 β=1 46% 21% α= 0.5 β= 0.5 39% 19% α = 1 β= 0 29% 15%

13. From this analysis we take a conservative view on the value of extra generation by assuming that the additional electricity generated will reduce the power purchased from other sources i.e. α =1. The proxy of power chosen for this analysis is based on situations where regular payments are made and does not take into account a one off situation of acute power deficit in the state. Note that the value of power could be higher than this figure.

14. This project remains economically viable even if the value of extra generation falls from Rs.3.62 per unit to Rs.2.30 per unit (cost of alternate generation from coal based generation) which results in ERR of 17 percent for R&M.

c. Benefit from increased reliability

15. Again, we take a conservative approach. We assume a part of the value for increased reliability forms part of the willingness to pay for extra generation and has been included in the previous component. Consumers that would be willing to pay high premiums for very reliable power supply (such as factories and hospitals) are assumed to continuing having access to back up generation (as the investment is not considered to increase reliability sufficiently to meet the needs of those with a high need and willingness to pay for reliable generation).

16. Also the increase in reliability results in reduction in unit heat rate and secondary oil consumption which is accounted for in the reduction in fuel cost component.

d. Benefit from reduced emissions of pollutants

91

17. As the investment is likely to impact emissions of pollutants, there are pollution externality benefits of investment that need to be valued and included in the calculation. The following aspects need to be considered:

• Emissions from the rehabilitated and/or new plants are lower per kWh than for the existing plant they replace. This leads to lower pollutant emissions which has a value.

• There will be some additional emission impact due to the increased generation. Thus the savings in emissions per kWh have to be set against the increase in total generation.

• There are some savings to the extent that the rehabilitated units replace self generation. The latter is much more polluting that the former, as can be seen in the table below.

Pollutant being reduced

External costs for self generation (US$/ton)

External costs for power from plants with high stacks (US$/ton)

Value of switching (US$/ton)(*)

PM10 7,963 234 7,729 SO2 1,747 51 1,696 NOx 668 20 648

Source: Lvovsky et al (2001)58 Switching value is the difference between the external costs of self generation and those from plants with high stacks. 18. The benefit can be calculated based on how many tons of each pollutant is saved due to the switch from self generation to sourcing from the power plant. In case of India, the Indian coal does not have high sulphur content therefore SO2 is not significant.

19. Since the objective of this project is to reduce carbon emissions in this analysis only the carbon reduction benefits have been calculated. The renovation and modernization of coal fired generation units would lead to improved energy efficiency as well as a higher amount of power generation due to increased capacity and improved load factor. To calculate the GHG benefits the GEF Manual59 has been followed. To facilitate the calculation of direct emission reductions, the emission reduction (or increase) has been broken down into two parts:

A. Emission Reduction from Present Level of Coal Consumption:

20. With improved energy efficiency, more electricity can be generated from the same amount of coal. In case the EE R&M project was not undertaken, this additional electricity generated from the same amount of coal would have been provided from new sources of generation connected to the grid – including coal-fired, gas-fired, lignite-fired, large hydropower, nuclear and renewable energy projects. Therefore, this additional generation avoids emissions from a combination of these sources.

58 Lvovsky, K. et al. (2000), Environmental Costs of Fossil fuels: A Rapid Assessment Method with Application to Six Cities, World Bank Department Paper 78, Washington DC: The World Bank.

59 GEF manual for calculating GHG benefits of GEF projects: energy efficiency and renewable energy projects

92

B. Emission Reduction / Increase from Additional Coal Consumption: 21. Because of increase in the capacity and improved plant load factor, the overall generation from the unit may be more than the generation possible from using the same amount of coal, thus leading to combustion of even more coal than earlier. Emission from this additional generation that requires additional coal to be burnt should be compared with emission from new generation capacities connected to the grid – including coal-fired, gas-fired, lignite-fired, large hydropower, nuclear and renewable energy projects. The emission reduction (or increase) for this part would be based on the difference in emission factors for the rehabilitated plant and the future build margin for the gird.

22. The Direct Emission Reductions for Bandel Unit 5 are to the tune of 0.85 million tones of CO2. For the purpose of this analysis, the value of carbon emissions is conservatively taken as $8 per metric tonne CO2. However this value can go as high as $30 per metric tonnes CO2.

Assuming $8 as the value of carbon benefits, the valuation of carbon emission reduction for Bandel is around Rs. 326 million.

The calculation of carbon emission reduction is provided as a separate analysis in Annex-16. The valuation of the carbon reduction benefits has not been included in the economic analysis. The valuation results will further strengthen the ERR results. Results of Economic Analysis

23. Both the options result in more efficient use of fuel leading to absolute savings in coal usage and increased generation. They also lead to reduced emissions due to switching from self generation. Keeping the status quo performance of the unit as the base case the ERR in case of R&M and Complete Replacement programs is shown below.

(The key assumptions of the analysis are covered at the end of this section.)

ERR EE R&M Complete Replacement

Highest ERR

Bandel Unit 5 29% 15% EE R&M 24. The above ERR calculations do not include the impact of economic benefits from carbon emissions reduction. The projected Heat Rate values for the EE R&M option are similar to those for the Complete Replacement option. As a result, the difference between the economic benefits from carbon emissions reduction is minor. An analysis conducted to evaluate the difference in economic benefits from carbon emissions reduction indicated that the replacement option leads to slightly higher annual reduction in carbon emissions, which if valued at an optimistic price of USD 15 per TCO2 would yield an additional economic benefit of only USD 0.6 million per annum. This additional economic benefit does not materially alter the economic comparison and EE R&M option remains preferable over Complete Replacement option.

Scenario Analysis

25. The viability of R&M projects can be adversely affected by under-estimation of costs, longer than anticipated implementation time and failure to achieve the anticipated R&M benefits.

93

The increase in cost and delay in implementation might be due to surprises i.e. changes required which may not have been anticipated and are known only once the entire machinery is opened. Sometimes R&M cannot re-achieve the original design specifications because of deterioration in coal quality and other factors.

26. Therefore to take into account the above possible impacts on costs and benefits, scenario analysis has been performed that assumes that not all operational and outcome parameters suggested by the design engineers are actually met due to the R&M investment. The results are shown in the table below. Each of the scenarios is calculated independently of the rest.

27. Variations in implementation parameters are found to have more impact on the ERR than the variations in outcome parameters. Out of the implementation parameters, cost overrun causes the maximum impact on ERR. The table below summarizes the changes in the R&M ERR if the various design parameters are not met.

Conclusions

28. Based on the ERR, the EE R&M of the unit is found to be the more economically viable option. The scenario analysis highlights that even in the case of variations in the key parameters, the economic returns on R&M investment are attractive (they range from 20 percent to 29 percent) which remains higher than the Complete Replacement option (15 percent).

III. FINANCIAL ANALYSIS

29. The Financial Internal Rate of return (FIRR) has been calculated for each of the projects based on a comparison between having no project and carrying out either an EE R&M, BTG Replacement or a Complete Replacement. As the regulators have not published their views on what process they will follow for determining the tariff, FIRRs are calculated for different forms of regulatory treatment, and the extreme (high and low) returns are considered.

94

Calculating Benefits & Costs of Investment

30. The anticipated benefits accruing on implementation of R&M, BTG Replacement or Complete Replacement include reduction in auxiliary consumption, increase in unit availability (resulting in higher load factor), reduction in station heat rate (SHR) with resultant savings in coal and oil consumption and availability of incremental saleable energy. The financial benefits to the Utility include annual increase in revenue from the incremental saleable energy and savings in expenditure of coal and oil.

Indicative Performance Improvements from Different Options

Generation (MUs)

Typical Heat Rate (Kcal / KWh)

PLF Typical Oil Consumption (Ml / KWh)

Coal Consumption (tonnes/year)

Pre R&M 7,082 2,872 67% 2.5 719,158 Post R&M 25,628 2,456 85% 1.5 931,371 Complete Replacement 26,296 2,400 85% 1.5 1,043,871

31. The drivers of increased energy production are the increase in capacity from a 210 MW unit to 215/250 MW, plus better plant availability leading to an improvement in plant load factor from 67 percent to 85 percent. The financial benefit of the investment in EE R&M is increased revenue from additional sales of energy, with increased (but proportionally lower) variable costs from increased fuel consumption. The net generation increases by 16,835 MU. Assuming the same tariff rate pre and post R&M of approximately Rs. 1.89 the increased revenue on an annual basis is approximately Rs. 2,600 million.. On the other hand, the increase fuel costs are only about Rs. 1,666 million, thus providing about Rs. 4266 million annually towards incremental benefits from the project.

32. The project is funded through a combination of utility’s own Equity, IBRD loan and GEF grant. In the analysis FIRR has been benchmarked against Weighted Cost of Capital (WACC) – the weighted average cost of equity and the cost of debt together, with weights equal to the share of financing from these two sources. For this project, WACC takes a value of 8.52 percent.

Result of Analysis

R&M Complete Replacement

Existing tariff continue 16.60 % 13.55% Cost plus approach for tariff 10.44 % 10.58%

33. The FIRR from the R&M project is 16.60 percent if the existing tariff continues and falls to 10.44 percent in the extreme case where the tariff is determined on a pure cost-plus basis (an unlikely regulatory approach). On the other hand, the FIRR from the complete replacement returns a figure of 13.55 percent if the existing tariff regime were to continue and falls to 10.58 percent if tariffs were determined on a pure cost-plus basis. Also, it is seen that the levelized tariff in case of R&M turns out to be lower than the existing levelized tariff in all scenarios

95

(adverse implementation parameters and adverse outcome parameters), whereas in case of replacement the levelized tariff would be about 9 percent higher than the existing levelized tariff even when all implementation and outcome parameters are fully met. Thus R&M is financially a more attractive option than Complete Replacement.

Options for Regulatory Treatment of R&M

34. The methodology to calculate the tariff post investment is not clearly defined – though the team has held discussions with the regulator and understands the likely options (see annex on Regulatory Engagement). To capture the impact on FIRR under the different regulatory options, we have calculated the FIRR in the following tariff scenarios:

A. Existing Tariffs continue. In this case the prevailing tariff for generation continues. B. Cost Plus Tariff based on Actual Unit Performance. This is a cost-plus approach

wherein the allowable costs and thus tariff are based on the actual performance of the unit post investment. The cost recovery is not limited to the norms and the Generator recovers actual costs.

C. Cost Plus Tariff based on Design Unit Performance. This is a traditional cost-plus approach. However, in this case, unit design parameters are used to calculate the allowable costs. If the actual performance meets the norm, the Generator recovers actual costs but if it is beyond the norms then cost recovery is limited to the norms.

D. Benefit Sharing based on Actual Unit Performance. This is a modified cost-plus approach wherein the allowable costs are based on the actual costs incurred post the investment. The framework is similar to the existing regulatory framework except if the actual performance meets the norm, the Generator recovers actual costs but if it is better than the norms, cost recovery is not limited to the norms. The benefit from the increase in efficiency (difference between prevailing tariff and the new tariff calculated) is shared equally by the consumers and Generator. This gives an incentive to the Generator to perform better.

E. Benefit Sharing based on Design Unit Performance. This is a modified cost-plus approach wherein the allowable costs are based on the design parameters post R&M and related costs. The framework is similar to the existing regulatory framework except if the actual performance meets the norm, the Generator recovers actual costs but if it is better than the norms cost recovery is not limited to the norms. The benefit from the increase in efficiency (difference between prevailing tariff and the new tariff calculated) is shared equally by the consumers and Generator. This gives an incentive to the Generator to perform better.

F. Upfront Tariff based on Alternate Green-Field Generation. In this case the generator is committed to supply only pre-R&M quantity of energy at pre-R&M tariff rates for the remaining life of the plant. The price of the additional quantity supplied by it (through the investment) is based on the tariff of a new plant.

Scenario Analysis

35. As explained above, the viability of R&M projects is examined in different regulatory scenarios and in different scenario where implementation and outcome parameters are not met. The table below shows the FIRR in all the different scenarios. The FIRR is highest (18.07 percent) in Scenario F when the existing tariff (Rs. 1.89 per unit) and tariff of a new plant (Rs.

96

2.3 per unit) are used to determine the tariff of the unit post R&M. If the existing tariff continues (Scenario A) then the FIRR is 16.6 percent and if the benefit is shared equally between the utility and consumer the FIRR touches 13.71 percent. In case of Implementation & Outcome Scenarios -Variations in outcome parameters cause more impact on the FIRR than the variations in implementation parameters. Out of the outcome parameters, variation in SHR causes the maximum impact on FIRR.

36. According to an order issued by West Bengal Electricity Regulatory (WBERC) in December 2007 (2.8.6.2)- “If the actual performance of a generating station of a generating company or a licensee in a particular year in respect of any parameter, the operating norm of which has been laid down in Schedule 9A of these regulations, is better than the norm applicable to that parameter in that year, then such gain shall be shared in the manner and with the person as specified in Schedule 9B of these regulations.”

37. Also “In addition to the gains originating from better performance which are to be shared as per regulations 2.8.6.2 and 2.8.6.3, the licensee or the generating company shall also be entitled to incentives for improved performance, if the generating company or the licensee attains or exceeds various standards of operating performance related to different parameters for a year according to principles as specified in Schedule-10 of these regulations”

38. Since the targeted operating norms after R&M for Unit 5 of Bandel far exceed the operating norms set by the commission therefore according to the WBERC regulations the utility will be entitled to gain sharing and incentives, thus scenario D seems more likely.

Conclusion

39. Based on the FIRR, the R&M of the unit is a better option that replacement of the entire unit. The scenario analysis highlights the fact that even in the case of variations in the key parameters the returns on R&M investment are better than the returns on Replacement. Overall, as would be expected, the degree of absolute financial viability of each option is sensitive to the way in which tariffs are set. However, the result that R&M is more viable than complete replacement is a robust result.

97

Tab

le-9

.1:

Res

ults

of

Scen

ario

Ana

lysi

s fo

r F

IRR

98

IV. DETAILED ASSUMPTIONS FOR ECONOMIC AND FINANCIAL ANALYSIS

Common Assumptions

• Capacity increases from 210 MW to 215 MW incase of R&M and 250 MW in case of Complete Replacement

• Capital Expenditure is estimated at Rs.21.97 million per MW incase of R&M and Rs. 44.94 million per MW incase of Complete Replacement

• Unit shutdown period varies from 6 months incase of R&M to 33 months for Complete Replacement

• Unit life increases to 15 years in case of R&M and 25 years in case of Replacement • Operational Parameters

� PLF increases from 67 percent to 85 percent in case of both R&M and Complete Replacement

� Station Heat Rate reduces from 2872 kcal/kWh to 2456 kcal/kWh in case of R&M and 2400 kcal/kWh in case of Complete Replacement

� Auxiliary Consumption reduces s from 10.86 percent to 8.5 percent incase of R&M and 8 percent in case of Complete Replacement

� Secondary Oil consumption falls to 1.5 ml/kWh in both the cases � For all these parameters a suitable escalation/deterioration factor is assumed

Specific Assumptions for Economic Analysis

• Value of Fuel Saved - To calculate the adjusted price of coal the average price of imported coal with calorific value 6000 kcal/kg is assumed to be Rs.2800.

• Value of additional Generation is assumed at average cost of alternate supply from recent gas based thermal generation i.e. Rs. 3.62 per kWh

Specific Assumptions for Financial Analysis

• Financing terms for World Bank loan -Rate of interest for domestic borrowing of 6.17 percent (Hedging cost of 3 percent+ LIBOR 3.175 percent), moratorium period of 2 years and repayment period of 10 years is assumed.

• Financing terms for domestic borrowing -Rate of interest for domestic borrowing of 10 percent, moratorium period of 2 years and repayment period of 10 years is assumed.

• O&M expenses reduces from Rs.1.09 million per MW to Rs.0.96 million per MW incase of R&M and Rs 0.9 million per MW in case of Complete Replacement

• For tariff calculation an O&M expense of Rs.1.3 million/MW is allowed by the Regulator and thus included in the tariff calculation.

• O&M expenses are assumed to increase at 4 percent • Existing tariff escalation factor is assumed at 4 percent and tariff escalation factor for a new

plant is assumed at 2 percent • Return on equity is assumed to be 14 percent

99

Trends in Revenue

23306

2608327009

2100022000230002400025000260002700028000

FY06 FY07 FY08

Rs

in m

iilion

Trends in Generation (MUs)

15109

15614

16805

14000

14500

15000

15500

16000

16500

17000

FY06 FY07 FY08

B. ENTITY LEVEL FINANCIAL ANALYSIS

West Bengal Power Development Corporation Limited

40. West Bengal Power Development Corporation Limited (WBPDCL) has a total generation capacity of 2,820 MW across six thermal power plants located at Bandel (4x80 + 1x 210 MW), Bakreshwar (5x210 MW), Kolaghat (6x210 MW), and Santhaldih (4x120 MW). WBPDCL plans to add 2230 MW over the eleventh plan period. Addition of the proposed capacity may spill over to the next plan period. During the tenth plan, three plants of 1270 MW were scheduled to be commissioned but due to time over run and technical difficulties these plants were delayed and are now scheduled for commissioning in the eleventh plan.

Historical Performance 41. Generation: The total generation of the company grew steadily at 5.5 percent compounded annual growth rate (CAGR) in the period. The portfolio of assets under WBPDCL is old. Most of the plants are not efficient and do not meet the regulatory norms for operating parameters such as SHR, PLF etc. Santaldih is operating at PLF less than 40 percent. At an aggregate level during 2007-08, WBPDCL achieved a PLF of 68 percent. Santaldih is proposed for replacement. Units in Bandel & Santaldih also face frequent outages. Investments in R&M and strengthening of O&M practices are required to make the existing plants more efficient.

42. Profitability: WBPDCL’s revenue has at a CAGR of 7.65 percent from FY06 to FY08. However, during FY08; WBPDCL has registered a growth rate of 3.55 percent on year on year (yoy) basis as compared to 11.92 percent in FY07. This is primarily due to an extraordinary item of Rs.2620 million against Fuel Cost adjustment of FY 05 and FY 06 and Rs. 80 million of Incentive as per directive of WBERC, included in revenue of FY 07.

43. The profit after tax (PAT) increased steadily until FY06 and saw a quantum jump in FY07. This jump can be attributed to the drastic decline in the interest and financial charges in FY07.

100

Trends in Profit afterTax (PAT)& Interest & Financial Charges

226

2552

18292256

992 845

0500

10001500200025003000

FY06 FY07 FY08

Rs

in m

ilion

Profit after Tax Interest & Financial charges

Expenditure Split FY08

85%

5% 4% 1% 5%

Fuel Cost Employee Cost Repairs & Maintenance

Administrative Expenses Stores Consumed

44. The interest and financial charges reduced drastically when the Government of West Bengal (GoWB) implemented a financial restructuring for WBPDCL and erstwhile West Bengal State Electricity Board (WBSEB). Under this financial restructuring plan, GoWB adjusted Rs. 27,183 million out of total amount of Rs. 28,527 million receivable from erstwhile WBSEB on 31 March 2006 against an outstanding GoWB loan. The balance of Rs.1, 344 million was considered in the books as receivable from WBSEB.

45. Expenditure: The total generation & related expenses have increased from Rs.20,974 million in FY06 to Rs. 24,071 million in FY08 at a CAGR of 7.3 percent. The split of expenditure has not changed significantly over the period. Fuel cost which is the main component constitutes 85 percent of total expenditure in FY08. Fuel costs for the Company’s generation plant was Rs. 20342 million in FY08 against Rs.18767 million in FY07 recording an increase of 8.4 percent which is attributed to the increased generation levels and increase in cost

of coal cost. This is not an issue as this item is a pass through to the customer. Employee cost have increased at a CAGR of 26.5 percent The increase in employee cost during FY08 by 48.7 percent as compared to FY07 was primarily on account of recruitment of new staff for the assets coming on stream in FY09 viz. Sagardighi, extensions at Bakreswar and Santaldih Plants. Administration and other expenses includes rent, rates and taxes, insurance etc. which

decreased by 46 percent CAGR from FY06 to FY08. These expenses have decreased in FY08 compared to FY06 due to a substantial decrease in miscellaneous expenses over the last three years. Even though the plants under WBPDCL are old, the expenditure on operations and maintenance (O&M) is comparatively low. The O&M expense per MW is lower than the norm set by CERC.

101

Financial Projections for WBPDCL

Note: - PBDIT-Profit before Depreciation, Interest & Tax; PBT- Profit Before Tax: PAT- Profit After Tax

The formula used for calculation of key financial ratios are given in the table below

46. The financial projections are based on the following assumptions:-

• WBPDCL plans to more than double its capacity from 2820 MW in FY08 to 6320 MW by end of 2013. A Debt: Equity ratio of 70:30 with repayments tenors similar to existing projects of 11-13 years which is the current repayment terms for the PFC and REC funded projects has been assumed.

Total capacity

(MW) Expected Year of

commissioning Estimated Project Cost (Rs million)

X Plan Projects Sagardighi Stage 1 600 (2 X 300) FY 09 27500Santaldih Unit 5 250 (1 X 250) FY 09 9550Bakreswar Unit 4,5 420 (2 X 210) FY 09 14300XI Plan Projects Sagardighi Stage II 1320 (2 X 660) FY 13 79200Santaldih Unit 6 250 (1 X 250) FY 12 10000Bakreswar Unit 6 660 (1 X 660) FY 12 39600Total 3500 191600

102

Trends in Generation (MUs)

37424

44909 46604

0

10000

20000

30000

40000

50000

FY 06 Adjusted FY 06 FY 07

• R&M Projects have been considered for Bandel Unit 5 under current consideration for World Bank funding and Kolaghat Unit 3 which is currently undertaking an RLA study and R&M scope design financed by KfW

• The operational performance of the existing operational assets have been based on the projections of WBPDCL as submitted to WBERC in the MYT petition for the period FY09 to FY11. The same trend has been considered for the subsequent period.The operational performance of the new projects under the Xth and XIth Plan has been based on the WBERC specified guidelines for operating norms.

• The fuel cost and operation & maintenance expenses for the existing assets viz. Koradi Thermal Power Station, BkTPS, Bandel Thermal Power Station and Santhaldih Thermal Power Station have been based on the Multi Year Tariff (MYT) petition as filed by WBPDCL with WBERC for the control period FY09 to FY11. Beyond the control period the expenses have been projected on the basis of WBERC allowable norms for the same.

