FINAL REPORT Power project financing

Project Appraisal and Integrated Project Rating of Thermal Power Project at Power Finance Corporation Ltd.

A SUMMER PROJECT STUDY SUBMITTED IN PARTIAL FULFILLMENT FOR THE REQUIREMENT OF THE TWO YEARPOST GRADUATE DIPLOMA IN MANAGEMENT (FULL-TIME)

BY

SHYAM SUNDER GUPTA

PGDM-FINANCE-77/2008

LAL BAHADUR SHASTRI INSTITUTE OF MANAGEMENT, DELHI

JUNE, 2009

Power Finance Corporation Ltd. 2009

1 Project Appraisal and Integrated Project Rating

Table of ContentsACKNOWLEDGEMENT .........................................................................................................3

LIST OF ABBREVIATIONS....................................................................................................4

EXECUTIVE SUMMARY .......................................................................................................5

1: INDUSTRY PROFILE..........................................................................................................6

2: COMPANY PROFILE ........................................................................................................17

3: OBJECTIVE AND METHODOLOGY ..............................................................................24

4: LITERATURE REVIEW ....................................................................................................25

5: GUIDING PRINCIPLE FOR PROJECT APPRAISAL AT PFC .......................................29

6: PROJECT APPRAISAL PROCESS AT PFC.....................................................................30

7: FINANCIAL MODEL: A TOOL FOR PROJECT APPRAISAL.......................................31

8: INTEGRATED PROJECT RATING ..................................................................................32

Categorization of Entities: ................................................................................................33

Preliminary Appraisal.......................................................................................................33

Detailed Appraisal: ...........................................................................................................33

Quantitative Factor Grade: ..............................................................................................37

Qualitative Factors............................................................................................................38

Final Output..........................................................................................................................40

9: CASE STUDY.....................................................................................................................46

9.1: PROJECT DETAILS........................................................................................................47

9.1.1 Project Structure..........................................................................................................47

9.1.2 Location of the Project ................................................................................................47

9.1.3 Land.............................................................................................................................48

9.1.4 Generation Process......................................................................................................48

9.1.5 Super Critical Technology ..........................................................................................50

9.1.6 Primary Fuel................................................................................................................51

9.1.8 Secondary Fuel............................................................................................................51

9.1.9 Water ...........................................................................................................................52

9.1.10 EPC Contract.............................................................................................................52

9.1.11 Operation & Maintenance Arrangements .................................................................53

9.1.12 Utilities ......................................................................................................................53

9.1.13Evacuation of power...................................................................................................53



9.1.14 Environmental Aspects .............................................................................................54

9.1.15 Schedule of Implementation......................................................................................55

9.2: COST OF THE PROJECT ...............................................................................................56

9.2.1 Components of Project Cost........................................................................................56

9.2.2 Capital Cost Comparison ............................................................................................60

9.3: MEANS OF FINANCE....................................................................................................60

9.4: MARKET AND SELLING ARRANGEMENTS ............................................................61

Selling Arrangements...........................................................................................................61

9.5: STATUS OF APPROVALS / CLEARANCES ...............................................................62

9.6: PROFITABILITY PROJECTIONS .................................................................................63

9.6.1Financial Projections –Snapshot ..................................................................................63

9.6.2 Sensitivity Analysis.....................................................................................................64

9.7: RISK ANALYSIS AND SWOT ANALYSIS..................................................................65

9.7.1 Risk Analysis – Allocation & Mitigation....................................................................65

9.7.2 SWOT Analysis...........................................................................................................70

9.8: CONCLUSIONS ..............................................................................................................72

10: LIMITATIONS..................................................................................................................73

11: LEARNINGS.....................................................................................................................74

12: RECOMMENDATIONS...................................................................................................75

13: ANNEXURES ...................................................................................................................76

REFERENCES ......................................................................................................................105



ACKNOWLEDGEMENT

All successful work needs large number of hands to accomplish any work. I acquire this opportunity with much pleasure to thank all the people who have helped me through the course of my journey towards this project. I sincerely thank my project guide, Mr. P. K. Sinha (D.G.M. Projects, PFC), for his guidance, help and motivation. Apart from the subject of my study, I learnt a lot from him, which I am sure, will be useful in different stages of my life.

I would like to express my gratitude to Mr. Sanjeev Gupta (Officer, Project Appraisal) and Mr. Mohit Anand (Officer, Entity Appraisal) for their help in understanding and formulating the model design and methodology, and Mr. Nitin Garg (Officer, Project Appraisal) for his review and many helpful comments.

I would like to thank Prof. G.