• With the setting up of new units the number of employees is bound to increase. The projection on the number of employee and employee costs for new stations has been considered in proportion with plant size. CAGR of 5 percent growth has been used for projection of employee expenses on a standard YoY hike in employee’s salary.

Maharashtra State Power Generation Company Limited 47. The erstwhile Maharashtra State Electricity Board (MSEB) was restructured in the FY 2005-06 into four companies i.e. MSEB holding Company, Maharashtra State Power Generation Company Limited (MSPGCL), Maharashtra State Electricity Transmission Company Limited (MSETCL) and Maharashtra State Electricity Distribution Company (MSEDCL). MSPGCL was entrusted the work of generation of electricity in the State of Maharashtra. MSPGCL operates in a regulated sector with the return on equity provided by Maharashtra Electricity Regulatory Commission (MERC). Throughout the analysis all the FY06 figures are from period June 2005-March 2006, and therefore figures for April and May 2005 are not included.

48. The total capacity of MSPGCL’s existing generating stations is 9972 MW, comprising 2320 MW of hydel generation capacity, 6830 MW of coal based thermal generation capacity and 852 MW of gas based generation capacity.

Historical Performance 49. Generation: The total units generated increased by 24 percent in FY07. The increase was primarily due to the increase in PLF from 71 percent to 73 percent as opposed to an increase in total installed capacity. If the total units are adjusted for two months, then the increase is only about 4 percent. Most of

103

Trends in Profit After Tax (PAT)

11291355

2335

0

500

1000

1500

2000

2500

FY 06 Adjusted FY 06 FY 07

Split of expenditure in FY07

85.64%

6.96%

0.83%6.58%

Generation of Pow er Repairs and Maintenance

Employee Costs Administration and General Expenses

the plants owned by MSPGCL are of considerable vintage. In 2007, CEA approved the de-rating of capacities for Nasik, Koradi, Bhusawal, Paras and Parli Thermal Power Stations (TPS).Also, the generation units of these plants are of smaller capacity which reduces the operational efficiency of the stations. In order to circumvent the problem, MSPGCL is considering the option of replacing the older and smaller units with newer and more efficient generating stations. Also to ensure that the existing plants operate at least at existing efficiency levels, if not better, for the rest of the life of the plant, the plants would have to be subjected to major renovation and modernization activity. This entails high investment in the future which may financially strain the company. Debt Service Coverage Ratio (DSCR) indicates the ability of the firm to pay its debt installments and interest from the cash available. MSPGCL’s DSCR in future is within the satisfactory range. The DSCR ranges from 1.29 to 1.69 in FY09 – FY18.

50. Profitability: The profit after tax (PAT) doubled in FY07.The jump in PAT can be attributed primarily to the increase in units sold and the rise in net realization. The profit that the company is earning is lower than the return the company is eligible to earn (fixed 14 percent RoE). The profit is lower on account of relatively poor performance of existing generating stations vis-à-vis performance parameters specified by MERC and higher O&M expenditure than allowed by MERC led to under-recovery of costs.

51. Expenditure: The total expenditure increased by 33 percent (from Rs.52, 065 million in FY06 to Rs. 69,489 million in FY07). The split of expenditure has not changed over the period. Fuel cost is the main component contributing around 85 percent of total expenditure. The increase in the fuel cost is on account of increase in station heat rate. The actual heat rate achieved during FY 2006-07 for all the stations except Khaperkheda was higher as compared to the norm. . Fuel costs also include the allowed transit losses. For a few plants, the transit losses are substantially higher than the MERC approved norms of 0.80 percent of coal transit losses for

non-pithead coal plants.

52. In the past the company has faced problems with regulator on the allowance of operating costs. For example, some of the existing old stations have not been able to adhere to operational performance norms as defined by the MERC and the additional cost is not allowed by the regulator affecting the

104

financial performance of the company. To address this challenge in 2008, the Appellate Tribunal for Electricity directed the Commission to take into consideration an independent study and reset the operating parameters, viz., transit loss of coal, station heat rate, auxiliary consumption, and specific oil consumption, and align its Regulations by prescribing achievable norms. Therefore in the future the allowance of operating costs may not be challenge for the utility.

Operational Norms for Existing MSPGCL Plants as per MYT

Station Heat Rate

Auxiliary Consumption

Specific Oil Consumption

Transit Loss

(Kcal / kWh) (%) (ml/kWh) (%) Actual Norms Actual Norms Actual Norms Actual Norms

Bhusawal TPS 2,673 2,561 9.75% 9.75% 2.70 2.00 2.00% 0.80%

Paras TPS 3,171 3,105 10.00% 9.70% 3.50 2.00 2.11% 0.80%

Parli TPS 2,634 2,573 9.00% 9.00% 2.50 2.00 3.24% 0.80%

Chandrapur TPS 2,600 2,480 7.90% 8.50% 1.17 2.00 1.00% 0.80%

Koradi TPS 2,977 2,907 10.28% 9.80% 2.56 2.00 0.80% 0.80%

Nashik TPS 2,597 2,584 9.00% 9.00% 3.30 2.00 1.00% 0.80%

Khaparkheda TPS 2,660 2,644 9.00% 8.50% 2.08 2.00 1.50% 0.80%

Uran GPS 2,010 1,950 2.30% 2.30% - - - -

Financial Projections for MSPGCL

Note: - PBDIT-Profit before Depreciation, Interest & Tax; PBT- Profit Before Tax: PAT- Profit After Tax

105

53. The key assumptions on which the financial projections for MSPGCL are based are given below.

• MSPGCL has planned for expansion of about 7000 MW (including 1,560 MW through replacement units) of capacity over a period of 2006-07 to 2012-13 for a total investment of about Rs. 350 billion.

• The investment plan is considered to be funded in the ratio of 80:20 of debt equity. MSPGCL has envisaged financing for the proposed investment plan through debt from the financial institutions like PFC and REC and the equity portion funding through internal cash generation and other sources.

• The operational parameters such as station heat rate, auxiliary consumption etc. for the existing generating stations have been assumed at performance parameter levels reported by MSPGCL for approval of Annual Revenue Requirement (ARR) for MYT period 2007-10 and assumed to sustain at the levels of FY2009-10 thereafter. For new expansion units and replacement units the operational parameters are considered at the levels specified in the Terms and Conditions of Tariff by MERC.

• The operating costs such as fuel cost, employee and administration & general expense is assumed to be as per cost estimated by MSPGCL in its petition submitted to MERC and has been escalated according to the past trend.

• Other income comprises revenues such as income from loans, advances to staff, income from trading, etc. In case of the existing stations, the trend for other income for the past five years has not been uniform. Hence an escalation of 5 percent over the previous year has been assumed for projecting the other income during the plan period.

• Return on equity at rate of 14 percent per annum has been assumed for the financial plan as per the norms approved by MERC.

Haryana Power Generation Company Limited 54. HPGCL has a total installed capacity of 2195 MW. Out of this, thermal power plants account for around 96 percent of the capacity. HPGCL owns three thermal power plants – Panipat Thermal Power Station (PTPS) (4x110, 2x 210, and 2 x 250 MW), Faridabad Thermal Power Station (FTPS) (3x55 MW) and Deenbandhu Chottu Ram Thermal Power Plant (2x300 MW). Along with the generation business in FY06, HPGCL was entrusted with the short-term and long-term power trading business for the state but the business has been transferred to both the distribution utilities with effect from April 1, 2008. Therefore in FY06, FY07 & FY 08 the revenue of HPGCL includes revenue for trading business and generation business.

55. Currently Haryana faces a peak deficit of around 30 percent. To meet the growing demand for power in the state HPGCL has been focusing on adding capacity (600MW were added in 2008) and improving the operating efficiency of generating stations through renovation and modernization (R & M) of old thermal generating stations (Unit 1 & 2 of PTPS).

106

Break up of units sold( MUs)

6181 8304 9740 9881

17218

6181

22240 24068 25715

0

5000

10000

15000

20000

25000

30000

FY05 FY06 FY07 FY08

Ow n Generation ( Gross) Bulk Trading ( Gross) Net Units Sold

56. The age profile of the thermal plants HPGCL is highly varied. There was no capacity addition from 1989- 2001.Therefore around half the thermal capacity was commissioned before 1989 and the other half post 2001. During 2001-2007, 725 MW was added to the capacity and in 2008 alone the generation capacity was augmented by another 600 MW.

Historical Performance 57. Generation: The gross units sold from own generation increased from 6181 million in FY03 to 9881 million in FY08 at CAGR of 17 percent. The two factors which were attributable for such growth are:

• Addition in installed capacity • Improvement in average PLF

58. All the three units in FTPS and Unit 1 -4 PTPS, which constituted approx 36 percent of total capacity of HPGCL, are more than 25 to 30 years old and are operating much below performance standards. In FY 08, the PLF of FTPS was around 49 percent and the PLF for Unit 1-4 of PTPS was around 61 percent. The average PLF of HPGCL was much higher around 78 percent due to moer than 80 percent PLF of Unit 5-8 of PTPS. The Station Heat Rate (SHR) is also considerably high. In FTPS the SHR was as high as 4759 Kcal/Kwh and in Unit 1-4 of PTPS it was around 3445 Kcal/Kwh. Further auxiliary power consumption and specific oil consumption of these seven units are abnormally high as compared to new PTPS units.

59. To improve the operating performance of HPGCL as a whole HPGCL undertook the R&M of Unit 1 & 2 of PTPS and the R&M of Unit 3 and 4 are in the pipeline. It has also decided to phase out old and inefficient plant like FTPS and invest in large and more efficient power plants. Unit 2 of FTPS has already been closed and the remaining units- Unit 1 and 3 are scheduled to be closed in FY11 and are planned to be replaced with gas-based units subject to availability and pricing of gas.

60. There has been improvement in the various parameters of efficiency over the years. The auxiliary consumption has improved from 11.04 percent in FY05 to 9.93 percent in FY 08. Similarly the coal and oil consumption in HPGCL’s plant have also improved. But even the current improved performance does not meet the norms set by HERC. As per HERC norms, the auxiliary consumption should be maintained below 9 percent while the oil consumption should be brought down to 2.0 ml/kWh even for the older plants as well.

107

Trends in Operating Profit

1221

3089 3304 3569

(301)

(2467)

702

2182

4952

21401160

-3000

-2000-1000

01000

20003000

40005000

6000

FY05 FY06 FY07 FY 08

Rs

in m

illion

Operating Profit Operating profit from Generation Business

Operating profit from bulk trading business

Trends in PAT

-40

-8

16.9 17.2

-50-40

-30-20-10

010

2030

FY05 FY 06 FY 07 FY08

Rs.

in m

illioj

n

Split of expenditure in FY 08

31%

65%

1% 3% 0.18%

Generation of pow er Purchase of Pow er R&M Employees Cost Administrative expenses

61. Profitability: Operating profit as a percent of total revenue declined from 7.04 percent in FY05 to 5 percent in FY08. One of the reasons for such reduction was the transfer of bulk trading business which HPGCL which was operating with negative margins in FY 06 & FY07. This has affected overall operating profitability of HPGCL. Operational profit of generating business showed significant improvement in FY07 due to increase in efficiency of operating parameters. The PLF increased from 67 percent in FY 06 to 79 percent in FY 07, auxiliary consumption reduced from 10.08 percent to 9.8 percent , oil consumption reduced from 3.74 ml/kwh to 1.85 ml/kwh and transit loss of coal declined from 4.79 percent to 3.23 percent.

62. During the last four years HPGCL earned operating profit but it incurred continuous losses at Rs.40 million and Rs.8 million in FY05 and FY06. This is mainly on account of high interest burden due to increasing level of borrowings to fund capacity expansion and working capital requirements. (aggregate loan liabilities of HPGCL including secured and unsecured loans have increased three fold from Rs.18, 458 million in FY03 to Rs. 57,420 million in FY08) and also transfer of bulk trading business in which HPGCL made an operating loss to the tune of Rs. 2467 million. In FY 07, though HPGCL more than doubled its operating profit from generating business, due to high operating losses incurred in bulk trading business, it could record only marginal profits.

63. Expenditure: Expenses of HPGCL mainly includes power generation cost, power purchase cost, repairs and maintenance cost, employee cost and administration cost. During FY 06- 08, purchase of power has been the main component of HPGCL’s expenditure. Since the trading division has been transferred to the distribution companies, in the future power generation cost will form the key component of expenditure.

108

Split of expenditure in FY 08 ( excluding power purchase cost)

87%

1%9%4%

Generation of pow er R&M Employees Cost Administrative expenses

Power generation cost, mainly includes coal consumption cost, is around 87 percent of total expenditure. Power generation cost component has been increasing and this can partly be attributed to high coal transit losses. In FY03 the losses were as high as 6.16 percent for PTPS and 7.8 percent for FTPS. Over these few years, HPGCL has succeeded in reducing the coal transit losses to 3.46 percent in FTPS and 3.02 percent in PTPS. One of the major initiatives taken by HPGCL is appointment of a coal agent in 2006.Though there is improvement in coal transit losses, it is still far behind CERC approved norms of 0.80 percent of coal transit losses for non-pithead coal plants.

Financial Projections for HPGCL

Note: - PBDIT-Profit before Depreciation, Interest & Tax; PBT- Profit before Tax: PAT- Profit after Tax

64. At present HPGCL faces two key issues- 1) Inadequate performance of its ageing Faridabad and Panipat Plants and 2) Inadequate power generation capacity to meet the increasing power demand which is expected to grow at around 14 percent p.a. during XI plan. The present performance of its existing old plants is affecting its operational and financial performance. To address these major issues, during 11th plan HPGCL has proposed capital outlay of Rs 113 billion mainly for undertaking renovation and modernization of existing plants and addition of 3900 MW (thermal and gas based) power generation capacity. These investments are expected to improve performance of the old plants as well as increase the power supply in the State by strengthening HPGCL’s generation capacity. As a result of the improvement of performance of old plants and setting up of new efficient plants the financial position of HPGCL is projected to improve. Further the financial position is expected to improve with the transfer of the trading business.

109

65. The key assumptions on which the financial projections for HPGCL are based are given below.

• HPGCL plans to add 1800 MW to its coal based generation capacity. It proposes to invest approximately Rs. 101 billion during 11th plan to add thermal as well as gas-based generation capacity of approx. 3150 MW.

• Refurbishment of the PTPS Unit 3, 4 &5 with installed capacity of 430 MW is also planned during the 11th plan.

• After 11th plan, old and underperforming coal-based Faridabad plants will be replaced by gas-based plants of 1050 MW in the year 2012-13 and 2013-14.

• Capital cost of any new coal based plants added beyond the 11th plan is assumed at Rs.45 million per MW and that of gas based plant is assumed at Rs.30 million per MW with an escalation of 5 percent every five years.

• The total investments planned during the period FY08 to FY12 is assumed to be funded in the debt equity ratio of 80:20 except for projects proposed to be funded by the World Bank, a debt to equity ratio of 70:30 has been assumed, where the additional equity/quasi-equity has been assumed to be brought in through market borrowings.

• While calculating future annual revenue requirement (ARR) for HPGCL, return on equity (ROE) of 14 percent has been assumed on the project equity from FY09 onwards. However, the ROE passed by HERC in the tariff order of 2007-2008 & 2008-09 was 12 percent.

• Future ARR of HPGCL has been projected taking into consideration the fixed as well as the variable cost estimated as per HERC prescribed norms.

• O&M cost which includes repairs and maintenance, employee cost and general administration expenses have been estimated on per MW basis as per CERC specified norms for the newer units and as per HERC passed costs for the existing units.

• An appropriate escalation factor is used for all the costs such as 4 percent for O&M expenses.

• Working capital for the existing as well as new plants has been estimated on the basis of HERC specified norms for the fuel stock (2 months), debtors (2 months), O&M expenses (1 month) and stores and spares (1 percent of capital cost).

110

Annex 10: Safeguard Policy Issues

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT A. Environment 1. Approach to Environmental Management. The project will result in major positive environmental benefits, in terms of improved energy efficiency, reduced local and global air pollutants, which will be measured and quantified during the Project. In order to maximize the rehabilitation measures, a two pronged approach has been adopted: (i) unit level improvements addressing environmental issues; and (ii) plant level improvements in respect of management of common effluents as well as EHS management systems. In order to achieve this, Environmental Audit and Due Diligence (EADD) studies were conducted for BTPS and KTPS. The scope of EADDs has been finalized after conducting environmental due diligence reports by the Bank’s environmental specialists, based on PPAH guidelines for rehabilitation of existing plants. The final EADD reports including Environmental Management Action Plans (EMAPs) have been finalized and disclosed by BTPS and KTPS respectively. Based on Bank’s internal due diligence report for PTPS, the Terms of Reference for conduct of EADD for PTPS has been cleared. Currently HPGCL is processing the procurement of consultants for conduct of EADD for PTPS. The objective of EADD is to establish and assess the baseline environmental performance with a view to identify appropriate technical, financial, institutional and management measures to improve the environmental performance of the rehabilitation units, in conjunction with the proposed R&M investments. The EADDs analyze plant level compliances and environmental impacts and provide measures including mitigation of potential/perceived environmental risks/liabilities as part of the proposed rehabilitation program. The final EADDs prepared on these lines for BTPS and KTPS includes the following:

� Baseline Environmental Performance o Compliance Assessment o Pollution Prevention & Control Assessment o Resource Efficiency Assessment o Occupational Health, Safety Assessment

� Potential Liabilities/Risks including Assessment of Environmental Impacts � Institutional Capacity Assessment � Identification of Interventions in the form of specific Environmental Management Action

Plans (EMAP) including budgetary estimates for implementation 2. Koradi Thermal Power Station. The Koradi Thermal Power Station (KTPS) is situated 18 km to the north of Nagpur city in Maharashtra. The plant has seven units with total installed capacity of 1300 MW (120 MW – 4 units, 200 MW - one unit; 210 MW – 2 units). R&M activities have been proposed for Unit 6. The final EADD including EMAP has been disclosed by MSPGCL at their corporate office and at KTPS. The EADD/EMAP are disclosed at Bank’s Infoshop. The key findings of EADD and the summary of EMAP are included in Table 10.1. 3. Bandel Thermal Power Station. Bandel Thermal Power Station (BTPS) is located in the Hooghly district of West Bengal. The area is included in the Triveni Chandrahati Gram panchayat. BTPS was established in 1965 and consisted of four coal-fired thermal units, each of 82.5 MW capacity. A fifth unit with a capacity of 210 MW was added in 1982. R&M activities are proposed for Unit-5. The final EADD including EMAP has been disclosed by WBPDCL at their corporate

111

office and at BTPS. The EADD and EMAP are disclosed at Bank’s Infoshop. The key findings of EADD and the summary of EMAP are included in Table 10.2 4. Panipat Thermal Power Station. Panipat Thermal Power Station (PTPS) is located in Khukhrana Village, about 8 km west of Panipat City on Panipat-Assandh Road (about 100 km from New Delhi) in the State of Haryana. Established in 1979, the plant comprises eight generating units (4x110 MW, 2x210 MW and 2x250 MW) for a total installed capacity 1,360 MW. An internal due diligence report has been prepared by Bank’s environmental specialists for review of information/data collected by the due diligence team from the plant. The due diligence has focused on the following environmental aspects.

i) Status of compliance with applicable regulatory requirements related to environment, ii) Status of compliance with applicable World Bank environmental guidelines

(environmental guidelines contained in the Pollution prevention and Abatement Handbook),

iii) Performance of the plant with respect to resource efficiency, iv) Evidence of any other critical issues and risks, and v) Adequacy of the institutional capacity of the plant in managing environmental issues.

5. The due diligence summary is provided in Table 10.3. Based on this, a detailed scope of work has been prepared for conduct of EADD. Currently HPGCL is in the process of procuring the EADD consultants.

11

2

Tab

le 1

0.1:

Key

Fin

ding

s of

EA

DD

Rep

ort a

nd S

umm

ary

of E

MA

P f

or K

orad

i Pla

nt (

KT

PS)

E

nvir

onm

enta

l Aud

it

Par

amet

er

Key

Fin

ding

s an

d Is

sues

P

ropo

sed

Man

agem

ent M

easu

res

and

Per

form

ance

Ind

icat

ors

Air

Pol

lutio

n �

The

pla

nt p

osse

sses

the

“Air

Con

sent

” to

ope

rate

. The

pla

nt

com

plie

s w

ith m

ost o

f th

e re

gula

tory

req

uire

men

ts in

term

s of

ap

plic

able

env

iron

men

tal s

tand

ards

and

spe

cifi

c co

nditi

ons

of th

e co

nsen

t, ex

cept

in r

espe

ct le

vel o

f Pa

rtic

ulat

e em

issi

ons

from

U

nits

– 5

, 6, a

nd 7

. The

em

issi

ons

from

Uni

t 7 a

re s

igni

fica

ntly

hi

gher

than

Ind

ian

Nat

iona

l Am

bien

t Air

Qua

lity

Stan

dard

s (N

AA

QS)

as

wel

l as

PPA

H g

uide

lines

�

The

cur

rent

PM

em

issi

on le

vel o

f U

nit-

6, m

onito

red

as p

art o

f au

dit i

s ab

out 1

80 m

g/N

m3

exce

edin

g N

AA

QS

of 1

50 m

g/N

m3.

PP

AH

req

uire

s th

e re

habi

litat

ion

proj

ects

to ta

rget

to a

chie

ve 5

0 m

g/N

m3

of p

artic

ulat

e em

issi

ons,

alth

ough

the

requ

irem

ent v

arie

s fr

om 5

0 to

150

mg/

Nm

3 de

pend

ing

on a

ge o

f th

e pl

ant.

Uni

t-6

is

an o

ld p

lan

whi

ch is

in o

pera

tion

over

15

year

s, f

allin

g in

to r

are

case

s.

The

exi

stin

g ai

r po

llutio

n co

ntro

l mec

hani

sm o

f co

mbi

natio

n of

E

SPs

and

Bag

Hou

ses

hind

ers

the

pollu

tion

cont

rol d

ue to

op

erat

ion

and

mai

nten

ance

rel

ated

issu

es. T

his

arra

ngem

ent i

s pr

opos

ed to

be

switc

hed

over

to E

SPs

and

the

viab

ility

of

the

sam

e is

cur

rent

ly b

eing

ass

esse

d as

par

t of

R&

M d

esig

ns f

or U

nit-

6. T

he

indi

cato

rs to

ref

lect

com

plia

nce

with

air

em

issi

on s

tand

ards

sha

ll in

clud

e:

�

As

Uni

t-6

is a

n ol

d pl

ant,

part

icul

ate

cont

rol s

yste

ms

for

Uni

t-6

shou

ld b

e ai

med

to a

chie

ve 1

00 m

g/N

m3

of P

M e

mis

sion

s an

d sh

all n

ot e

xcee

d 15

0 m

g/N

m3.

SO

2, a

nd N

o x s

hall

com

ply

with

NA

AQ

S an

d co

nsen

t con

ditio

ns o

f M

PCB

. �

For

the

rest

of

the

units

, KT

PS w

ill c

ompl

y w

ith N

AA

QS,

ad

optin

g pr

ogre

ssiv

e em

issi

on r

educ

tions

ove

r th

e pr

ojec

t im

plem

enta

tion

peri

od.

Fly

Ash

�

Cur

rent

ly th

e as

h is

dis

char

ged

in to

the

cons

truc

ted

ash

pond

in

the

slur

ry f

orm

. The

ash

pon

d is

man

aged

eff

ectiv

ely

with

no

resi

dual

com

mun

ity o

r en

viro

nmen

t rel

ated

issu

es.

The

cur

rent

co

rpor

ate

polic

y ha

s co

mpr

ehen

sive

com

pens

atio

n pr

ovis

ions

for

ad

dres

sing

agr

icul

tura

l los

s in

cas

e of

acc

iden

tal s

lurr

y sp

ills

from

pi

pelin

es

�

The

cur

rent

leve

l of

fly

ash

utili

zatio

n is

ver

y lim

ited.

�

KT

PS is

cur

rent

ly in

the

proc

ess

of w

orki

ng o

ut s

peci

fic

arra

ngem

ents

with

the

cem

ent p

lant

s an

d co

nstr

uctio

n in

dust

ries

. for

util

izin

g th

e fl

yash

. Arr

ange

men

ts f

or d

ry a

sh

colle

ctio

n sy

stem

are

cur

rent

ly u

nder

adv

ance

d st

age

of

cons

ider

atio

n.

Wat

er

Pollu

tion

�

The

pla

nt u

ses

two

capt

ive

pond

s fo

r th

e re

quir

emen

t of

mai

ntai

ning

the

cool

ing

wat

er te

mpe

ratu

re. T

he c

oolin

g w

ater

is

dist

ribu

ted

in tw

o la

rge

pond

s th

roug

h lo

ng o

pen

chan

nels

for

na

tura

l coo

ling.

Wat

er f

rom

thes

e po

nds

is a

gain

use

d fo

r co

olin

g pu

rpos

es. T

here

is n

o ne

t out

flow

of

cool

ing

wat

er to

wat

er

bodi

es, w

hich

are

ext

erna

l to

the

plan

t.

�

Nec

essa

ry E

TP

and

STP

are

in p

lace

to tr

eat r

espe

ctiv

e tr

ade

effl

uent

s an

d se

wag

e fr

om th

e pl

ant.

�

The

wat

er e

fflu

ent d

isch

arge

s fr

om a

sh p

ond

mee

ts th

e di

scha

rge

stan

dard

s. P

art o

f th

e as

h po

nd d

isch

arge

s is

cur

rent

ly r

ecyc

led

in

the

syst

em.

�

The

inte

rmitt

ent a

sh s

lurr

y ov

erfl

ows

and

CH

P fl

oor

was

hing

s ar

e cu

rren

tly d

isch

arge

d in

to th

e ne

arby

nat

ural

str

eam

with

out

trea

tmen

t. T

his

is le

adin

g to

wat

er q

ualit

y vi

olat

ions

�

Inst

alla

tion

of n

eces

sary

met

erin

g eq

uipm

ent f

or e

stab

lishi

ng

wat

er m

ass

bala

nce

is e

ssen

tial t

o id

entif

y op

port

uniti

es to

m

inim

ize

loss

es a

s w

ell a

s to

rat

iona

lize

wat

er c

ess.

The

fin

al

audi

t out

put i

nclu

des

inve

stm

ent r

equi

rem

ents

for

im

plem

enta

tion.

Thi

s m

easu

re w

ill b

e im

plem

ente

d by

KT

PS.

�

Wat

er c

onsu

mpt

ion

in th

e pl

ant c

an f

urth

er b

e re

duce

d by

im

prov

ing

the

recy

clin

g sy

stem

to r

ecyc

le a

dditi

onal

ove

rflo

w

from

the

ash

pond

, als

o by

str

ictly

mon

itori

ng a

nd r

educ

ing

the

amou

nt o

f w

ater

in th

e as

h sl

urry

sys

tem

. Spe

cifi

catio

ns

for

this

mea

sure

are

cur

rent

ly b

eing

con

side

red

as p

art o

f de

sign

eng

inee

ring

�

Mea

sure

s to

inte

grat

e th

e in

term

itten

t dis

char

ges

in to

exi

stin

g E

TP

or a

dditi

onal

ET

P ar

e be

ing

cons

ider

ed a

s pa

rt o

f de

sign

st

udie

s.

11

3

Env

iron

men

tal A

udit

P

aram

eter

Key

Fin

ding

s an

d Is

sues

P

ropo

sed

Man

agem

ent M

easu

res

and

Per

form

ance

Ind

icat

ors

�

The

per

form

ance

indi

cato

rs w

ill in

clud

e:

�

Com

plia

nce

with

was

tew

ater

dis

char

ge s

tand

ards

stip

ulat

ed

thro

ugh

MPC

B c

onse

nt c

ondi

tions

�

Impr

oved

wat

er r

ecyc

ling

esta

blis

hed

thro

ugh

corr

ect w

ater

ba

lanc

e by

inst

allin

g m

eter

s as

per

EA

DD

rec

omm

enda

tions

. O

ccup

atio

nal

Hea

lth,

Safe

ty a

nd

Em

erge

ncy

Man

agem

ent

• B

asic

hea

lth in

fras

truc

ture

exi

sts,

and

hea

lth s

ervi

ces

are

prov

ided

to

the

wor

kers

, •

No

spec

ific

impo

rtan

ce is

atta

ched

to th

e oc

cupa

tiona

l hea

lth

issu

es, a

nd a

s su

ch n

o sp

ecif

ic h

ealth

che

ck u

ps a

re d

one

for

occu

patio

nal h

ealth

con

cern

s.

• E

HS

man

agem

ent s

yste

m h

as b

een

prop

osed

as

part

of

the

audi

t rec

omm

enda

tions

. The

se m

easu

res

incl

ude:

acc

iden

t re

port

ing

prot

ocol

s, tr

aini

ng a

nd c

apac

ity b

uild

ing

at a

ll le

vels

, int

egra

tion

of E

HS

in to

the

curr

ent E

MS

syst

em a

nd

inst

itutio

nal c

hang

es f

or e

ffec

tive

enfo

rcem

ent o

f E

HS

mec

hani

sms.

In

stitu

tiona

l ca

paci

ty o

f th

e pl

ant i

n m

anag

ing

envi

ronm

enta

l iss

ues

The

pla

nt h

as a

new

inst

itutio

nal s

truc

ture

in p

lace

as

part

of

the

new

en

viro

nmen

t man

agem

ent s

yste

m (

ISO

140

01)

that

is u

nder

im

plem

enta

tion.

Whi

le th

e in

stitu

tiona

l str

uctu

res

are

reas

onab

le,

ther

e ar

e de

fici

enci

es in

rep

ortin

g m

echa

nism

s on

env

iron

men

tal a

nd

safe

ty m

anag

emen

t asp

ects

. It i

s al

so n

oted

that

ther

e ar

e no

sys

tem

s fo

r re

gula

r tr

aini

ng a

nd c

apac

ity b

uild

ing

to a

ddre

ss E

HS

rela

ted

issu

es.

• Si

ngle

str

eam

of

plan

t lev

el r

epor

ting

and

coor

dina

tion

of

EH

S re

late

d as

pect

s •

Tra

inin

g an

d sk

ill s

tren

gthe

ning

for

eff

ectiv

e m

anag

emen

t of

EH

S re

late

d is

sues

Oth

er C

riti

cal I

ssue

s A

ssoc

iate

d Fa

cilit

y: T

he m

inin

g fa

cilit

ies

supp

lyin

g co

al to

KT

PS, a

re n

ot u

nder

con

trol

of

KT

PS m

anag

emen

t. T

he c

oal s

uppl

y is

bas

ed o

n an

nual

ag

reem

ents

fro

m th

e po

ol o

f si

x m

ines

dep

endi

ng o

n av

aila

bilit

y. T

here

fore

env

iron

men

tal p

erfo

rman

ce o

f m

inin

g ac

tiviti

es is

bey

ond

the

scop

e of

KT

PS

man

agem

ent.

The

refo

re e

nvir

onm

enta

l per

form

ance

of

min

ing

faci

litie

s is

not

fac

tore

d in

the

audi

t.

Mer

cury

Pol

lutio

n: A

t pre

sent

, the

re a

re n

o sp

ecif

ic r

egul

atio

ns in

Ind

ia o

n m

ercu

ry e

mis

sion

s fr

om th

e co

al f

ired

pow

er p

lant

s. A

lso,

no

spec

ific

in

stan

ces/

evid

ence

s of

Hg

pollu

tion

have

bee

n re

port

ed a

roun

d th

e K

orad

i TPS

. How

ever

, the

re h

ave

been

incr

ease

d at

tent

ion

to H

g po

llutio

n in

the

coun

try

in g

ener

al, a

nd o

ff la

te, C

PCB

has

sta

rted

mon

itori

ng H

g po

llutio

n in

air

and

wat

er. T

here

fore

, mas

s ba

lanc

e st

udie

s of

mer

cury

con

side

ring

Hg

in c

oal,

air

emis

sion

s; a

nd f

ly-a

sh a

nd w

ater

sam

ples

fro

m a

sh p

ond

was

car

ried

out

. The

mer

cury

at s

ourc

e in

coa

l and

em

issi

ons

in m

ost c

ases

are

bel

ow U

SEPA

st

anda

rds.

C

omm

unity

Rel

ated

Iss

ues:

In

orde

r to

asc

erta

in a

ny c

omm

unity

rel

ated

issu

es, c

onsu

ltatio

ns w

ere

carr

ied

with

the

com

mun

ities

aro

und

the

plan

. The

co

nsul

tatio

ns c

oncl

uded

that

ther

e ar

e no

env

iron

men

tal i

ssue

s re

port

ed b

y th

e co

mm

unity

.

11

4

Tab

le 1

0.2:

Key

Fin

ding

of

EA

DD

Rep

ort a

nd S

umm

ary

of E

MA

P f

or B

ande

l Pla

nt (

BT

PS)

Env

iron

men

tal A

udit

P

aram

eter

K

ey F

indi

ngs

and

Issu

es

Pro

pose

d M

anag

emen

t Mea

sure

s an

d P

erfo

rman

ce

Indi

cato

rs

1. A

ir P

ollu

tion

�

Stac

k em

issi

ons

and

Am

bien

t ai

r qu

ality

is

with

the

pe

rmis

sibl

e N

atio

nal

stan

dard

s ex

cept

Pa

rtic

ulat

e em

issi

ons

in U

nit

1-4,

whi

ch e

xcee

d PP

AH

Gui

delin

es

as w

ell

as N

AA

QS.

PPA

H g

uide

lines

for

reh

abili

tatio

n pr

ojec

ts r

equi

res

to t

arge

t to

ach

ieve

50

mg/

Nm

3 of

pa

rtic

ulat

e em

issi

ons,

alth

ough

the

req

uire

men

t va

ries

fr

om 5

0 to

150

mg/

Nm

3 de

pend

ing

on t

he a

ge o

f th

e pl

ant a

nd s

cope

of

inte

rven

tions

. It w

as n

oted

that

Uni

t –

5 us

es A

mm

onia

dos

ing

whi

ch c

ould

mai

ntai

n th

e em

issi

ons

with

in

100-

150

mg/

Nm

3.

How

ever

, it

is

note

d th

at a

dequ

ate

haza

rdou

s ch

emic

al m

anag

emen

t m

easu

res

are

not i

n pl

ace

w.r

.t. u

se o

f am

mon

ia

The

exi

stin

g po

llutio

n co

ntro

l mec

hani

sm u

sing

am

mon

ia

dosi

ng p

ract

iced

in U

nit-

5 is

an

acce

ptab

le p

ract

ice

unde

r U

SEPA

sta

ndar

ds, t

houg

h co

untr

y st

anda

rds

are

not a

vaila

ble.

C

urre

ntly

am

mon

ia d

osin

g is

not

pro

hibi

ted.

The

refo

re, E

SP

serv

icin

g an

d am

mon

ia d

osin

g ha

s be

en r

ecom

men

ded

for

air

pollu

tion

cont

rol.

How

ever

, EH

S st

anda

rds

for

amm

onia

ha

ndlin

g to

be

follo

wed

. The

indi

cato

rs to

ref

lect

com

plia

nce

with

air

em

issi

on s

tand

ards

sha

ll in

clud

e:

�

Part

icul

ate

cont

rol s

yste

ms

for

Uni

t-6

shou

ld b

e ai

med

to

achi

eve

100

mg/

Nm

3 of

PM

em

issi

ons

and

shal

l not

ex

ceed

150

mg/

Nm

3. S

O2,

and

No x

sha

ll co

mpl

y w

ith

NA

AQ

S an

d co

nsen

t con

ditio

ns o

f M

PCB

. �

For

the

rest

of

the

units

, BT

PS w

ill c

ompl

y w

ith

NA

AQ

S, a

dopt

ing

prog

ress

ive

emis

sion

red

uctio

ns o

ver

the

proj

ect i

mpl

emen

tatio

n pe

riod

2.

Wat

er P

ollu

tion

�

Det

aile

d m

onito

ring

has

bee

n ca

rrie

d ou

t to

mon

itor

tem

pera

ture

of

the

cool

ing

wat

er d

isch

arge

s an

d th

e cu

rren

t di

scha

rges

are

com

plia

nt w

ith P

PAH

and

GO

I st

anda

rds.

The

se d

isch

arge

s w

ould

rem

ain

unaf

fect

ed

as t

he R

&M

act

iviti

es d

o no

t al

ter

the

cool

ing

wat

er

flow

rat

e an

d di

scha

rge

tem

pera

ture

s

�

Tre

ated

w

aste

wat

er

disc

harg

es

are

with

in

the

perm

issi

ble

stan

dard

s. H

owev

er,

the

disc

harg

es f

rom

no

n-po

int

sour

ces

from

CH

P an

d oi

l ha

ndlin

g ar

eas

caus

es

wat

er

pollu

tion,

w

hich

is

cu

rren

tly

not

mon

itore

d.

Aud

it m

onito

ring

of

th

ese

effl

uent

s re

veal

ed v

iola

tion

of w

ater

qua

lity

stan

dard

s

Wat

er c

olle

ctio

n ar

rang

emen

ts a

t oil

hand

ling

area

s an

d w

ater

tr

eatm

ent u

sing

equ

aliz

atio

n ta

nk, A

PI s

epar

ator

to b

e in

tegr

ated

as

part

of

the

tech

nica

l des

igns

B

TPS

to e

nsur

e W

aste

wat

er tr

eatm

ent f

or th

e ef

flue

nts

com

ing

from

can

teen

as

wel

l as

Prov

isio

n of

sto

rm w

ater

co

llect

ion

faci

litie

s at

CH

P an

d us

e of

exi

stin

g oi

l pon

d as

se

ttlin

g ta

nk p

rior

to d

ispo

sal

Impr

oved

wat

er r

ecyc

ling

esta

blis

hed

thro

ugh

corr

ect w

ater

ba

lanc

e by

inst

allin

g m

eter

s as

per

EA

DD

rec

omm

enda

tions

T

he p

erfo

rman

ce in

dica

tors

will

incl

ude:

•

Com

plia

nce

with

was

tew

ater

dis

char

ge s

tand

ards

st

ipul

ated

thro

ugh

WB

PCB

con

sent

con

ditio

ns in

clud

ing

utili

zatio

n of

ash

pon

d di

scha

rges

.

3. C

oal L

inka

ges

�

The

re a

re n

o en

viro

nmen

tal

conc

erns

em

ergi

ng f

rom

su

pply

of

coal

to

BT

PS o

r fr

om h

ealth

, sa

fety

and

en

viro

nmen

tal

conc

erns

at

the

coal

min

ing.

WB

PDC

L

uses

Ben

gal

EM

TA

coa

l m

ine

for

BT

PS t

o th

e tu

ne o

f 15

%. W

BPD

CL

has

26%

sta

ke in

EM

TA

and

hen

ce th

e pe

rfor

man

ce o

f th

e m

ine

is o

f re

leva

nce.

The

EM

TA

ope

ratio

ns a

re c

lear

ed b

y M

oEF

for

min

ing

and

curr

ently

the

WB

PCB

issu

es a

nnua

l con

sent

for

min

e op

erat

ion

on r

evie

w o

f co

mpl

ianc

e w

ith “

cons

ent t

o op

erat

e”.

Thi

s re

gula

tory

com

plia

nce

mec

hani

sm w

ould

ens

ure

that

en

viro

nmen

tal i

ssue

s ar

e ad

dres

sed.

11

5

4. F

ly A

sh U

tiliz

atio

n an

d M

anag

emen

t �

The

lev

el o

f as

h ut

iliza

tion

in B

TPS

is

foun

d to

be

(as

requ

ired

to

com

ply

with

GO

I no

tific

atio

n) s

atis

fact

ory.

B

TPS

has

com

mitt

ed n

ot t

o se

ek m

ore

land

for

ash

di

spos

al u

ntil

2021

. T

he r

esou

rces

and

inf

rast

ruct

ure

requ

ired

to m

aint

ain

the

curr

ent p

ace

of a

sh u

tiliz

atio

n is

be

ing

met

thro

ugh

curr

ent a

rran

gem

ents

�

BT

PS d

ispo

ses

part

of

ash

in t

he a

sh p

ond.

Cur

rent

ly

ther

e is

no

recy

clin

g m

echa

nism

to

use

disc

harg

es f

rom

th

e as

h po

nd

�

Furt

her,

as

part

of

the

inst

itutio

nal s

tren

gthe

ning

co

mpo

nent

WB

PDC

L w

ill e

stab

lish

corp

orat

e en

viro

nmen

t man

agem

ent p

ract

ices

, whi

ch w

ould

ena

ble

WB

PDC

L to

be

effe

ctiv

e in

add

ress

ing

envi

ronm

enta

l is

sues

of

all t

he f

acili

ties

that

it o

wns

or

has

cont

rolli

ng

stak

es.

�

Res

truc

turi

ng o

f A

sh p

ond

with

pro

visi

ons

for

wat

er

colle

ctio

n su

mp

and

recy

clin

g of

wat

er f

or b

ette

r ut

iliza

tion

of w

ater

res

ourc

es. T

his

mea

sure

will

be

impl

emen

ted

by B

TPS

as

part

of

over

all e

nvir

onm

enta

l im

prov

emen

ts

5. O

ccup

atio

nal h

ealth

&

safe

ty

�

Alth

ough

, B

TPS

has

the

bas

ic h

ealth

inf

rast

ruct

ure

in

plac

e, a

nd h

ealth

ser

vice

s ar

e pr

ovid

ed t

o th

e w

orke

rs,

no s

peci

fic

impo

rtan

ce i

s at

tach

ed t

o th

e oc

cupa

tiona

l he

alth

iss

ues.

No

spec

ific

hea

lth c

heck

ups

are

don

e fo

r oc

cupa

tiona

l hea

lth c

once

rns.

�

BT

PS d

oes

not

have

an

emer

genc

y m

anag

emen

t pl

an in

pl

ace,

whi

ch w

ould

be

deve

lope

d an

d im

plem

ente

d as

pa

rt o

f th

e pr

opos

ed R

ehab

ilita

tion

Proj

ect.

Cur

rent

ly

the

acci

dent

info

rmat

ion

is n

ot a

vaila

ble

�

As

part

of

R&

M im

plem

enta

tion,

BT

PS w

ill e

stab

lish

Occ

upat

iona

l Hea

lth a

nd S

afet

y M

anag

emen

t pro

cedu

res

and

impl

emen

t on

prio

rity

6. I

nstit

utio

nal C

apac

ity f

or

Env

. Man

agem

ent

�

The

cur

rent

inst

itutio

nal s

truc

ture

app

ears

insu

ffic

ient

to

resp

ond

to t

he e

nvir

onm

enta

l ne

eds

of t

he p

lant

. T

he

curr

ent e

nvir

onm

enta

l div

isio

n al

thou

gh q

uite

ene

rget

ic,

wou

ld n

eed

to b

e st

reng

then

ed b

oth

with

add

ition

al

reso

urce

s an

d au

thor

ity

to

plan

an

d im

plem

ent

an

inte

grat

ed e

nvir

onm

enta

l an

d oc

cupa

tiona

l he

alth

and

sa

fety

mat

ters

in th

e pl

ant

�

As

part

of

the

inst

itutio

nal s

tren

gthe

ning

com

pone

nt, i

t is

prop

osed

to e

stab

lish

an E

HS

cell

whi

ch w

ill c

oord

inat

e en

viro

nmen

t and

saf

ety

man

agem

ent a

spec

ts a

t the

pla

nt

leve

l

116

Table 10.3: Summary Findings of Preliminary Environmental Due Diligence for Panipat Thermal Power Station (PTPS)

Parameters of

Environmental Due Diligence

Key Findings and Observations

Compliance with applicable regulatory requirements related to environment

� The plant possesses MoEF clearance and only Water Consent. However, consent to operate under Air Act and storage of hazardous chemicals is still to be secured by PTPS.

� The plant also needs to comply with various conditions of water consent and MoEF clearance.

� The plant also (specially the Units 3 and 4 proposed for R&M) is not complying to the stack emission norms (about 295 to 729 mg/ Nm3 from the stacks connected the units 3 and 4 as against the permissible emission standards of 150 mg/ Nm3 of MoEF and 50 mg/ Nm3 of PPAH)

� The plant disposes the untreated effluents into the near by water body and some of the parameters (suspended solids and Oil & Grease) exceed the disposal standards significantly

� The plant is also implementing concerted efforts to utilize the fly ash. However, the resources and infrastructure required to maintain the current pace of ash utilization would need to be assessed as part of the proposed Rehabilitation Project so as to ensure compliance with the fly ash utilization notification

Conformance with applicable World Bank environmental guidelines (Pollution prevention and Abatement Handbook)

� Based on the available data, the SPM levels of the plant seem to be exceeding the PPAH guidelines both the stack emissions and ambient air

� PPAH requires the rehabilitation projects to target to achieve 50 mg/Nm3 of particulate emissions, although the requirement varies from 50 to 150 mg/Nm3 depending on the age of the plant and proposed interventions. Since the proposed unit for R&M is over two decades old, it is proposed to aim the emission control interventions to achieve 100 mg/Nm3, but not to exceed 150 mg/Nm3.

� From the available reports, it is noted that the process and domestic wastewater discharges do not comply with HSPCB consent conditions as well as PPAH guide lines. Yet times the discharges exceed the standards significantly. The actual level of non-compliance need to be further ascertained through monitoring as part of unit level and plant level environmental audits

Resource Efficiency and Resource Demand

• The procedures followed to calculate Unit Heat Rate, one of the key indicators of resource efficiency from fuel consumption perspective, need to be studied in detail, so as to ensure that the methodology accurately estimates the heat rate of PTPS.

• Long term coal linkage for the plant is already in place, and there does not appear to be any significant issues with respect to availability of coal for continual operation of the plant. Since the quality of coal from the allocated mines has changed significantly over the years, it would be very important to take the present quality of available coal into consideration while designing rehabilitation measures in order to achieve the optimum efficiency.

• There is no water balance available for PTPS to assess the water consumption pattern and explore the opportunities for water conservation.

117

Parameters of Environmental Due

Diligence

Key Findings and Observations

The same needs to be studied during the Environmental Audit and appropriate measures need to be implemented as part of the R&M project.

Occupational Health, Safety and Emergency Management

• Although, PTPS has the basic health infrastructure in place, and health services are provided to the workers, no specific importance is attached to the occupational health issues. No specific health check ups are done for occupational health concerns.

• The emergency management plan of PTPS need to be updated and implemented reflecting the latest changes in the plant operations.

Other critical issues and risks

Associated Facility: The mining facilities supplying coal to PTPS, as an associated/linked facility is not under control of PTPS management, therefore, difficult to manage in terms of environmental performance. There are no known environmental concerns emerging from supply of coal to PTPS or from health, safety and environmental concerns at the coal mining. Therefore, the due diligence recommends the EA to focus on developing and enhancing corporate environment management practices of HPGCL, which would enable HPGCL to be effective in addressing environmental issues of all the facilities that it owns or has controlling stakes. Mercury Pollution: At present, there are no specific regulations in India on mercury emissions from the coal fired power plants. Also, no specific instances/evidences of Hg pollution have been reported around PTPS. However, there have been increased attention to Hg pollution in the country in general, and of late, CPCB has started monitoring Hg pollution in air and water. Therefore, PTPS should include mercury pollution assessment as part of the environmental assessment of the proposed rehabilitation project. Potential Environmental Liability Issues: PTPS is fighting four legal cases concerning health impacts on the people of village Khukrana (village near by PTPS). With both air and water quality exceeding the permissible standards and discharge of untreated effluent in to the near by water body (Untla Nala), all the community concerns with regard to environmental pollution need to be resolved with high priority.

Institutional capacity of the plant in managing environmental issues

With no separate environmental unit, the current institutional structure of PTPS is insufficient to respond to the environmental needs of the plant. Appropriate environmental capacity need to be developed both with adequate resources and authority to plan and implement an integrated environmental and occupational health and safety matters in the plant.

118

B. Social Safeguard Issues 6. Rapid Social Assessment (RSA): OP 4.12 (involuntary resettlement) does not apply here as there is no land acquisition and displacement. However, RSA was carried out in both the power stations (i) to document adverse impacts of the thermal power station’s (TPS) operations on agricultural fields (Koradi) and dense habitations (Bandel); (ii) to identify any existing communication channel between the power station and community; and (iii) to assess the needs of the community and facilities that power station has extended, which also provided input for preparing Corporate Social Responsibility (CSR) policy. Therefore, as part of project preparation, rapid social appraisal of the sub-projects was carried out focusing on the above mentioned issues. The appraisal not only provided the baseline information, but helped in understanding the outstanding issues with the community living in the periphery of the power stations. 7. Though the RSA identified tribal households, none of them were found to have any distinct identities and cultures. All the tribal households have assimilated themselves with the local non tribal community and hence OP 4.10 is not triggered. 8. The RSA results: The results of RSA which covered 315 households in Bandel TPS and 300 in Koradi TPS clearly brought out the adverse impacts on the health of the community members due to power station’s operations. Some of the major health issues highlighted by the community include respiratory problems; skin diseases; nasal and eye irritation; hearing impairment and stomach related diseases. Crop loss due to bursting of fly ash pipeline in Koradi has also been reported. However, KTPS has a mechanism in place. In case any cultivator complains of crop damage, office of Executive Engineer - Civil (II) of KTPS forwards the complaint letter to concerned Tehasildar. The Tehasildar conducts joint survey with KTPS to determine the extent of crop damage and compensation amount. KTPS on receipt of report from the office of Tehasildar, makes the payment through cheque and copy of the cheque is also send to the office of Tehasildar. 9. On the other hand both the power stations have generated economic opportunities for the community apart from direct employment given to the project affected families. The schools, medical aid centre, post office and banks within the TPS colony are also accessible to the habitations nearby. TPS also provides for drinking water and water is drawn from the fly ash pond for irrigation purpose especially during by the dry season by the agriculture community. 10. Court Cases: In early and late 70’s, Koradi TPS acquired approximately 900 acres of land and thereby affected 1470 families. About 253 court cases were filed, of which 207 are still pending in district civil court of Nagpur. Protests were also launched resulting in two years delay in construction of ash bund. Though KTPS has Grievance Settlement Mechanism, no PAP approached GSM. The GSM is headed by the District Collector and has representation of PAPs. The primary reason for court cases, as explained by Executive Engineer Civil Division – III, was lower compensation rate (approximately 1.5 times less than prevailing market rate at the time of acquisition). The PAPs those who have filed court case, however accepted their compensation amount “under protest”. KTPS informed that as and when court has enhanced the compensation amount, it has been paid by KTPS. 11. In 1961-62, Bandel TPS acquired 299 acres of land from one person. However there were 12 share croppers those who were also affected. No court case was filed by project affected persons (PAPs).

119

12. Employment and Resettlement Colony: Employment for those losing land and shelter was provided by both the power stations. KTPS provided employment to 1200 affected families out of 1470 affected. BTPS also provided employment to one member of the affected family. The displaced families of KTPS were resettled in New Koradi village about 2 km from the affected site (existing power station). KTPS provided free of cost housing plots and house construction allowance. The colony has roads, street lights, drainage and power stations also provides them treated piped water supply. 13. New Land Acquisition: As per the RSA and discussion with the concerned officials, there will be no fresh land acquisition as both the existing power stations have adequate land for new facilities. BTPS has in fact leased out part of its land to surrounding villages for cultivation.

14. Social Responsibility: Although WBPDCL and MSPGCL do not have any Corporate Social Responsibility (CSR) policy; both the power stations have extended facilities to the immediate surrounding habitations. The schools, hospitals, cooperatives, bank, post office, and other such facilities are accessible to villagers around the power stations. Both the power stations have generated direct and indirect employment and engage contract labourers in operation and maintenance of the power station. Considering the fact that both the power stations have informally carried out community welfare activities, Corporate Social Responsibility policy was prepared to mitigate some of the adverse social impacts identified by the RSA. The implementation of CSR would also (i) enhanced reputation and image of the entities; (ii) open communication channel and would develop good relationship with the community; and (iii) smooth execution of the project and later operations. 15. The CSR policy of both Koradi and Bandel Thermal Power Stations captures the existing facilities extended by the power stations. It details out the visions and objective of each entity towards social responsibility, activities to be carried out and institutional mechanism for implementation of CSR. The policies have been endorsed by both MSPGCL and WBPDCL. 16. Panipat Thermal Power Station: The community perception on health impacts of PTPS operations is a very critical aspect to be addressed in the project. A detailed assessment of health impacts will be carried out, so that appropriate strategies to mitigate the impacts are formulated. Corporate Social Responsibility Policy will also be prepared. All such efforts will ensure that the community is fully convinced about the efforts of PTPS and the proposed R&M initiatives with The World Bank’s support are implemented successfully. 17. Although the client has agreed to undertake a Rapid Social Assessment (RSA) for Panipat Thermal Power station, it is yet to start. The terms of reference for RSA, communication strategy and CSR has been shared with the client. However, in community consultations during site visits and from the recent press reports, health impacts due to air and water pollution in the nearby village Kukrana have been reported. It was also found that some villagers in Ror community have migrated to Karnal due to acute pollution levels caused by PTPS operation. As reported by the press, the villagers have formed a “Gaon Sudhar Samiti” (Village Improvement Committee) to fight a legal battle in the Punjab and Haryana High Court. PTPS has reported that there were four cases in the High Court of Punjab & Haryana with regards to the impacts of health and loss of agriculture productivity. Court has ruled in favour of the community in three cases and have rejected one case filed against PTPS. Legal review of court cases will be carried out in order to (i) have an opinion on the likely outcome of the legal challenges based on precedence established in such cases elsewhere in

120

India; (ii) assess the legal implications of the cases and the likelihood that they will adversely affect the Bank-supported project; and (iii) assess the potential impact of the court cases on the reputation of the Bank. The process of hiring a consultant for legal review is underway.

121

Annex 11: Project Preparation and Supervision

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT Planned Actual PCN review 06/27/2006 06/27/2006 Initial PID to PIC 07/20/2006 07/04/2006 Initial ISDS to PIC 07/20/2006 07/04/2006 Appraisal 11/18/2008 11/24/2008 Negotiations 02/17/2009 02/23/2009 Board/RVP approval 06/11/2009 Planned date of effectiveness 12/15/2009 Planned date of mid-term review Planned closing date 06/30/2014 Key institutions responsible for preparation of the project:

i. West Bengal Power Development Corporation Limited (WBPDCL) ii. Maharashtra State Power Generation Corporation Limited (MSPGCL)

iii. Haryana Power Generation Corporation Limited (HPGCL) iv. Central Electricity Authority, Ministry of Power, Government of India

Bank staff and consultants who worked on the project included: Name Title Unit Mikul Bhatia Team Leader / Energy Specialist SASDE Kwawu Mensan Gaba Co-Team Leader / Lead Energy Specialist SASDE A.S. Harinath Environment Specialist SASDI A.Sita Ramakrishna Environment Specialist SASDI Boonsri Prasertwaree Kim Program Assistant SASDE Chandrasekeren Subramaniam Sr. Power Engineer SASDE Debabrata Chakraborti Sr. Procurement Specialist SARPS Dirk Pauschert Operation Analyst ETWWP Don Bennett Consultant – Power Plant O&M Harriette Peters Program Assistant SASDO Julia Fraser Sr. Financial Analyst SASDE Mani Khurana Operation Analyst SASDE Manoj Jain Sr. Financial Management Specialist SARFM Masaki Takahashi Sr. Power Engineer ETWEN Mustafa Zakir Hussain Infrastructure Finance Specialist FEU Naval Karrir Sr. Carbon Finance Specialist SASDI Parthapriya Ghosh Social Specialist SASDI Ramola Bhuyan ET Consultant – Financial Management SARFM Ravinder Singh Sohal Consultant – Technical Expert Rishi Kumar Jain Consultant – Technical Expert SASDE Robert Richwine Consultant – Power Plant O&M ETWEN Saurabh Yadav ET Consultant – Energy Specialist SASDE Sona Thakur Communications Officer SAREX Stratos Tavoulareas Consultant – Technical Expert Sunil Kumar Khosla Sr. Energy Specialist SASDE Yash Gupta ET Consultant - Procurement SARPS

122

Bank funds expended to date on project preparation:

1. Bank resources: $434,000 2. Trust funds: $222,000 3. Total: $656,000

Estimated Approval and Supervision costs:

1. Remaining costs to approval: $45,000 2. Estimated annual supervision cost: $300,000

123

Annex 12: Documents in the Project File

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

1. Project Concept Note 2. Integrated Safeguards Data Sheet 3. Project Information Document 4. Risk Identification Worksheet 5. Governance and Accountability Plan 6. Procurement Plans for HPGCL, MSPGCL, WBPDCL, and CEA 7. Rapid Social Assessment and Environmental Audit Due Diligence Reports for Bandel

and Koradi 8. Project Implementation Plans for MSPGCL and WBPDCL 9. Operations manual for CEA 10. Policy note to the Government of India: Improving regulatory incentives to invest in

rehabilitation of coal-fired generating plants in India. June 2008. 11. Regulatory study to encourage energy efficiency through investments in rehabilitation of

coal fired generation plant in India, IPA Energy + Water Consulting and KPMG India, August 2008.

12. Study of O&M Practices at Koradi and Bandel, PWC/STEAG, October 2008 (draft) 13. Project Design Report (also called Detailed project Report) for Renovation and

Modernization of 210 MW, Unit #5, Bandel Thermal Power Station, prepared by Evonik Energy Services India Pvt. Ltd, July 2008

14. Project Design Report for Design, Renovation & Modernization Scheme to Improve the Energy Efficiency, Upgrade Capacity and Enhance Residual Life of Koradi Thermal Power Station Unit-6 (210 MW), Maharashtra State Power Generation Company, prepared by Evonik Energy Services India Pvt. Ltd, October 2006

15. File Note on Calculation of Emission Reductions

124

Annex 13: Statement of Loans and Credits

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

Original Amount in US$ Millions

Difference between expected and actual

disbursements

Project ID FY Purpose IBRD IDA SF GEF Cancel. Undisb. Orig. Frm. Rev’d

P093478 2009 Orissa Rural Livelihoods Project 0.00 82.40 0.00 0.00 0.00 72.67 -3.09 0.00

P096023 2009 Orissa State Roads 250.00 0.00 0.00 0.00 0.00 250.00 0.00 0.00

P094360 2009 National VBD Control&Polio Eradication 0.00 521.00 0.00 0.00 0.00 479.73 8.33 0.00

P100735 2009 Orissa Community Tank Management Project

56.00 56.00 0.00 0.00 0.00 103.80 -3.17 0.00

P101653 2008 Power System Development Project IV 1,000.00 0.00 0.00 0.00 0.00 779.29 80.62 0.00

P102547 2008 Elementary Education (SSA II) 0.00 600.00 0.00 0.00 0.00 354.45 2.47 0.00

P102737 2008 Bihar DPL 150.00 75.00 0.00 0.00 0.00 112.02 111.10 0.00

P095114 2008 Rampur Hydropower Project 400.00 0.00 0.00 0.00 0.00 334.00 11.67 0.00

P078538 2007 Third National HIV/AIDS Control Project

0.00 250.00 0.00 0.00 0.00 188.32 96.73 0.00

P078539 2007 TB II 0.00 170.00 0.00 0.00 0.00 112.22 -17.89 0.00

P090768 2007 TN IAM WARM 335.00 150.00 0.00 0.00 0.00 425.10 90.36 0.00

P090764 2007 Bihar Rural Livelihoods Project 0.00 63.00 0.00 0.00 0.00 58.09 3.06 0.00

P090592 2007 Punjab Rural Water Supply & Sanitation 0.00 154.00 0.00 0.00 0.00 139.71 77.16 0.00

P090585 2007 Punjab State Roads Project 250.00 0.00 0.00 0.00 0.00 143.81 -20.39 0.00

P083187 2007 Uttaranchal RWSS 0.00 120.00 0.00 0.00 0.00 108.28 43.00 0.00

P075174 2007 AP DPL III 150.00 75.00 0.00 0.00 0.00 76.02 -77.33 0.00

P075060 2007 RCH II 0.00 360.00 0.00 0.00 0.00 218.20 51.30 0.00

P096019 2007 HP State Roads Project 220.00 0.00 0.00 0.00 0.00 195.63 20.25 0.00

P102768 2007 Stren India's Rural Credit Coops 300.00 300.00 0.00 0.00 0.00 285.19 91.92 0.00

P099047 2007 Vocational Training India 0.00 280.00 0.00 0.00 0.00 210.43 -8.31 0.00

P100789 2007 AP Community Tank Management Project

94.50 94.50 0.00 0.00 0.00 175.06 16.21 0.00

P071160 2007 Karnataka Health Systems 0.00 141.83 0.00 0.00 0.00 81.60 -18.28 0.00

P086414 2006 Power System Development Project III 400.00 0.00 0.00 0.00 0.00 34.40 -135.60 0.00

P092735 2006 NAIP 0.00 200.00 0.00 0.00 0.00 173.67 55.57 0.00

P093720 2006 Mid-Himalayan (HP) Watersheds 0.00 60.00 0.00 0.00 0.00 34.59 4.10 0.00

P078832 2006 Karnataka Panchayats Strengthening Proj 0.00 120.00 0.00 0.00 0.00 79.92 -34.68 0.00

P079675 2006 Karn Municipal Reform 216.00 0.00 0.00 0.00 0.00 176.47 64.14 0.00

P079708 2006 TN Empwr & Pov Reduction 0.00 120.00 0.00 0.00 0.00 83.21 23.58 0.00

P083780 2006 TN Urban III 300.00 0.00 0.00 0.00 0.00 201.81 97.56 0.00

P086518 2005 SME Financing & Development 520.00 0.00 0.00 0.00 0.00 400.00 0.00 0.00

P073370 2005 Madhya Pradesh Water Sector Restructurin

394.02 0.00 0.00 0.00 0.00 309.43 206.32 0.00

P073651 2005 DISEASE SURVEILLANCE 0.00 68.00 0.00 0.00 0.00 51.56 43.16 0.00

P084632 2005 Hydrology II 104.98 0.00 0.00 0.00 0.00 87.19 72.18 40.22

P084792 2005 Assam Agric Competitiveness 0.00 154.00 0.00 0.00 0.00 91.64 67.12 0.00

P084790 2005 MAHAR WSIP 325.00 0.00 0.00 0.00 0.00 246.64 130.97 0.00

P075058 2005 TN HEALTH SYSTEMS 0.00 110.83 0.00 0.00 20.06 45.52 51.83 28.94

P077977 2005 Rural Roads Project 99.50 300.00 0.00 0.00 0.00 127.07 71.46 0.00

125

P077856 2005 Lucknow-Muzaffarpur National Highway 620.00 0.00 0.00 0.00 0.00 254.10 70.76 0.00

P094513 2005 India Tsunami ERC 0.00 465.00 0.00 0.00 0.00 379.85 388.68 0.00

P073776 2004 ALLAHABAD BYPASS 240.00 0.00 0.00 0.00 0.00 32.77 29.57 0.00

P050655 2004 RAJASTHAN HEALTH SYSTEMS DEVELOPMENT

0.00 89.00 0.00 0.00 0.00 38.80 32.22 0.00

P078550 2004 Uttar Wtrshed 0.00 69.62 0.00 0.00 0.00 37.75 3.36 0.00

P082510 2004 Karnataka UWS Improvement Project 39.50 0.00 0.00 0.00 0.00 7.58 7.58 0.73

P071272 2003 AP RURAL POV REDUCTION 0.00 215.03 0.00 0.00 0.00 26.19 -58.48 0.00

P067606 2003 UP ROADS 488.00 0.00 0.00 0.00 0.00 105.29 105.29 0.00

P050649 2003 TN ROADS 348.00 0.00 0.00 0.00 0.00 80.14 76.81 0.00

P073094 2003 AP Comm Forest Mgmt 0.00 108.00 0.00 0.00 0.00 19.89 0.16 0.00

P076467 2003 Chatt DRPP 0.00 112.56 0.00 0.00 20.06 50.93 58.85 0.00

P072539 2002 KERALA STATE TRANSPORT 255.00 0.00 0.00 0.00 0.00 93.72 93.72 0.00

P071033 2002 KARN Tank Mgmt 32.00 130.90 0.00 0.00 25.07 109.06 51.30 -5.91

P069889 2002 MIZORAM ROADS 0.00 78.00 0.00 0.00 0.00 15.99 -13.12 0.00

P040610 2002 RAJ WSRP 0.00 140.00 0.00 0.00 25.84 42.12 30.90 0.00

P050668 2002 MUMBAI URBAN TRANSPORT PROJECT

463.00 79.00 0.00 0.00 0.00 261.82 249.72 87.89

P050653 2002 KARNATAKA RWSS II 0.00 151.60 0.00 0.00 15.04 16.98 5.17 0.00

P050647 2002 UP WSRP 0.00 149.20 0.00 0.00 40.11 71.90 86.03 0.00

Total: 8,050.50 6,413.47 0.00 0.00 146.18 8,691.62 2,491.95 151.87

INDIA STATEMENT OF IFC’s

Held and Disbursed Portfolio In Millions of US Dollars

Committed Disbursed

IFC IFC

FY Approval Company Loan Equity Quasi Partic. Loan Equity Quasi Partic.

2005 ADPCL 39.50 7.00 0.00 0.00 0.00 0.00 0.00 0.00

2006 AHEL 0.00 5.08 0.00 0.00 0.00 5.08 0.00 0.00

2005 AP Paper Mills 35.00 5.00 0.00 0.00 25.00 5.00 0.00 0.00

2005 APIDC Biotech 0.00 4.00 0.00 0.00 0.00 2.01 0.00 0.00

2002 ATL 13.81 0.00 0.00 9.36 13.81 0.00 0.00 9.36

2003 ATL 1.00 0.00 0.00 0.00 0.68 0.00 0.00 0.00

2005 ATL 9.39 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2006 Atul Ltd 16.77 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2003 BHF 10.30 0.00 10.30 0.00 10.30 0.00 10.30 0.00

2004 BILT 0.00 0.00 15.00 0.00 0.00 0.00 15.00 0.00

2001 BTVL 0.43 3.98 0.00 0.00 0.43 3.98 0.00 0.00

2003 Balrampur 10.52 0.00 0.00 0.00 10.52 0.00 0.00 0.00

2001 Basix Ltd. 0.00 0.98 0.00 0.00 0.00 0.98 0.00 0.00

2005 Bharat Biotech 0.00 0.00 4.50 0.00 0.00 0.00 3.30 0.00

1984 Bihar Sponge 5.70 0.00 0.00 0.00 5.70 0.00 0.00 0.00

2003 CCIL 1.50 0.00 0.00 0.00 0.59 0.00 0.00 0.00

2006 CCIL 7.00 2.00 0.00 12.40 7.00 2.00 0.00 12.40

126

1990 CESC 4.61 0.00 0.00 0.00 4.61 0.00 0.00 0.00

1992 CESC 6.55 0.00 0.00 14.59 6.55 0.00 0.00 14.59

2004 CGL 14.38 0.00 0.00 0.00 7.38 0.00 0.00 0.00

2004 CMScomputers 0.00 10.00 2.50 0.00 0.00 0.00 0.00 0.00

2002 COSMO 2.50 0.00 0.00 0.00 2.50 0.00 0.00 0.00

2005 COSMO 0.00 3.73 0.00 0.00 0.00 3.73 0.00 0.00

2006 Chennai Water 24.78 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2003 DQEL 0.00 1.50 1.50 0.00 0.00 1.50 1.50 0.00

2005 DSCL 30.00 0.00 0.00 0.00 30.00 0.00 0.00 0.00

2006 DSCL 15.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2005 Dabur 0.00 14.09 0.00 0.00 0.00 14.09 0.00 0.00

2003 Dewan 8.68 0.00 0.00 0.00 8.68 0.00 0.00 0.00

2006 Federal Bank 0.00 28.06 0.00 0.00 0.00 23.99 0.00 0.00

2001 GTF Fact 0.00 1.20 0.00 0.00 0.00 1.20 0.00 0.00

2006 GTF Fact 0.00 0.00 0.99 0.00 0.00 0.00 0.99 0.00

1994 GVK 0.00 4.83 0.00 0.00 0.00 4.83 0.00 0.00

2003 HDFC 100.00 0.00 0.00 100.00 100.00 0.00 0.00 100.00

1998 IAAF 0.00 0.47 0.00 0.00 0.00 0.30 0.00 0.00

2006 IAL 0.00 9.79 0.00 0.00 0.00 7.70 0.00 0.00

1998 IDFC 0.00 10.82 0.00 0.00 0.00 10.82 0.00 0.00

2005 IDFC 50.00 0.00 0.00 100.00 50.00 0.00 0.00 100.00

IHDC 6.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2006 IHDC 7.90 0.00 0.00 0.00 0.00 0.00 0.00 0.00

2006 Indecomm 0.00 2.57 0.00 0.00 0.00 2.57 0.00 0.00

1996 India Direct Fnd 0.00 1.10 0.00 0.00 0.00 0.66 0.00 0.00

2001 Indian Seamless 6.00 0.00 0.00 0.00 6.00 0.00 0.00 0.00

2006 JK Paper 15.00 7.62 0.00 0.00 0.00 7.38 0.00 0.00

2005 K Mahindra INDIA 22.00 0.00 0.00 0.00 22.00 0.00 0.00 0.00

2005 KPIT 11.00 2.50 0.00 0.00 8.00 2.50 0.00 0.00

2003 L&T 50.00 0.00 0.00 0.00 50.00 0.00 0.00 0.00

2006 LGB 14.21 4.82 0.00 0.00 0.00 4.82 0.00 0.00

2006 Lok Fund 0.00 2.00 0.00 0.00 0.00 0.00 0.00 0.00

2002 MMFSL 7.89 0.00 7.51 0.00 7.89 0.00 7.51 0.00

2003 MSSL 0.00 2.29 0.00 0.00 0.00 2.20 0.00 0.00

2001 MahInfra 0.00 10.00 0.00 0.00 0.00 0.79 0.00 0.00

Montalvo 0.00 3.00 0.00 0.00 0.00 1.08 0.00 0.00

1996 Moser Baer 0.00 0.82 0.00 0.00 0.00 0.82 0.00 0.00

1999 Moser Baer 0.00 8.74 0.00 0.00 0.00 8.74 0.00 0.00

2000 Moser Baer 12.75 10.54 0.00 0.00 12.75 10.54 0.00 0.00

Nevis 0.00 4.00 0.00 0.00 0.00 4.00 0.00 0.00

2003 NewPath 0.00 9.31 0.00 0.00 0.00 8.31 0.00 0.00

2004 NewPath 0.00 2.79 0.00 0.00 0.00 2.49 0.00 0.00

2003 Niko Resources 24.44 0.00 0.00 0.00 24.44 0.00 0.00 0.00

2001 Orchid 0.00 0.73 0.00 0.00 0.00 0.73 0.00 0.00

1997 Owens Corning 5.92 0.00 0.00 0.00 5.92 0.00 0.00 0.00

2006 PSL Limited 15.00 4.74 0.00 0.00 0.00 4.54 0.00 0.00

2004 Powerlinks 72.98 0.00 0.00 0.00 64.16 0.00 0.00 0.00

2004 RAK India 20.00 0.00 0.00 0.00 20.00 0.00 0.00 0.00

1995 Rain Calcining 0.00 2.29 0.00 0.00 0.00 2.29 0.00 0.00

127

2004 Rain Calcining 10.00 0.00 0.00 0.00 10.00 0.00 0.00 0.00

2005 Ramky 3.74 10.28 0.00 0.00 0.00 0.00 0.00 0.00

2005 Ruchi Soya 0.00 9.27 0.00 0.00 0.00 6.77 0.00 0.00

2001 SBI 50.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

1997 SREI 3.21 0.00 0.00 0.00 3.21 0.00 0.00 0.00

2000 SREI 6.50 0.00 0.00 0.00 6.50 0.00 0.00 0.00

1995 Sara Fund 0.00 3.43 0.00 0.00 0.00 3.43 0.00 0.00

2004 SeaLion 4.40 0.00 0.00 0.00 4.40 0.00 0.00 0.00

2001 Spryance 0.00 1.86 0.00 0.00 0.00 1.86 0.00 0.00

2003 Spryance 0.00 0.93 0.00 0.00 0.00 0.93 0.00 0.00

2004 Sundaram Finance 42.93 0.00 0.00 0.00 42.93 0.00 0.00 0.00

2000 Sundaram Home 0.00 2.18 0.00 0.00 0.00 2.18 0.00 0.00

2002 Sundaram Home 6.71 0.00 0.00 0.00 6.71 0.00 0.00 0.00

1998 TCW/ICICI 0.00 0.80 0.00 0.00 0.00 0.80 0.00 0.00

2005 TISCO 100.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00

2004 UPL 15.45 0.00 0.00 0.00 15.45 0.00 0.00 0.00

1996 United Riceland 5.63 0.00 0.00 0.00 5.63 0.00 0.00 0.00

2005 United Riceland 8.50 0.00 0.00 0.00 5.00 0.00 0.00 0.00

2002 Usha Martin 0.00 0.72 0.00 0.00 0.00 0.72 0.00 0.00

2001 Vysya Bank 0.00 3.66 0.00 0.00 0.00 3.66 0.00 0.00

2005 Vysya Bank 0.00 3.51 0.00 0.00 0.00 3.51 0.00 0.00

1997 WIV 0.00 0.37 0.00 0.00 0.00 0.37 0.00 0.00

1997 Walden-Mgt India 0.00 0.01 0.00 0.00 0.00 0.01 0.00 0.00

2006 iLabs Fund II 0.00 20.00 0.00 0.00 0.00 0.00 0.00 0.00

Total portfolio: 956.52 249.41 42.30 536.35 604.74 175.91 38.60 236.35

Approvals Pending Commitment

FY Approval Company Loan Equity Quasi Partic.

2004 CGL 0.01 0.00 0.00 0.00

2000 APCL 0.01 0.00 0.00 0.00

2006 Atul Ltd 0.00 0.01 0.00 0.00

2001 Vysya Bank 0.00 0.00 0.00 0.00

2006 Federal Bank 0.01 0.00 0.00 0.00

2001 GI Wind Farms 0.01 0.00 0.00 0.00

2004 Ocean Sparkle 0.00 0.00 0.00 0.00

2005 Allain Duhangan 0.00 0.00 0.00 0.00

Total pending commitment: 0.04 0.01 0.00 0.00

128

Annex 14: Country at a Glance

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

Lo wer-P OVER T Y and SOC IA L So uth middle-

India A sia inco me2007Population, mid-year (millions) 1,123.3 1,520 3,437GNI per capita (Atlas method, US$) 950 880 1,887GNI (Atlas method, US$ billions) 1,069.4 1,339 6,485

A verage annual gro wth, 2001-07

Population (%) 1.4 1.6 1.1Labor force (%) 1.8 2.1 1.5

M o st recent est imate ( latest year available, 2001-07)

Poverty (% of population below national poverty line) .. .. ..Urban population (% of to tal population) 29 29 42Life expectancy at birth (years) 64 64 69Infant mortality (per 1,000 live births) 57 62 41Child malnutrition (% of children under 5) 44 41 25Access to an improved water source (% of population) 89 87 88Literacy (% of population age 15+) 61 58 89Gross primary enro llment (% of school-age population) 112 108 111 M ale 114 111 112 Female 109 104 109

KEY EC ON OM IC R A T IOS and LON G-T ER M T R EN D S

1987 1997 2006 2007

GDP (US$ billions) 276.0 410.9 916.3 1,171.0

Gross capital formation/GDP 22.0 23.9 36.0 38.2Exports o f goods and services/GDP 5.7 10.8 22.1 21.3Gross domestic savings/GDP 20.6 22.6 33.0 35.1Gross national savings/GDP 20.9 24.7 35.3 37.2

Current account balance/GDP -1.9 -1.4 -1.1 -2.1Interest payments/GDP 0.7 1.1 0.7 ..Total debt/GDP 20.1 23.0 16.7 ..Total debt service/exports 29.7 21.6 7.5 ..Present value of debt/GDP .. .. 12.7 ..Present value of debt/exports .. .. 48.5 ..

1987-97 1997-07 2006 2007 2007-11(average annual growth)GDP 5.5 6.9 9.7 9.0 8.5GDP per capita 3.5 5.3 8.2 7.7 7.2Exports o f goods and services 11.5 15.4 18.9 7.5 13.8

ST R UC T UR E o f the EC ON OM Y

India

Lower-middle-income group

D evelo pment diamo nd*

Life expectancy

Access to improved water source

GNIpercapita

Grossprimary

enro llment

India

Lower-middle-income group

Eco no mic rat io s*

Trade

Indebtedness

Domesticsavings

Capital formation

1987 1997 2006 2007(% of GDP)Agriculture 29.4 26.1 18.3 17.8Industry 26.3 26.8 29.3 29.4 M anufacturing 16.4 16.4 16.3 16.4Services 44.3 47.1 52.4 52.8

Household final consumption expenditure 67.1 66.0 56.7 54.8General gov't final consumption expenditure 12.3 11.4 10.3 10.1Imports o f goods and services 7.1 12.1 25.1 24.4

1987-97 1997-07 2006 2007(average annual growth)Agriculture 3.5 2.7 3.8 4.5Industry 6.3 7.2 11.0 8.5 M anufacturing 6.6 6.8 12.0 8.8Services 6.8 8.5 11.1 10.8

Household final consumption expenditure 5.5 5.8 10.3 7.3General gov't final consumption expenditure 4.2 3.9 6.2 5.5Gross capital formation 6.8 11.0 14.3 13.3Imports o f goods and services 12.3 14.8 24.5 7.7

Note: 2007 data are preliminary estimates.This table was produced from the Development Economics LDB database.

* The diamonds show four key indicators in the country (in bo ld) compared with its income-group average. If data are missing, the diamond will be incomplete.

0

10

20

30

02 03 04 05 06 07

GCF GDP

Gro wth o f capital and GD P (%)

0

20

40

60

02 03 04 05 06 07

Exports Imports

Gro wth o f expo rts and impo rts (%)

129

India

P R IC ES and GOVER N M EN T F IN A N C E1987 1997 2006 2007

D o mestic prices(% change)Consumer prices 7.8 7.0 6.7 5.3Implicit GDP deflator 9.3 6.5 5.6 4.3

Go vernment f inance(% of GDP, includes current grants)Current revenue 19.4 17.4 20.6 22.4Current budget balance -2.7 -3.5 -4.4 -1.6Overall surplus/deficit -9.2 -8.3 -6.5 -5.6

T R A D E1987 1997 2006 2007

(US$ millions)Total exports (fob) 12,644 35,680 128,083 146,632 M arine products 411 1,207 1,744 .. Ores and minerals 600 1,061 7,033 .. M anufactures 8,195 26,547 82,818 91,657Total imports (cif) 19,812 51,187 191,254 238,296 Food 1,141 1,483 3,291 .. Fuel and energy 3,118 8,164 57,074 .. Capital goods 5,064 9,796 52,944 71,311

Export price index (2000=100) 113 116 .. ..Import price index (2000=100) 116 110 .. ..Terms of trade (2000=100) 97 106 .. ..

0

100,000

200,000

300,000

01 02 03 04 05 06 07

Exports Imports

Expo rt and impo rt levels (US$ mill.)

0

2

4

6

8

02 03 04 05 06 07

GDP def lator CPI

Inf lat io n (%)

B A LA N C E o f P A YM EN T S1987 1997 2006 2007

(US$ millions)Exports o f goods and services 16,216 45,109 204,264 246,071Imports o f goods and services 22,839 59,297 235,625 297,009Resource balance -6,623 -14,188 -31,361 30,176

Net income -1,337 -3,521 -6,573 ..Net current transfers 2,698 11,830 27,941 30,176

Current account balance -5,262 -5,879 -9,993 -24,408

Financing items (net) 4,526 9,772 46,599 44,282Changes in net reserves 736 -3,893 -36,606 -19,874

M emo :Reserves including go ld (US$ millions) 6,223 29,367 198,710 218,582Conversion rate (DEC, local/US$) 13.0 37.2 45.2 40.3

EXT ER N A L D EB T and R ESOUR C E F LOWS1987 1997 2006 2007

(US$ millions)Total debt outstanding and disbursed 55,570 94,317 153,075 .. IBRD 4,709 8,138 6,177 7,040 IDA 11,615 17,912 24,059 26,512

Total debt service 5,686 12,413 17,879 .. IBRD 808 1,410 597 739 IDA 166 381 841 915

Composition o f net resource flows Official grants 531 549 873 .. Official creditors 2,498 -406 2,144 .. Private creditors 2,877 1,089 16,097 .. Foreign direct investment (net inflows) 212 3,577 17,453 .. Portfo lio equity (net inflows) 0 2,556 9,549 ..

World Bank program Commitments 3,504 2,306 1,228 3,174 Disbursements 2,212 1,372 1,787 1,905 Principal repayments 499 1,070 942 1,089 Net flows 1,714 302 845 816 Interest payments 476 721 496 566 Net transfers 1,238 -419 349 251

Note: This table was produced from the Development Economics LDB database. 9/24/08

-3

-2

-1

0

1

2

3

01 02 03 04 05 06 07

C urrent acco unt balance to GD P (%)

G: 11,971A: 6,177

D: 4,096

B: 24,059

F: 87,110

E: 19,662

A - IBRDB - IDA C - IM F

D - Other mult ilateralE - BilateralF - PrivateG - Short-term

C o mpo sit io n o f 2006 debt (US$ mill.)

130

Annex 15: Governance and Accountability Action Plan

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT 1. Summary of Key GAAP Issues: There are three key governance and accountability (GAC) issues for the India Coal-Fired Generation Rehabilitation Project. It is noted that significant upstream work has been carried out by the implementing agencies with the support of the Bank team to mitigate these risks. A summary of the three high risk areas and mitigation measures are as follows:

i) Risk related to technical aspects of the project This pertains to the difficulty in assessing apriori the exact scope of what physical activities need to be carried out, since this cannot be fully determined until after the contractor opens up the machine, and the consequent difficulty of accurately defining technical specifications in the bid documents and assessing project costs. Mitigation measures include deployment of independent consultants to carry out detailed technical and design studies and incorporation of lessons learned from both domestic and international experience.

ii) Risk of low level of participation in the bidding process and higher than anticipated price discovery It is noted that the pre-bid conference for rehabilitation of the first unit has already been held and attracted several quality suppliers. In addition, wider competition, including from international suppliers (in particular, Chinese and Eastern European which have an interest in the Indian power market), is being actively sought by the utilities. Qualification requirements are also being designed to widen competition. In addition, a the two-stage bid-process will be used under which supplier concerns would be further incorporated prior to submitting a price bid.

iii) Weak client capacity and the inadequate decision-making framework during implementation, especially in view of possible ‘surprises’ upon opening the machines which may require contract modifications and price increases. The weak client capacity will be partially mitigated through the employment of implementation support and quality assurance consultants by each utility. In addition, a recommended strategy for handling potential surprises has been developed in advance and a decision making process in case of unidentified surprises has been defined and agreed during appraisal to reduce delays and minimize potential governance issues.

2. These and other issues are highlighted in the sections below, along with mitigation measures.

Background: India depends on 76,000MW of coal-fired power generation capacity representing about 53 percent of total installed capacity (143,000 MW). About two-thirds of this capacity is with generation utilities which are owned by state governments. Most of these state generation utility owned power plants are in poor shape, and many (about 30,000 MW) would need to be rehabilitated over the next few years.

131

3. However, rehabilitation of power plants in India has been focused on life extension and increased availability rather than improved energy efficiency. Also, such projects have been facing several barriers in implementation – including rehabilitation design challenges, procurement difficulties, contractual issues, regulatory issues, limited institutional capacity to take up such projects, and poor capacity for post-rehabilitation operation and maintenance of the plant. As a result, implementation of rehabilitation projects during the tenth plan period fell nearly 40 percent short from the targeted 10,400 MW.

Rehabilitation of old and energy inefficient coal-fired generation capacity assumes significance in view of the climate change mitigation concerns. It also offers an opportunity to add low cost power to the starving grid and in a shorter time span60. The Bank project is aimed at addressing some of the key barriers to implementation of energy efficient rehabilitation projects and demonstrating energy efficiency focused (rather than just life extension or availability focused) approaches in 640 MW of capacity across the three selected states – West Bengal, Maharashtra and Haryana.

4. Approach to Project Design and Preparation: Since the objective of the project is to demonstrate approaches for successful rehabilitation of old generation units (with focus on energy efficiency) – even in the face of difficulties in implementation of similar projects in the past – the process of risk identification and initiation of steps towards mitigation of risks started early in the project design cycle. Based on the past rehabilitation experience in India and abroad, it was recognized upfront that this project would be fraught with several risks. The approach to project design and preparation is therefore reflective of the focus on risk identification and mitigation efforts. Some of the key aspects are:

(i) Preparation of technical design of the project by an independent international technical consultancy firm. The consultants were responsible for review of Residual Life Assessment reports, conducting Energy Audit studies, developing coherent Design Options, evaluation of design options to select the preferred option, preparation of Detailed Technical Specifications and support on commercial and contractual design of the bidding process.

(ii) Detailed review of all technical aspects of project design by a team of technical experts with extensive experience in design and implementation of R&M projects in India and abroad. The team includes Bank experts who have multi-country experience of design and implementation of R&M projects, including the recent projects in Turkey and China. The team provided its inputs/comments to the client (WBPDCL) and consultants at all stages of technical evaluation and design.

(iii) Structuring of procurement for R&M of Unit-5 of Bandel into four packages – (a) Boiler, Turbine and Generator (BTG) package, (b) Coal Handling Plant, (c) Ash Handling Plant, and (d) Electrical System Package. The decision to keep the most critical BTG elements as a single package (as against allowing two or three separate packages for these elements) was based on past R&M experience in India and abroad which assists in correct risk allocation between the client and contractors. This would allow supplier’s accountability for unit performance as a whole, while also ensuring that the designs of various sub-systems are mutually compatible.

60 A new coal based thermal plant takes about 42 months after the contract award, while well planned Renovation & Modernization work could be completed in 24-30 months with around 6 months plant down time.

132

(iv) Two-stage bidding for the main BTG package would allow further refinements in technical design based on concerns highlighted by bidders. It would also allow the client to gauge the market response to R&M projects and accommodate any concerns in contractual design which may discourage wider participation in the bid process.

(v) Bid documents are being designed to allow wider bidder participation (which has been a problem in the past) while ensuring contractual accountability during and after R&M implementation. In addition, the responsibility to manage and mitigate risks is also being clearly put forth in the bid documents to avoid contractual issues during implementation.

(vi) Independent Implementation Support and Quality Assurance Consultants would be appointed for monitoring of implementation progress as well as quality. These consultants would act as owner’s engineers and validate all design details, material supplies and works executions. The consultants would also support the decision making process to handle surprises during the course of R&M implementation.

(vii) In the past, R&M projects in India have faced environmental concerns because of which some of the non-Bank funded projects did not find enough interest from generation utilities. For this project, detailed EADD and RSA studies have been completed for R&M of units/plants in West Bengal and Maharashtra. The recommendations from the EADD studies have been included in the technical design prepared by design consultants. An action plan for implementation of recommendations from the RSA study as well as steps for mitigating additional plant level environmental concerns has been agreed with these utilities. Assessment of environmental and social aspects of Panipat power plant in Haryana is being carried out.

(viii) Preparation of a detailed strategy for handling surprises when the machines are opened up for R&M implementation. The strategy includes a list of possible surprises, ensuring availability of parts to minimize delays, addressing upfront the likely contractual aspects of additional supplies and works, and establishing a clear decision making framework.

(ix) In terms of initiating steps to address some of the sector level barriers to R&M in India, ESMAP funds have been used for pursuing a “Study of Options for Regulatory Treatment of Rehabilitation Projects in India”. The first part of the study has been completed and is being disseminated to stakeholders. Another key sustainability risk from the past projects has been the lack of adequate capacity for Operations and Maintenance (O&M) of the rehabilitated units. ESMAP funds have been used for undertaking a “Study of O&M practices at Koradi and Bandel”. The study which is now in the final stages of completion also brings out a plan for strengthening O&M practices at these power plants.

(x) Phasing of R&M investments in the states of West Bengal, Maharashtra and Haryana to allow transfer of learning from one state to the next.

5. However, despite incorporating the above approaches in the design and preparation of the project, the team feels that the residual risk remains substantial.

6. Approach to GAAP Analysis: The governance and accountability action plan (GAAP) is a summary of governance related issues and actions that have been distilled from risk

133

identification and mitigation steps proposed by several functional parts of the team such as technical, implementation arrangements, procurement, FM, environment, social safeguards, communication etc) and the task team in consultation with the clients (i.e. the state-owned utilities in West Bengal, Maharashtra and Haryana).

7. The GAAP has been structured to examine issues at the project, corporate and sector levels in three separate sections. This structure is seen as conducive to highlighting immediate concerns for successful implementation of the project, medium term capacity strengthening aspects at the corporate (or plant) level, and sector level issues.

8. Since project activities in the three implementing utilities would be phased-apart, the GAAP provides an indicative timeframe of implementation progression in each of the three utilities. The mitigation measures, cost estimates, resource availability and monitoring mechanisms for these measures are also captured in a separate table across various activity phases of the project.

9. The participating state utilities have expressed interest in taking up proactive actions (including capacity development) to address some of the corporate level governance and accountability aspects. It is important to note that client utilities view Bank engagement as an opportunity to strengthen institutional capacities, although the Bank project forms a rather small part of their overall investment plans. For example, Maharashtra State Power Generation Company Limited (MSPGCL) has capacity augmentation plans for about 7000 MW (about USD 7 billion) during the XI plan (up to 2011-12). In comparison, the Bank project would involve investments of about USD 100 million in the state.

10. Most of the risks and mitigation approaches identified under the GAAP are already being implemented in course of project design and preparation. Many of the steps proposed would be incorporated in the long-drawn R&M preparation and implementation process in each state. The project team would be working closely with the clients for their implementation.

I. Project Level Issues

11. Based on a risk analysis across various stages of the project cycle (viz. renovation and modernization (R&M) Design, Procurement, Implementation and Post-Implementation), the following risks and mitigation measures have been identified (see Table-1 below). The implementation phasing of these mitigation measures, cost estimates, resource availability and monitoring mechanism are provided in Table-4.

Table-15.1: Project Level Risks and Mitigation Steps

Risk Description (Level of Risk)

Mitigation Steps (Level of Residual Risk)

Responsibility Timeline / Status

R&M Design Inaccurate assessment of R&M requirements and inappropriate selection of design options may lead to inadequate design, implementation delays, cost escalations and sub-

Deployment of independent consultants for carrying out Energy Audit Studies, Residual Life Assessment studies and preparing Design Specifications. Review of Design options and Selected

Utility: Appoint independent consultants and support R&M design activities. Bank: Assist in review of technical design by

WBPDCL: Consultants appointed, Review by independent sector experts undertaken. MSPGCL: Independent consultants appointed. HPGCL: Procurement of

134

Risk Description (Level of Risk)

Mitigation Steps (Level of Residual Risk)

Responsibility Timeline / Status

optimal post-commissioning performance.

(High)

Design Specifications by utility officials and independent sector experts. Incorporation of lessons learned in domestic and international experience.

(Substantial)

independent sector experts.

Independent consultants underway.

Design Specifications may be tailored to favor a particular supplier, or may incorporate propriety items.

(Moderate)

Multiple agencies (including design consultants, utility officials, and independent experts) vet the design before finalization. Two-stage procurement would provide opportunity to bidders to flag biases

(Low)

Utility: Get Design specifications vetted by various agencies. Utility: Address concerns raised by bidders at the end of stage-one of two-stage bidding process.

WBPDCL: Specifications have been vetted by various agencies MSPGCL/HPGCL: Specifications to be vetted by various agencies during

Procurement Risk of corruption in procurement or collusion among suppliers is moderate where potential bidders are known to be business rivals.

(Moderate)

Enhance participation through wider dissemination of procurement notices by mailing the SPN to all potential suppliers, making the bid documents easily accessible and a participatory pre-bid conference to address concerns.

(Low)

Utility: Enhance participation through wider dissemination of procurement notices by mailing the SPN to all potential suppliers. Utility: Make the bid documents easily accessible. Utility: Organize a participatory pre-bid conference to address concerns.

WBPDCL: A suppliers' conference has been held to gauge supplier interest and also identify their concerns. MSPGCL/HPGCL: Undertake the recommended steps at the appropriate stage, while also incorporating lessons from preceding R&Ms.

Risk of rebid and ensuing delay due to incorrect specifications or improper qualification requirements (QR). There is also a risk of higher than expected price bids.

(High)

Bidders for the main BTG package to be brought on par on technical basis through two-stage bidding process. Examine QR carefully. Budget estimates to have appropriate cushion for volatility in price discovery. Economic and Financial appraisal to confirm project viability even at a higher cost.

(Substantial)

Utility: Undertake a two stage procurement process (unless Bandel experience suggests otherwise). Utility/Bank: Examine QR carefully. Utility: Incorporate sufficient price and physical contingencies in cost estimates. Utility/Bank: Conduct scenario analysis to examine impact of high project cost. Utility/Bank: In case additional funds are needed, the client could borrow from commercial sources, or the Bank could consider additional financing.

WBPDCL: All suggestions have been incorporated in the procurement design. MSPGCL/HPGCL: Suggestions to be incorporated in procurement design at the appropriate stage. (Refer Table-4)

Contractual disputes due to changes in scope of

Dispute Resolution Mechanism would be

Utility/Bank: Specify a clear dispute resolution

WBPDCL: Dispute resolution mechanism is being provided

135

Risk Description (Level of Risk)

Mitigation Steps (Level of Residual Risk)

Responsibility Timeline / Status

work, delays on part of supplier (in supplies or works) or the client (providing shutdown, regulatory concurrence, decision making in event of surprises) and performance demonstration etc.

(High)

specified in bid documents. Bid documents to provide clear segregation of responsibility between supplier and client for shouldering residual risks.

(Substantial)

mechanism in the bid documents encompassing various modes of dispute resolution. Utility: Bid documents should provide a clear segregation of responsibility for shouldering risks.

in the bid documents. Segregation of responsibilities for risks is also being included in the bid documents. MSPGCL/HPGCL: Actions would be taken at the appropriate stage. (Refer Table-4)

Implementation Implementation delays due to non-availability of key components / equipment In addition, ‘Surprises’ may be found on opening the machines, leading to increased cost and time delays, and potential for governance issues in deciding how to handle such surprises.

(High)

Availability of components would be ensured before start of implementation. A list of potential surprises was developed along with a recommended strategy to handle it. For instance, the strategy for several potential surprises was for the utility to procure additional components and keep them as spares. Further, the bid documents would require the bidders to submit prices of such components/works which may need to be procured during implementation to handle surprises. Decision making process in case of surprises would be defined as a part of project design process. (See mitigation steps for the previous risk).

(Substantial)

Utility: Ensure that implementation plan of the supplier includes approach for ensuring that all critical components are available during implementation. Utility: Put in place a streamlined decision making process (including escalation mechanism) to handle surprises smoothly. Utility: Strategy for addressing surprises to be included in the Detailed Project Report. Prices of works/goods to handle surprises to be included in bids.

WBPDCL: Strategy for surprises is under preparation. Decision making process in case of surprises is being discussed. Supplier’s implementation plan would be put in place at the appropriate stage. MSPGCL/HPGCL: Actions would be taken at the appropriate stage. (Refer Table-4)

Inadequate utility capacity to supervise implementation of complex R&M project. Inadequate supervision and quality assurance may lead to sub-standard implementation, weak financial management discipline and lower than expected plan performance.

Independent Implementation Support Consultants (Quality Assurance Consultants) would be appointed to confirm that implementation is as per the design requirements. Consultants would also certify quality of materials and works before the payments are made as per contractual milestones. Since supply and install contracts will be used, this will mitigate any supply

Utility: Appoint Implementation Support (Quality Assurance) Consultants. Utility: Develop a project monitoring plan based on which the Implementation Consultants would monitor the progress of the R&M tasks.

WBPDCL: Process for procurement of consultants has been initiated MSPGCL/HPGCL: Implementation consultants would be procured at the appropriate stage. (Refer Table-4)

136

Risk Description (Level of Risk)

Mitigation Steps (Level of Residual Risk)

Responsibility Timeline / Status

(Substantial)

chain management issues, (Moderate)

Perceived negative social/environmental impacts of coal-fired generation on near-by villages despite appropriate safeguard measures.

(Substantial)

Disseminate project impact assessments and benefits to nearby villages by deploying an appropriate strategy for communication. (See complaint redressal mechanism below)

(Substantial/Moderate)

Utility: Develop an appropriate communication strategy and intensify initiatives under corporate social responsibility obligations.

WBPDCL/MSPGCL: No specific issues are anticipated. HPGCL: Communication strategy being developed – to be formalized as a part of Rapid Social Assessment.

Post-Implementation Sustainability of R&M gains may be affected by weak O&M practices and therefore the ultimate accountability for realizing the benefits of the investment may not be assured. (High)

Strengthening of O&M practices by conducting O&M assessment to develop and implement a long-term O&M action plan. This would be used as a capacity building tool for the entities.

(Moderate)

Utility: Undertake O&M assessment and develop an Action Plan Utility: Implementation of O&M Action Plan. Bank: Provide GEF grants for capacity building on O&M issues

WBPDCL/MSPGCL: O&M assessment and action plan tasks have been completed. Implementation to be undertaken in accordance with the action plan. HPGCL: O&M studies to be initiated by Dec’ 2008.

Transparency, Disclosures and Complaints Redressal Achievement of PDOs adversely affected by lack of adequate disclosure of project information or absence of adequate systems to disclose and report information.

(Low)

All three utilities come under the RTI Act for both suo-moto and on-demand information. Utilities to disclose all relevant project information (especially on safeguard and fiduciary aspects) as per bank requirements. (Low)

Utility: Disclose all relevant project information (especially on safeguard and fiduciary aspects) as per bank requirements.

WBPDCL/MSPGCL /HPGCL: Disclosure related agreed approach to be finalized in PIP.

Achievement of PDOs adversely affected by lack of adequate complaint redressal mechanisms.

(Substantial)

Adequate complaint redressal framework to be defined in consultation with the Bank team.

(Moderate)

Utility: To develop a complaint redressal mechanism for the project in consultation with the Bank team.

WBPDCL/MSPGCL/HPGCL: Complaint redressal mechanism is under discussion, and would finalized in PIP.

II. Corporate (or Plant) Level Issues

12. Corporate level issues have been identified based on capacity assessment studies in the areas of corporate governance, financial management, procurement, safeguards and operations & maintenance practices. All the three companies (WBPDCL, MSPGCL and HPGCL) have expressed interest in initiating significant measures towards strengthening institutional capacities through Bank support in course of implementation of the R&M project. Most of these initiatives would be taken at the corporate level, while the remaining would be piloted at the plants where R&M units are located. A summary of the key corporate level issues and agreed plans for addressing them through institutional capacity strengthening is provided in Table-2, where as detailed action plans in each area are provided in respective sections elsewhere in the PAD.

Table-15.2: Corporate (or Plant) Level Issues and Capacity Strengthening Plan

Agreed Actions Issues WBPDCL MSPGCL HPGCL

137

Agreed Actions Issues WBPDCL MSPGCL HPGCL

Corporate Governance and Financial Management Gaps in compliance with prudent financial management and corporate governance practices. 61

Implement the agreed time-bound CG&FM Action Plan (refer to PAD, Annex 7). Implementation of the CG&FM Action Plan would be supported through the GEF funded TA Component

Implement the agreed time-bound CG&FM Action Plan (refer to PAD, Annex 7). Implementation of the CG&FM Action Plan would be supported through the GEF funded TA Component

HPGCL would facilitate a Corporate Governance and Financial Management review by the World bank team. An agreed CG & FM Action Plan would be developed before negotiations.

Safeguards Power Plants under the project are not fully compliant with National Ambient Air Quality Standards (NAAQS) and the Bank safeguard policies.

WBPDCL to select the preferred option and implement it during the course of the project. Option-1: Adopt progressive emission reductions over the project implementation period for Units 1-4 to ensure compliance with NAAQS. Option-2: Provide a clear plan for scrapping of units 1-4 which are old and not suitable for rehabilitation.

Adopt progressive emission reductions over the project implementation period for all generation units of the Koradi power plant to ensure compliance with NAAQS.

EADD studies to be completed and recommendations for conforming to NAAQS and Bank operational policy requirements to be implemented for the Panipat plant as a whole.

Absence of a clear corporate policy with regard to environmental and social safeguards at the Generation companies. Limited institutional capacity to handle such issues.

Corporate environmental management policies and procedures to be established. Also, strengthening to safeguard and safety roles based on the recommendations of the EADD and RSA. CSR Policy to be developed and adopted.

Corporate environmental management policies and procedures to be established. Also, strengthening to safeguard and safety roles based on the recommendations of the EADD and RSA. CSR Policy to be developed and adopted.

EADD and RSA studies to be completed and recommendations on corporate safeguard policies to be adopted.

III. Sector Level Issues

13. Implementation of the GOI program for rehabilitation of old coal-fired generation units on a wider scale, as well as sustained performance of units that have been rehabilitated are affected by some sector level issues, which are much broader than the scope of the present project. The Bank project can only attempt to create demand side pressures and explore stakeholder interest in furthering the discussion on some of these issues. The most critical issues in this regard are provided in Table-3 below.

Table-15.3: Sector Level Concerns and Mitigation Approach

Sector Issue Approach for Addressing Responsibility Timeline / Status

Continued weak accountability for coal

This issue is a much larger than the scope of the current

Utility: Institutionalize / strengthen coal

Plant level study to be completed before start of

61 It is important to note that the Bank project has been largely insulated from such gaps. The project involves four large contracts for each R&M. Payment would be made directly to the suppliers by the World Bank for each contract based on recommendation by independent consultants.

138

quality and quantity (including availability)

project. However, energy efficiency orientation institutionalized under the project may stimulate some user side demand for coal sector reforms in the medium term.

accountability measures within the plant.

R&M works in each plant.

Regulatory treatment of R&M projects leaves substantial project risk with generation utility

Almost all R&M projects in India till date received cost-plus tariffs based on R&M design parameters, where most of the project risk rests with the generator. Other models for regulatory treatment and risk allocation need to be explored to facilitate wider implementation of R&M projects by mitigating regulatory risks.

Bank: Conduct a study to explore options for regulatory treatment of rehabilitation and modernization projects. Utility: Explore possibility of implementing some of the suggested models in present or future R&M projects

Study of regulatory options has been completed and dissemination is underway. Next phase of regulatory study involving deeper examination of select options to be completed before June 2009.

IV. Implementation Phasing, Resource Requirements and Monitoring Milestones

14. The implementation of the project will be carried out in a phased manner. The project is divided into nine key activity phases which are illustrated in Figure-1 with timelines for each of the three participating states. The mitigation measures that will be taken in each of these nine activity phases (as examined in the risk matrices in Tables-1, 2 & 3) are brought out in Table-4. This table also lays down the availability of resources for the carrying out the mitigation measures and the corresponding monitoring mechanisms that have been put in place. During supervision, the Bank team would be reviewing progress / conformity against these monitoring mechanisms.

Indicative Phasing of Project Implementation Activities

Year � 2007 2008 2009 2010 2011 2012 2013WBPDCL (Unit-5, Bandel) Quarter� 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2

Year � 2007 2008 2009 2010 2011 2012 2013 MSPGCL (Unit-6, Koradi) Quarter� 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3

Year � 2008 2009 2010 2011 2012 2013 2014 HPGCL (Unit 3&4, Panipat) Quarter� 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 41) Institutional Capacity Assessment 2) RLA, EA, DPR Reports 3) Preparation of Bid Documents 4) Procurement of the Main Package 5) Capacity Building Measures 6) Detailed Design and Supplies 7) Shutdown for Implementation 8) Testing and Acceptance 9) Post-R&M M&E Activities

139

Table-15.4: Phase-wise Mitigation Steps, Costing, Resource Availability & Monitoring Mechanism

Risk Mitigation Steps Cost Estimate Resource Availability Monitoring Mechanism

1. Institutional capacity Assessment and Improvement Action Plan a) Client Utility to facilitate Corporate Governance and Financial Accountability Review by the World Bank team.

- No additional resource requirement is anticipated for CG&FA review.

Submission of CG&FA review satisfactory to the Bank is an eligibility condition for inclusion under IBRD/GEF project.

b) Assessment of O&M practices in the proposed plants and preparation of Action Plan for improvement.

~USD 85,000 for each plant

O&M Studies at Koradi and Bandel already underway using ESMAP grant funding. Studies for Panipat to be funded from GEF grants under TA component (sub-component-4: USD 2.4 million)

Submission of report on detailed review of O&M practices and an agreed O&M improvement action plan (including institutional capacity strengthening) is an eligibility condition for inclusion under IBRD/GEF project.

c) EADD & RSA studies to be completed and CSR Policy to be developed and adopted.

~USD 75,000 for each plant

Studies for Bandel and Koradi already funded from PHRD grants. Part of the GEF grants under TA component (USD 2.5 million under sub-component-1) for Units 3&4 Panipat.

Submission of a detailed EADD, CSR & RSA satisfactory to the Bank is an eligibility condition for inclusion under IBRD/GEF project.

2. Residual Life Assessment, Energy Audit Report and Detailed Project Feasibility Report d) Deployment of independent consultants for carrying out Energy Audit Studies, Residual Life Assessment studies and preparing Design Specifications.

~USD 500,000 for each unit

Studies for Bandel and Koradi already funded from PHRD grants. Part of the GEF grants under TA component (USD 2.5 million under sub-component-1) for Units 3&4 Panipat and other (pipeline) R&M units.

Submission of a detailed project report (based on an independent energy audit) satisfactory to the Bank is an eligibility condition for inclusion under IBRD/GEF project.

e) Review of Design options and Final Design Specifications by utility officials and independent sector experts.

- No additional resource requirement is anticipated.

Bank supervision team to confirm that design options and final design specifications have been reviewed by utility officials and independent sector experts before the DPR is accepted.

f) Detailed project Report should incorporate the following: • Sufficient price and physical contingencies in cost estimates. • Lessons from domestic and international experiences. • Scenario analysis (economic and financial analysis) including impact of cost escalation, time delays, longer shutdown and non-achievement of design parameters. • List of potential surprises along with strategy to handle

- No additional resource requirement is anticipated.

Implementing utility to verify these points before it accepts the DPR and shares it with the Bank. Bank supervision team to verify these points before the DPR is accepted.

140

Risk Mitigation Steps Cost Estimate Resource Availability Monitoring Mechanism each of them. • Unit-level environmental measures as suggested in the EADD report are included. g) In-principal arrangements for additional financing in case of cost-escalations are identified.

- No additional resource requirement for conforming to this requirement is anticipated.

Implementing utility & Bank supervision team to verify this at the time of acceptance of DPR.

h) Decision making process at the utility during implementation (especially in case of surprises) to be defined and documented.

- No additional resource requirement is anticipated.

Implementing utility to submit the decision making framework document to the Bank for review and acceptance.

3. Preparation of Bid Documents i) Bid Documents should incorporate the following: • Two stage procurement process for the BTG package • Qualification requirements should help enhance competition • An explicit Dispute Resolution Mechanism • Clear segregation of responsibility between supplier and client for shouldering residual risks • Requirement from bidders to submit prices of components/ works which may need to be procured during implementation to handle surprises • Clear indication of applicable taxes • Strategy to handle surprises is incorporated • Role of Independent Quality Assurance Consultant (Implementation Support Consultant) is clearly stated.

- No additional resource requirement is anticipated.

Implementing utility to verify these points before it submits the bid document to the Bank for No Objection Bank team to verify these points before the Bid documents are accepted.

4. Procurement of the Main Package j) In-principal investment approval from regulator should be secured before start of procurement.

- No additional resource requirement is anticipated.

Client utility to confirm to the Bank team, that In-principal investment approval from the regulator has been secured.

k) Enhance participation through wider dissemination of procurement notices, making the bid documents easily accessible and a participatory pre-bid conference to address concerns.

- No additional resource requirement is anticipated.

Client utility to confirm implementation of these steps at least 4 weeks before the last date for submission of stage-1 bids.

l) Bidders for the main BTG package to be brought on par on technical basis through discussions after Stage 1

- No additional resource requirement is anticipated.

Client utility to obtain Bank’s No Objection on the revised stage-2 bid document. Supervision team to check at that stage that adequate post-stage-1

141

Risk Mitigation Steps Cost Estimate Resource Availability Monitoring Mechanism modifications have been incorporated to address suppliers’ concerns.

m) Independent Implementation Support Consultants (Quality Assurance Consultants) to be appointed.

~USD 500,000 for each unit

Part of the GEF grants under TA component (USD 1.5 million under sub-component-2) would be available for the three pilot R&Ms. Balance requirement (if any) would be funded by the implementing utility from its own sources.

Bank team to check with the implementing utility that implementation consultants are in place by the end of stage-1 bidding process.

5. Institutional Capacity Strengthening Measures n) Strengthening of O&M practices by implementing a long-term O&M action plan.

~USD 400,000 for each plant

Supported through the GEF funded TA Component (sub-component-4)

Bank team to supervise based on timelines provided in the O&M Action Plan for each plant.

o) Agreed CG & FA Action Plan is implemented in the agreed time-bound manner

~USD 150,000 for each utility

Supported through the GEF funded TA Component (sub-component-4)

Bank team to supervise based on timelines provided in the CG&FA Action Plan for each utility.

p) Strengthening of institutional capacities of implementing utilities and the CEA.

~USD 250,000 for each utility ~USD 350,000

for CEA (tentatively)

Supported through the GEF funded TA Component (sub-components-3 and 4)

Bank team to supervise based on timelines provided in the O&M Action Plan for each utility, and the agreed plan for CEA.

q) Plant level Environment Action Plan as per EADD to be implemented.

~USD 4 M million for

Bandel ~USD 2

million for Koradi

Estimates for Panipat would be available on completion of EADD study

Implementation of plant-level EAPs (including arrangement of funds) would be responsibility of the client utility

Client utility to disclose the plant level EAP as a part of disclosure requirements of the Bank. Implementation to be confirmed during supervision missions.

6. Detailed Design and Supplies r) Availability of components as per plan would be ensured before start of shutdown.

- No additional resource requirement is anticipated.

Implementing utility to confirm preparedness to the bank team before the start of shutdown for implementation.

s) Preparedness for handling surprises would be ensured before start of shutdown.

- No additional resource requirement is anticipated.

Implementing utility to confirm preparedness to the bank team before the start of shutdown for implementation.

t) Review of technical design and quality / timeliness of supplies / works to be ensured by the utility with the assistance of Implementation Support Consultants. The client/ consultants would also ensure that the implementation conforms to the R&M design.

- No additional resource requirement is anticipated.

Bank team to supervise during formal missions. In addition, informal interim missions would become more frequent during the final stages of this phase.

142

Risk Mitigation Steps Cost Estimate Resource Availability Monitoring Mechanism

7. Shutdown for Implementation u) Strategy to handle surprises, Decision making process at utility (especially in case of surprises / disputes) Arrangements for additional funds and Dispute resolution mechanism would be put into use when needed during this phase.

- No additional resource requirement is anticipated.

Client to ensure that these mechanisms are put into practice when required. Bank team to supervise closely to ensure compliance.

v) Closer supervise may be required during shutdown

- No additional resource requirement is anticipated.

Bank team to supervise more closely during shutdown

8. Testing and Acceptance w) The bidding documents prepared on the basis of the Bank Standard Bidding Documents for Supply and Installation have specific provision regarding plant provisional acceptance and final acceptance. The Independent Implementation Support Consultants will supervise this phase and certify that the performance of the plant is in compliance with technical specifications.

- No additional resource requirement is anticipated.

Implementing utility and Bank supervision team to verify before the payment are made as per contractual milestones. As per Bank procurement guidelines, the contractual documents will specify when and how final payment will be released to the contractor and the implementation consultants will have to certify that payment can be effected.

9. Post-R&M M&E Activities x) Lessons learnt to be documented and disseminated- Assistance to CEA in development of R&M program through 3-4 studies

~USD 750,000 Funds will be available through GEF TA component (sub-component-3)

Bank supervision team to coordinate documentation and dissemination activities through CEA. The proposed studies may be initiated earlier when project experience on specific aspects is available on completion of related phase.

143

Annex 16: Incremental Cost Analysis

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT I. BACKGROUND 1. Challenges in coal-fired generation sub-sector: India depends on 76,000 MW of coal-fired power plants representing 53 percent of total installed capacity (143,000 MW), but much of this does not perform well. The central sector National Thermal Power Corporation (NTPC) owns nearly a third of this capacity which are generally efficient with station heat rates (SHR) of about 2,500 kcal/kWh or less (i.e. close to design value). NTPC plants also have good plant availability with average plant load factors (PLF) of about 92 percent. The remaining coal-fired plants are owned largely by state government utilities. Most of these generation plants that are owned by state government utilities (except some states such as Rajasthan, Karnataka, Punjab and Andhra Pradesh) are in a poor shape – with an average PLF of about 70 percent with some plants having PLFs lower than 55 percent and SHR of about 3,000 kcal/kWh and above, (sometimes up to 4,000 kcal/kWh in many cases).

2. Large fleet of coal-fired power generation units is due for Rehabilitation: India was able to keep pace with needed Renovation and Modernization (R&M) investments through the better part of the 7th, 8th and 9th Five-Year Plans, covering the fifteen years until 2002. Since then R&M requirements have increased rapidly and implementation of R&M schemes has slowed down. The 10th Plan (2002-2007) R&M target was not fully met – especially by the state generation utilities and nearly 8000 MW spilled over into the 11th Plan, which now has an R&M requirement of nearly 27,000 MW (about a third of the total installed coal-fired generation capacity in the country). The Bank and GOI have agreed to focus on 110 MW and 210 MW units which are in urgent need for R&M in India and constitute about 68% of the 27,000 MW identified for R&M.

3. Also, in the case of past R&M investments, plant availability has tended to decline back to the pre-R&M levels within a few years due to poor O&M practices at many state government utilities. More importantly, for the past and planned R&M, the primary criteria is often PLF enhancement and life extension, and any energy efficiency improvements (SHR and other parameters) achieved is usually incidental and not a primary criteria for R&M project design.

4. Barriers to implementation of R&M projects: Past experience with R&M of coal-fired generation in India indicates that there are several barriers that inhibit R&M investments in India.

a. Difficulty in securing long plant shutdown needed for R&M. Many of the best candidates for R&M are owned by states which are facing severe power shortages and are therefore reluctant to have them out of service for the length of time required for R&M. The additional cost of arranging energy during shut down periods, for these fully depreciated plants is a significant burden on the utilities as well as the States.

144

b. Regulatory issues. There is significant uncertainty about whether the full R&M capital expenditure will be passed through to the rate base of the generation companies and on the sharing of benefits of R&M between generators and consumers.

c. Limited institutional capacity at the utility to take up R&M projects. Most generation utilities in India have plans for large green-field capacity addition over the eleventh five year plan period (2007-12). Utilities tend to accord a higher priority to green-field capacity addition over R&M projects, since the latter are perceived to be more risky, require much greater preparatory effort and the utility’s institutional capacity to implement projects is limited.

d. Lack of energy efficiency orientation. In the past, Indian power generation utilities and planning agencies have been primarily concerned with capacity enhancement and life extension of coal-fired generation and not the efficient operation of these facilities.

e. Time and cost overruns and contract management difficulties in the past. Utilities are discouraged from taking up R&M schemes by the implementation delays, cost escalations (due to surprises when machines are opened up) and contractual difficulties during implementation.

f. Poor O&M practices and internal management capacity have resulted in the long-term benefits from past R&M being unsustainable. Most state government generators, with a few exceptions, have very poor capacity in terms of skills for operating and maintaining plants.

g. General financial distress of state power utilities. The poor financial situation in the state power sector results in limited debt servicing ability. Available financing usually gets used to firefighting, ad-hoc investment or politically motivated schemes instead of schemes with long payback and short-term costs, i.e., R&M. Even when R&M is financed, usually the lowest capital expenditure option is considered first.

II. BUSINESS-AS-USUAL SCENARIO

5. In the Business-as-Usual scenario, the barriers to R&M interventions in state-owned power generation utilities in India would continue to impede wider implementation of R&M projects. Table 16.1 indicates that there is a need for rehabilitation of nearly 27,000 MW of old coal fired units during the XI Plan Period (2007-12). It shows that nearly 16,000 MW of R&M target for X Plan period (2002-07) – of which about 8,000 MW was in the state sector – could not be implemented and spilled over to the XI plan period. Even during the XI plan period there has been little movement towards implementation of targeted R&M interventions outside the IBRD-GEF and KfW projects, especially in the state sector.

6. The perception that R&M projects are difficult to design and implement, and entail very high risk would persist in the absence of any concrete attempts to develop and demonstrate approaches that systematically mitigate risks. As a result, while some state generation utilities may take up a few R&M interventions, by far the need for R&M in India would remain unaddressed.

145

Table 16.1: Need for Rehabilitation of Old Coal Fired Units during XI Plan Period (2007-12)

Size of unit <100 MW

100~200 MW

200~210 MW

500 MW

Total MW

Spillover from X Plan Period NTPC (including DVC) 0 0 3880 4000 7880State Generation Utilities 194 1480 5400 1000 8074TOTAL 194 1480 9280 5000 15954Additional Rehabilitation for XI Plan Period NTPC 0 800 2910 3000 6710State Generation Utilities 193 760 3320 0 4273TOTAL 193 1560 6230 3000 10983Total Rehabilitation Requirement for XI Plan Period NTPC 0 800 6790 7000 14590State Generation Utilities 387 2240 8720 1000 12347GRAND TOTAL 387 3040 15510 8000 26937

Source: Data collected from Central Electricity Authority Note: (i) Spill-over includes works that were initiated but could not be completed within the X Plan.

(ii) NTPC follows a rolling plan for R&M and although a large spillover is indicated here, significant works have been completed within the X Plan period.

7. Historically R&M activity carried out by state sector generators in India focused on PLF enhancement and life extension but not on energy efficiency. Due a host of barriers discussed above this situation is not likely to change in the future unless a concerted effort is made to demonstrate a comprehensive barrier reduction framework and implementation of EE R&M within the same. It is assumed that in the baseline scenario progress of even traditional R&M activities (which lack a focus on Energy Efficiency) will be limited, and adoption of EE R&M schemes will not take place.

8. Therefore, the Business-as-Usual scenario is characterized as: � Low investments in R&M projects in state-utility sector. � Even where R&M is undertaken, it would be mainly focused on enhancing plant load

factor and life extension, rather than energy efficiency. Also, after R&M these generation units would again gradually creep back to lower levels of performance due to poor operations and maintenance practices.

� Also, these Investments would be affected by barriers and higher project risks mentioned above leading to significant delays and lower probability of success and commensurate non-achievement of targeted benefits.

� Due to prevailing power shortages, most of the old generation units would continue to generate at a low level of energy efficiency and higher levels of greenhouse gas emissions. Also, these generation units would provide lower levels of generation due to frequent outages.

� Generation units which have not been rehabilitated (despite the need for it), would experience continued deterioration of equipment, with decreasing load factors, increasing heat rates, and increasing costs of generation.

146

III. GEF PROJECT ALTERNATIVE

9. The GEF alternative is focused on taking measures to address barriers to EE R&M projects, developing approaches to mitigate inherent project risks and initiating steps towards a wider EE R&M program in the country. The IBRD-GEF project would achieve this through pilot interventions in three states across coal fired generation units of 210MW and 110MW. These pilot projects would demonstrate approaches for energy efficiency focused R&M, while developing steps for mitigating risks and addressing barriers. Further, to enhance the momentum for a wider R&M program, a pipeline of EE R&M projects would be developed. The implication of this GEF Project Alternative is that the state generators will implement EE R&M activities – both due to the direct financing of demonstration projects under the Project, as well as from other sources of financing once successful EE R&M demonstration projects within a comprehensive barrier reduction framework are available for dissemination.

10. Project Components The project will have the following components: (i) Energy Efficiency R&M Pilots (US$295.9 million) and (ii) Technical Assistance (US$7.5 million). The project will be financed by a combination of an IBRD loan, GEF grant and generation company internal (equity) funds. GEF funds in the investment component would be used for funding the incremental cost of energy efficiency approaches in R&M. The financing plan is provided in the table below.

Table-16.1: Financing Plan

Financing Plan Component Indicative Costs GEF IBRD Equity Total

Energy Efficiency R&M Pilots 295.9 37.9 180.0 78.0 295.9 Technical Assistance 7.5 7.5 - - 7.5 Total 303.4 45.4 180.0 78.0 303.4

All figures in US$ million

11. Component 1: Energy Efficiency R&M Pilots (US$295.9 million). This component would renovate and modernize 640 MW (three to four generation units) of old coal-fired generation capacity to test and demonstrate energy efficient rehabilitation approaches. Energy efficient R&M of generation units would go beyond the typical Indian practice - of restoring original generation capacity, life-extension, and improving availability - by also modifying (or replacing) some equipment and systems to enable the unit to operate with higher fuel efficiency.

12. The Bank and GOI have agreed to focus on 110 MW and 210 MW units which are in urgent need for R&M in India and constitute about 68% of the 27,000 MW identified for R&M. The following generation units have been selected for participation in the pilot project:

• Unit-5, Bandel Thermal Power Plant, West Bengal (210 MW) • Unit-6, Koradi Thermal Power Plant, Maharashtra (210 MW) • Units-3 & 4, Panipat Thermal Power Plant, Haryana (110 MW each)

13. This component of the IBRD-GEF project incentivizes generation plants to work with the Bank team to develop demonstration EE R&M projects within a comprehensive barrier reduction

147

framework, while addressing the incremental costs of EE R&M approaches. Less efficient thermal power plants would be turned around resulting in significant improvements in heat rate and plant load factor (PLF) resulting in less coal consumed, less GHGs produced, and a lower cost of generation.

14. Component 2: Technical Assistance (US$7.5 million). The technical assistance component of the project is aimed at: (i) design of Energy Efficiency R&M projects, (ii) implementation of demonstration EE R&M investments funded under Component 1 of the project, (iii) measures to address barriers to replication of EE R&M projects in India, and (iv) strengthening of overall institutional capacities of the generation utilities and other relevant sector entities.

15. Sub-component-2 of the project would finance Energy Efficiency R&M design of 840 MW of additional capacity in Maharashtra, thus creating a pipeline of such projects. In addition to this the Bank has received an intimation of EE R&M of six 210 units in Gujarat. It is therefore expected that this intervention / project would lead to implementation of EE R&M approaches in at least 2100 MW (11%) of 18360 MW of old 110MW/210MW capacity in the country.

16. Under the GEF alternative, the following steps are envisaged for mitigation of barriers to EE R&M in state generation utilities in India:

Barrier Measures contemplated

Energy Shortages. Due to the prevailing generation shortage in the country, and the relatively low cost of generation from old plants (since these are fully depreciated), utilities find it difficult to take old generation units out for major R&M. Taking plants off-line for longer periods of time to do major work is politically risky and economically damaging.

� The project aims to reduce the plant outage to the minimum possible by conducting detailed RLA & Energy Audit studies of the plant to minimize surprises at the time of opening the machines.

� Detailed design studies of the plant also enable to systematically plan the shutdown and ensure that all the required equipments are available at the time of shutdown. Detailed studies would also help reduce the risk of surprises on opening of machines.

� Possibility of short term allocation of power supplies from GOI’s unallocated share of 15 percent of total central sector generation is being explored with GOI with a view to encourage EE R&M.

Regulatory issues. There is little regulatory incentive to invest in R&M, even as there is uncertainty whether full R&M capital expenditure will be passed through in generation tariff. In the prevailing cost-plus tariff regime, it is likely that benefits of the R&M investment would be passed through entirely to the customers by means of generation tariff reduction. Even though the National Tariff Policy announced in 2006

� As a part of the project, a study on options for regulatory treatment of R&M projects has been undertaken with funding from ESMAP. The study has been conducted in close coordination with several state electricity regulators. The findings of the study have been disseminated through a workshop. (see Annex 1)

� Capacity building measures under Technical Assistance include support to generators and regulatory staff on regulatory aspects of R&M.

148

provides for a multi year tariff framework to cover inter-alia the capital investments necessary for R&M, and suggests sharing of benefits of efficiency improvements, the modalities for implementing the same remain unclear.

� The team would continue dialogue with GOI on implementation of relevant provisions of National Tariff Policy, 2006.

General financial distress of state power utilities. The poor financial situation in the state power sector results in limited debt servicing ability of the companies. Available financing is usually consumed in fire fighting or inadequately planned schemes instead of schemes with long payback and short-term costs, such as R&M. Even when R&M is financed usually the lowest capital expenditure option is considered first.

� The project does not directly address the financial distress in the power sector. However, each sub-project proposed for financing will be subject to financial and economic appraisal wherein eligible projects will have to demonstrate adequate financial viability including future O&M budgets.

� With efficiency increases resulting from EE R&M and a part of the resulting benefits being passed to the generation utilities, the financial health of these utilities would be strengthened.

� As part of the Project a Financial Management Plan was prepared which aims at improving the financial management performance (corporate governance, financial accountability aspects) of the clients.

Lack of energy efficiency orientation. In the past Indian generators and the Indian government system had been primarily concerned with improving availability, life extension and capacity enhancement in designing rehabilitation of coal fired generation units. There has been little focus on energy efficiency improvement, in part attributable to the administered pricing (till mid-90s) and relative abundance of coal in India. This tendency has also been enhanced by PLF linked performance monitoring and incentives rather than heat rate linked incentives. However over the last few years GOI is laying emphasis on improving energy efficiency in power generation.

� The project requires measurement of energy efficiency performance and incorporation of energy efficiency as a primary criterion for R&M project design

� The team proposes to work with the Central Electricity Authority to incorporate energy efficiency parameters in the regular reporting requirements of all generators.

Inadequate O&M practices and internal management capacity. Most state government generators, with a few exceptions, have weak capacity in terms of skills for operating and maintaining plants. This has resulted in the long-term benefits from past R&M being unsustainable. Measurement and monitoring systems prevalent are outdated and often highly inadequate. Accountability for performance in this environment is generally low.

� Under ESMAP funding the Bank has hired consultants for BTPS (West Bengal) and KTPS (Maharashtra) for strengthening the current O&M practices and procedures. A similar study is proposed for PTPS (Haryana). It is also proposed to hire additional consultants to implement the recommendations. These will be funded with TA resources.

� In addition, the M&E system to be put in place by this project will improve accountability.

149

� The Partnership for Excellence program addresses this by requiring under performing generators to work with NTPC (and other strong generators) to improve their O&M practices before design of R&M project and sanction of financing.

Lack of long-term financing for R&M. The Capital Expenditure for R&M needs to be managed in such manner as to reduce the short-term increase in power cost from the generator. However, the financing traditionally available for R&M has been of relatively short tenor of up to 7 years thereby increasing the cash outflows of the generators and hence their tariff requirement.

� Demonstration of EE R&M approaches and sustained improved performance of plants under long term funding from the World Bank would allow local financial institutions and other international agencies to offer better long-term funds

Policy barrier to energy efficiency. While there has been a general recognition of the importance of R&M investments there has not been a comprehensive policy thrust for R&M in the past. Recently the National Electricity Policy (2005) and the National Tariff Policy (2006) have made appropriate enabling provisions to allow development of comprehensive regulatory and financing frameworks.

� Bank, in its dialogue with GOI, highlighted the fact that the thrust on ensuring energy efficiency as an important criterion in R&M project design needs to be increased.

� An agreement has been reached that the Project will demonstrate the framework and modality of doing the same and will work closely with states for timely and satisfactory implementation.

IV. CALCULATION OF GHG BENEFITS

17. The GEF Manual for calculating GHG benefits has been followed. As per the manual, emission reduction from GEF interventions has three components: (i) Direct Emission Reductions, (ii) Direct Post Project Emission Reduction Effects, and (iii) Replication and Indirect Impacts.

Direct Emission Reductions

18. These have been calculated for the three generation units where the IBRD-GEF supported investments in EE R&M are being undertaken. The project involves phased implementation of EE R&M activities in the three states, starting with Bandel Unit-5, followed closely by Koradi Unit-6 and finally Panipat Units 3&4. At present, the detailed project report (and the technical specifications) for EE R&M of Bandel Unit-5 have been prepared, while those for Koradi Unit-6 are still in draft and are in the process of finalization. The preparation of detailed project report for Panipat Units 3&4 would be initiated in the next few months. Therefore for Bandel Unit-5 the calculations are based on the actual numbers from the approved detailed project report (DPR) but for Koradi Unit -6 the calculations are based on a draft DPR. In case of Panipat Units 3&4 the calculations are done on the basis of past performance recorded by the plant authorities and conservative assumptions are taken about Post-R&M performance.

150

Table 16.2 - Key Data Capacity

(MW) Plant Load Factor (%)

Station Heat Rate

(KCal/KWh)

Age (years)

Before R&M

Post R&M

Before R&M

Post R&M

Before R&M

Post R&M

Bandel Unit- 5 27 210 215 67% 85% 2872 2500 Koradi Unit-6 27 210 214 72.2% 85% 2951 2600 Panipat Unit-3 24 110 115 77.7% 85% 3465 2850 Panipat Unit -4 22 110 115 67.4% 85% 3467 2850

Note- The post R&M figures are indicative and will be confirmed on the basis of actual performance of the units. 19. The renovation and modernization of coal fired generation units would lead to improved energy efficiency as well as a higher amount of power generation due to increased capacity and improved load factor. To facilitate the calculation of direct emission reductions, the emission reduction (or increase) has been broken down into two parts:

A. Emission Reduction from Present Level of Coal Consumption

20. With improved energy efficiency, more electricity can be generated from the same amount of coal. In case the EE R&M project was not undertaken, this additional electricity generated from the same amount of coal would have been provided from new sources of generation connected to the grid – including coal-fired, gas-fired, lignite-fired, large hydropower, nuclear and renewable energy projects. Therefore, this additional generation avoids emissions from a combination of these sources.

21. Some of the parameters used in calculating emission reduction from the above are as follows:

• Annual electricity generated - Keeping the consumption of coal constant, the annual additional electricity generated due to the reduction in Unit Heat Rate, is calculated.

• Emission Factor- The additional energy generated using the same amount of coal would substitute generation from a mix of grid connected generation sources based on the planned new power generation projects. Emission Factor for the planned new generation projects is the future build margin for the grid, which is calculated based on the list of green-field projects under execution and the CO2 Emission Factors provided in Central Electricity Authority (CEA) - CO2 Baseline Data for Indian Power Sector Version 4. Underlying calculations are presented in Annex-1 of this document. The future build margin emission factor for the national grid is calculated as 0.77 t CO2 e / MWh.

• Average Useful Investment Lifetime- This is the residual life of the unit if the unit was not rehabilitated. For the units being rehabilitated under the IBRD-GEF project, the residual life without rehabilitation is as follows:

o Bandel Unit 7 years o Koradi Unit 7 years

151

o Panipat Unit 3&4- 10 years

B. Emission Reduction / Increase from Additional Coal Consumption: 22. Because of increase in the capacity and improved plant load factor, the overall generation from the unit may be more than the generation possible from using the same amount of coal, thus leading to combustion of even more coal than earlier. Emission from this additional generation that requires additional coal to be burnt should be compared with emission from new generation capacities connected to the grid – including coal-fired, gas-fired, lignite-fired, large hydropower, nuclear and renewable energy projects. The emission reduction (or increase) for this part would be based on the difference in emission factors for the rehabilitated plant and the future build margin for the gird.

23. It may be noted here that in some cases, the generation unit may already be operating on a high load factor generating close to the maximum possible levels. In such a case, there may be a net saving of coal from the unit (additional generation through additional coal consumption may be negative).

24. Some of the parameters used in calculating emission reduction / increase from the above are as follows:

• Annual electricity generated- The additional electricity generated through the additional coal consumption is calculated as the difference between generation from the unit based on the post-R&M load factor and the part of generation attributable to existing level of coal consumption.

• Emission Factor- The emission factor in this case is the difference between the future build margin emission factor for the national grid and the Post R&M emission factor for the generation unit.

• Average Useful Investment Lifetime- This is the residual life of the unit if the unit was not rehabilitated.

o Bandel Unit 7 years o Koradi Unit 7 years o Panipat Unit 3&4- 10 years

Direct Post Project (DPP) Emission Reduction Effects

25. In this project there is no GEF -supported financing mechanism that will continue to support direct investments after the implementation or supervision of the project. Therefore no DPP emission reduction effects have been calculated for this project.

Replication and Indirect Impacts

Bottom- up Approach 26. The GEF TA money is being used to develop a pipeline of replication projects (840 MW) - two units in Chandrapur, one unit in Bhusawal and one unit in Parli - all of them in Maharashtra. There is also an intimation of another 1260 MW in Gujarat of being added to the pipeline. Together, it is expected that at least 2100 MW of follow-on activity would take place. Thus the Replication Factor of 3 is used for calculation (~2100/640).

152

Top- down Approach 27. Total market for coal fired generation rehabilitation is about 27,000 MW, which would be captured over a ten year period. Of this 210 and 110 MW units account for about 68% or 18360 MW.

28. Given the fact that during the tenth plan the GOI could only implement less than a third of the planned R&M target, it can be safely assumed that in the absence of this project the share of EE R&M in the total R&M activity would have been limited and the target for R&M activity would not been achieved. Also keeping in mind that investments in R&M projects are expected to gain momentum in the coming years, we assume that the average share of EE R&M investments in the baseline in the 10 year period that needs to be bridged is 60%. Further, because of the phased-out implementation of R&M, the rehabilitated units would only function during the later part of the 10 year period – thus we assume that only 50% of the emission reduction takes place in the ten year period. Therefore, the total emission reductions from EE R&M of 210 and 110 MW units would be 31.72 million tonnes of CO2 (60% x 50% x 18360 MW x 3.69 MTCO2 / 640 MW).

29. Assuming a GEF causality factor of 40% i.e. the GEF contribution is modest and substantial indirect emission reduction can be attributed to the baseline, the indirect emission reduction through the Top down approach amounts to 12.69 million tonnes.

Results

Table 16.3 - Emission Reductions

Replication & Indirect Impacts Direct Direct Post Project

Bottom-Up Top-Down

Bandel Unit 5 0.64 0 Koradi Unit 6 0.78 0 Panipat Unit 3 1.46 0 Panipat Unit 4 0.81 0

11.06 12.69

Total 3.69 0 11.06 12.69 Figures in million tonnes of CO2

30. Direct Emission Reductions Part of the outputs of the project will be the following investments: Financing the incremental cost of energy efficiency approaches in Renovation and Modernization of 640 MW of old Coal Fired Generation Capacity. These investments will result in direct greenhouse gas emission reductions during the project’s implementation phase. As a result of these activities during the project implementation period of: Seven to Ten years across different units, direct greenhouse gas emission reductions totaling 3.69 million tonnes of CO2 eq will be achieved over the useful lifetime of the investments of seven years. In the non-GEF case, these energy needs would be satisfied by: Supply from the grid where the build margin calculated based on green field power generation projects planned over the next five years is 0.77 t CO2 e / MWh.

153

31. Indirect Emissions Reductions Using the GEF bottom-up methodology, indirect emission reductions attributable to the project are 11.06 million tonnes of CO2 eq. This figure assumes a replication factor of 3.0, which is consistent with the EE R&M projects already in the pipeline. Using the GEF top-down methodology, indirect emission reductions attributable to the project are 12.69 million tonnes of CO2 eq. This figure assumes that total technological and economic potential for GHG emission reductions in this area over 10 years is 31.7 million tonnes of CO2 eq, and a project causality factor of 40 percent.

VI. INCREMENTAL COST AND BENEFIT ANALYSIS

32. Incremental Project Benefits The project would lead to domestic benefits as well as global environmental benefits. It would demonstrate approaches for mitigating inherent risks in EE R&M interventions, thus paving the way for a larger EE R&M Program in the country. The project is a win-win approach for augmenting availability of power with lower investments than green-field projects, reducing requirement of coal for generation and reducing carbon dioxide emissions.

Incremental Cost-Benefit Matrix

Baseline GEF Alternative Increment

BENEFITS Domestic Benefits

a. Interventions to address the need for R&M of old coal fired power generation units

• Barriers continue to impede wider implementation of R&M projects

• R&M projects are perceived as high risk and reluctance to engage in such interventions persists. (As a result utilities did not demonstrate enough appetite for an IBRD only engagement, as also for an ADB engagement in the past).

• Little movement towards preparation and implementation of R&M projects in state-utilities in India.

• Several gaps in

preparation of R&M projects leading to high risks in implementation phase.

• Barriers are systematically addressed through studies, sector dialogue and capacity building.

• GEF grant supported Pilot EE R&M interventions for 640MW of capacity across 210 MW and 110 MW units to demonstrate approaches for reducing risks for effective implementation of EE R&M interventions.

• R&M Interventions in

state-utilities in India are kick-started through pilot interventions (640 MW) and pipeline interventions (840MW).

• Systematic approaches for mitigation of project risks are developed and demonstrated through pilot interventions.

• Reduced barriers to EE R&M leading to initiation of R&M preparation activities for at least 2880 MW from IBRD-GEF and other sources.

• Risk mitigation strategies (such as comprehensive technical studies, effective procurement practices, strategies to handle surprises etc) are developed and demonstrated through pilot interventions.

b. Energy Efficiency of old • Generation units continue • Energy efficiency is • Heat Rate improvement of

154

Baseline GEF Alternative Increment coal fired power generation units

to operate at lower levels of energy efficiency.

improved through specific technological interventions, and sustained through improved operations and maintenance practices.

12 to 18% across selected pilot generation units.

c. Generation from old coal fired power generation units

• Generation units operate at a load factors between 67% and 77%

• Generation units have rated capacity of 210 MW or 110MW

• Residual life of 7 years or 10 years for different units. However, given power shortages it is unlikely that these units will be relinquished even at the end of such period.

• Generation units operate at a load factors between 85% and 90%.

• Generation units are up-rated to capacity of 214~215 MW or 115 MW.

• Extension of life of generation unit to 15 years or 20 years. Energy efficient operations of units during the extended life.

• Additional power of at least 948 MU(24% increase) per annum would be available across the three pilot power plants.

Global Environmental Benefits

Reductions in Green House Gas (GHG) (Carbon Dioxide) emissions from power generation units

Minimal or no energy efficiency improvements / GHG reductions at old state-utility owned coal fired power generation units

Reductions in GHG based on efficiency improvements at thermal stations.

15.6 million tons of carbon dioxide reduced across pilot and pipeline interventions.

COSTS (million USD)

COMPONENT-1 Expenditure Investment in Energy Efficiency R&M Pilots

256.3*

295.9

39.5

Funding Sources IBRD Loan Other Loans Equity GEF Grants

0.0

179.4 76.9

0.0

180.0

0.0 78.0 37.9

0.6 0.0 1.1

37.9 COMPONENT-2 Expenditure (i) Technical Assistance (ii) Investments in Pipeline R&M Interventions

0.0 0.0

7.5

430.0

7.5

430.0

Funding Sources IBRD Loan Other Loans Equity GEF Grants

0.0 0.0 0.0 0.0

0.0

301.0 129.0

7.5

0.0

301.0 129.0

7.5 TOTAL Expenditure (i) Technical Assistance (ii) Investments in R&M Interventions

0.0

256.3

7.5

725.9

7.5

430.0

Funding Sources IBRD Loan Other Loans

0.0

179.4

180.0 301.0

0.0

301.0

155

Baseline GEF Alternative Increment Equity GEF Grants

76.9 0.0

207.0 45.4

129.0 7.5

TOTAL GEF COSTS (million USD) Technical Assistance 0.0 7.5 7.5 Coal R&M Energy Efficiency Financing Window

0.0 37.9 37.9

GEF Incremental Costs 45.4 * Although some investments in R&M would have happened even without the IBRD-GEF intervention, as explained in the benefits section of the above table, such interventions would have been relatively few and may have been subject to barriers and higher project risks leading to lower probability of success and commensurate non-achievement of targeted benefits. 33. Incremental Cost-Benefit of Energy Efficiency Pilots Based on a GEF Grant of US$37.9 million for the energy efficiency financing window, the energy efficiency R&M pilots are expected to require US$295.9 million in investments for 640 MW capacity. Overall, this financing window will result in reduction of heat rate of selected pilot generation units by 12% to 18%, and there by the same reduction in Carbon Dioxide emission intensity of generation from these units. The absolute Carbon Dioxide emissions from these units would reduce by 3.69 million tonnes. The project would lead to additional generation of power of 948 million kWh per annum.

34. Leveraging of GEF Funds. The GEF funds would be used to support more than US$295.9 million in coal-fired power generation unit efficiency improvement investments representing a ratio of 7.8:1 (expected investments to net grant) over the implementation period of the project. However, given that a second generation of investments (US$ 430 million for pipeline interventions) is likely to be made once the pipeline positive results are proven at stations with R&M investments, along with increased commercial lending; total leverage of GEF funds would be significantly higher at almost 16:1.

35. Grant Cost Effectiveness. The net cost of carbon abatement for the project is a direct result of the leverage provided by the GEF grant. Grant cost effectiveness in terms of the direct emissions from the project is calculated as $10.27/ton of CO2e, whereas the grant cost effectiveness taking into account both direct and indirect emission reductions is calculated at about $2.91/ton of CO2e.

156

Annex 17: STAP Review and Responses

INDIA: COAL FIRED GENERATION REHABILITATION PROJECT

(STAP Review undertaken in May 2006, 62 Team’s response updated in March 2009)

The STAP review comments received at work program inclusion have been taken into account in the preparation of the Project Appraisal Document. Specific comments and responses (at appraisal stage) are provided below: 1. Comment: It is not clear whether the project as a part of the Partnership in Excellence (PIE)

program would involve NTPC (formerly National Thermal Power Corporation) to conduct diagnostics (energy audits?) and provide technical assistance, and Power Finance Corporation (PFC) to provide financing. If not, what would be the financing mechanism: a separate account (a dedicated Fund) for this project? If so, how would commercial lenders participate in individual projects or in the overall Fund?

Response: Under the Partnership in Excellence (PIE) program, coal-fired power plants with poor plant load factors (less than 60 percent) partnered with stronger utilities such as NTPC to improve performance through adoption of better management systems and Operations and Maintenance (O&M) practices. The program experienced mixed success with some utilities such as DVC benefiting significantly, but some others showing little sustained improvement. One of the objectives of the PIE program was to assist the weak utilities in preparation and implementation of R&M activities. However, due to absence of adequate performance incentives, utility financial constraints and inter-institutional issues, the program did not continue further enough in promoting R&M of old units.

At the time of GEF Project Brief submission, the team in intensive discussions with NTPC to explore its involvement in IBRD/GEF supported EE R&M project for state-level power generation units. However, NTPC has a joint-venture with ALSTOM called NTPC ALSTOM Power Services Private Limited (NASL), which had been created specifically to enhance the R&M interventions in India. In face of the possible conflict of interest situation, and in view of already low levels of competition for R&M in India, the Bank team preferred that NASL participate as a potential supplier, rather than involving NTPC for support on IBRD-GEF project.

In preparing this project, the team also explored the option of channeling IBRD/GEF funds through an intermediary such as Power Finance Corporation (PFC). However, GOI rejected this option as a result of an unsatisfactory response from state generation utilities to a similarly structured ADB project. Therefore, it was decided to shift to the standard mechanism of on-lending to state generators through the government system, so as to lower transactions costs and be more hands-on with regard to issues such as project and technical design, incorporation of energy efficiency approaches, procurement strategy, implementation support, and transferring lessons learned for a wider national program.

62 STAP review comments in May 2006 provided by Gautam S. Dutt. The team’s responses at that stage were included in the Project Brief for Work Program Submission. The same have now been updated at the project appraisal stage.

157

Apart from the EE R&M interventions directly funded by the IBRD/GEF project, a pipeline of additional EE R&M interventions is being developed under the project, which would be financed from sources outside the current project.

2. Comment: The level of efficiency increase actually achieved in current R&M projects in

India (which do not focus on energy efficiency) should be brought out and compared with the expected level of energy efficiency improvement to be achieved in the proposed project. Also, how does the proposed project compare with alternatives such as new high-efficiency coal power plants or new combined cycle gas power plants, and the option of scrapping the worst power plants altogether and replace them with new high-efficiency coal or natural gas power plants? The economic analysis should compare at least these three alternatives to the project scenario and doing nothing.

Response: The team agrees with the suggestion. The Detailed Project Reports (DPR) for each of the EE R&M interventions under the project would capture various options and provide a techno-economic evaluation of these options, including scenario analysis to examine the impact of risks under each option. The options being considered include: (i) No R&M case; (ii) EE R&M; (iii) Replacement of Boiler-Turbine-Generator; (iv) Scrap the unit; and (V) Complete Replacement. In addition, various technical options for carrying out the R&M intervention (including approaches specifically focused on energy efficiency– such as removal of Bauman Stage in Low Pressure Turbine, conversion of High Pressure Turbine from Impulse to Reaction Blades etc.) have been examined in the DPRs from a techno-economic perspective.

3. Comment: Since the project has a large and cost effective replication potential, GEF is a better instrument than alternatives considered and rightly rejected in Section B6, as it provides focus on barrier reduction rather than subsidies or specific incentives. Experience with other GEF projects has shown that technical assistance alone without associated financing is not effective. Moreover, carbon financing such as the Clean Development Mechanism, is project oriented addressing one power plant at a time, and does not lead to effective barrier removal.

Response: The team agrees with the observations. 4. Comment: As regards the barriers to energy efficient R&M identified in the Project Brief,

these are correct and the mitigation measures also appear to be reasonable. One possible weak area is the lack of long-term financing for R&M activities. It is rightly noted in Annex 1 that a successful implementation of the proposed activities would provide the basis for future financing through commercial sources. Improved financing would also result from Tariff Reforms which would improve the financial status of state power companies.

Response: The IBRD/GEF project would assist in preparation of EE R&M for 1440 MW of capacity across eight coal-fired power generation units in three states, of which R&M of 640 MW capacities would be funded under this project, while the remaining would be funded from sources outside this project. Activities under the project have contributed to a renewed interest in R&M interventions and several bilateral agencies are now looking at opportunities for funding R&M interventions in India. In particular, KfW has taken up another seven generation units (about 1400 MW) for EE R&M preparation and is likely to fund at least

158

three of these units. The success of first few pilot interventions under the IBRD/GEF project is likely to pave the way for more commercial financing of such projects.

5. Comment: The monitoring parameters and process indicated in Annex 3 appear to be excellent.

Response: The results framework presented in Annex-3 of the Project Brief has now been modified to bring out baseline and target values specific to the selected coal-fired power generation units. The revised results framework has been included in Annex-3 of the Project Appraisal Document.

6. Comment: As regards the identification of global environmental benefits, the incremental

cost of mitigation (GEF investment per tonne of CO2 emissions reduction) considering only the direct benefits from EE R&M Financing Component (the benefits from Technical Assistance component being inherently speculative) is estimated to be about $6 per tonne CO2, which is quite cost effective compared to many alternative mitigation options. In general, the Incremental Cost Analysis shown in Annex 15 is clear and appears to be correct.

Response: The incremental cost of mitigation (GEF investment per tonne of CO2 emissions reduction) considering only the direct benefits from EE R&M Financing Component has been revised and is now estimated to be about $10.27 per tonne CO2 over the remaining useful life of existing generation unit (7-10 years for different units). The incremental cost of mitigation for the direct and indirect benefits taken together, using the standard GEF methodology, is found to be $3.08 per tonne, which is quite cost effective compared to many alternative mitigation options. The revised incremental cost analysis is presented in Annex-17 of the PAD. The key change in the analysis is the more accurate assessment of Baseline scenario (without GEF intervention) and calculation of incremental cost and emission reductions as per the GEF methodology.

The team would like to point out that during the course of project preparation (since May 2006), it was seen that due to barriers to EE R&M, there has been little movement on initiation of new R&M activities for generation units outside the IBRD-GEF and KfW projects, despite a large target for R&M during the XI plan period (2007-12). Therefore, the baseline case for estimation of incremental cost of mitigation is taken as No R&M (old generation units continue to run with poor heat rates and therefore high emissions), rather than Usual R&M (without focus on Energy Efficiency) as taken at the Work Program submission stage.

7. Comment: The project fits very well within the context of GEF goals, specifically through its Operational Program 5: Removal of Barriers to Energy Efficiency and Energy Conservation. The project also incorporates strategic priorities CC-2 (Increased access to local sources of financing for renewable energy and energy efficiency) and CC-3 (Power sector policy frameworks supportive of renewable energy and energy efficiency).

Response: The team agrees with the observation.

8. Comment: As regards replicability of the project, the experience to be gained through the project should be very valuable to other power plant owners and operators in various Indian states. The total estimated market of the Partnership for Excellence program is stated to be

159

3960 MW, showing that there is at least a five-fold potential for replication. As regards sustainability of the project, energy efficiency improvements in coal-fired power plant R&M, is shown to be reasonably cost effective.

Response: The team agrees with the observation.

9. Comment: As regards linkages to other focal areas, the type of project activity would have no significant adverse effect on other GEF focal areas or in land degradation.

Response: The team agrees with the above observation.

10. Comment: As regards other programs at the regional/sub-regional levels, there are no prior GEF programs involving energy efficiency improvements in electric power generation in India. There have been two projects involving end-use efficiency improvements that are not relevant to the proposed project. Since India is a region by itself, no linkage to other GEF programs in sub-continent is required for the success of the proposed project.

Response: The team agrees with the above observation. 11. Comment: The Clean Development Mechanism is another source of technology transfer for

climate change mitigation projects. There are no registered CDM projects so far involving energy efficiency improvements in coal-fired power plants in India or anywhere else. Indeed there are no approved baseline and monitoring methodologies (so far) that would allow such projects to be registered under the CDM. The only methodology for power plant efficiency improvements is ACM007: Conversion from single cycle to combined cycle power generation, applicable to natural gas power plants. Indeed, CDM favors other types of projects, and is unlikely to be a major source of financing for the type of activities covered by the proposed project. Thus GEF support is highly relevant.

Response: The team agrees with the above observation. 12. Comment: There is another project with very similar objectives to the proposed project. This

is the so-called “Efficient Power Generation (Greenhouse Gas Pollution Prevention [GEP] Project)” supported by a $12 million grant from USAID, plus supplementary funding from Indian sources. The project is administered by the Centre for Power Efficiency and Environmental Protection (CENPEEP) of NTPC. The objectives are similar to Component 1 of the proposed GEF project. Though the potential beneficiaries of the proposed project are state power utilities, a great deal can be learned from the experience of CENPEEP GEP project and should be incorporated into the design of the implementation program for the proposed project. Note that there is no mention of CENPEEP in the current version of the GEF project brief.

Response: The Bank team has held discussions with USAID and CENPEEP and the lessons from the GEP project are reflected in the Project document. The GEP project aimed at improving efficiency and heat rate of coal-fired generation primarily through use of advanced instrumentation for optimizing operations and maintenance (O&M) practices. However, use of the techniques and practices promoted by CENPEEP require generation plants to have a minimum O&M performance level and an energy efficiency orientation. The IBRD/GEF project targets poor performing plants where the performance needs to be improved to a basic

160

minimum level with capital investment and capacity building before advanced optimization for energy efficiency can be used. It is planned to leverage CENPEEP expertise (or similar expertise available with other agencies) during the implementation of O&M Action Plan for the three utilities.

13. Comment: As regards other beneficial or damaging environmental effects, the project

should have no damaging environmental effects. Indeed, local air pollution should decrease as a result of cleaner combustion or better treatment of exhaust gases from the power plants.

Response: The team agrees with the above observation.

14. Comment: As regards degree of involvement of stakeholders in the project, particularly with the objective of addressing barriers to energy efficiency improvements in power plant renovation and modernization, getting input from state power companies and other intended beneficiaries would be an important part of learning how to break down the barriers identified. In this regard, a survey of the perceptions of potential beneficiaries as part of the “Technical and Policy studies”, conducted early in the project would help improve the implementation plan.

Response: A substantial amount of consultation has been carried out with various sector stakeholders including Central Electricity Authority, NTPC, central and state regulatory commissions, state generation utilities, consultants, and equipment manufacturers which has now been reflected in the Project Appraisal Document. Extensive interaction has also taken place with GOI, CEA, NTPC, state generators and the Bank on the barriers affecting R&M in India. A two day workshop involving state level generators, NTPC, GOI and state governments was conducted by the Bank in September 2005 to identify barriers to R&M in India and possible ways to address barriers. Subsequently, workshops have also been organized by Eco-Asia-USAID and KfW (in collaboration with the Bank team) where specific challenges affecting R&M projects were discussed. Strategies to address barriers are discussed in the PAD in Annexure-4 and Annexure-15 of the PAD.

15. Comment: One of the generic barriers to energy conservation and efficiency is lack of trained personnel and technical and managerial expertise. The proposed technical assistance and capacity building component is an important aspect of the project and the brief description of this component in Annex 4 appears to be adequate.

Response: The team agrees with the above observation. Also, by the appraisal stage, the technical assistance component has been further strengthened and defined more clearly. It now includes (i) support for R&M design and safeguard studies for pilot interventions (640 MW)and pipeline interventions (840 MW), (ii) implementation support and quality assurance consultancies for pilot interventions; (iii) support through the Central Electricity Authority (CEA) for addressing barriers to energy efficient R&M; and (iv) strengthening capacities in implementing utilities as well as the CEA. In addition, several R&M preparation studies, barrier reduction studies and sector dialogue are already underway (or completed). These include R&M Design studies for Unit-5 Bandel and Unit-6 Koradi; Study of Regulatory Aspects of R&M; and Study of Operations and Maintenance practices at Bandel and Koradi Power Plants.

BULD

HA

NAJALGAON

JALNA

AURAN-GABAD

THANE

NASHIK

DHULE

BEED

SOLAPURSATARARATNA

GIRI

PUNE

RAIG

ARH

AHMADNAGAR PARBHANI

NAN

DED

LATUR

SANGLI

KO

LHA

PUR

SINDHUDURG

CHANDRA-PUR

GA

DH

CH

IRO

LI

NAGPUR

YAVATMAL

AMRAVATI

AKOLA

WARDHA

WASHIM

HINGOLI

NANDURBAR

GONDIA

DHARASHIV

BHANDARA

0 50

0 50 100 Miles

100 Kilometers

MAHARASHTRA

BHIWANI

SIRSA

HISAR

FATEHABAD

JIND

KURUKSHETRA

SONIPAT

ROHTAK

JHAJJAR

AMBALA

PANCHKULA

YAMUNA-NAGAR

PANIPAT

KAITHAL

REWARI

KARNAL

GU

RGA

ON

FARI

DA

BAD

MA

HEN

DRA

GA

RH

0 25

0 25 50 Miles

50 Kilometers

HARYANA UTTARDINAJPUR

DAKSHINDINAJPUR

B I R

BHU

M

BARDDHAMAN

JALPAIGURI

KOCHBIHAR

DA

RJILI

NG

MALDAH

MURSHI-DABAD

NA

DIA

MEDINIPUR

BANKURAPURULIYA

HOOGHLY

KOLKATTA

NORTH24-PARGANAS

SOUTH 24-PARGANAS

HAORA

NEPAL

BANGLADESH

0 50

0 50 100 Miles

100 Kilometers

WESTBENGAL

Tribeni

Mumbai

BandelPower Plant

KoradiPower Plant

PanipatPower Plant

Kolkata

Chandigarh

This map was produced by the Map Design Unit of The World Bank. The boundaries, colors, denominations and any other informationshown on this map do not imply, on the part of The World BankGroup, any judgment on the legal status of any territory, or anyendorsement or acceptance of such boundaries.

IBRD 36158

MAY 2008

INDIA

COAL-FIRED GENERATION REHABILITATION PROJECT

POWER PLANTS

STATE CAPITALS

DISTRICT BOUNDARIES

STATE BOUNDARIES

INTERNATIONAL BOUNDARIES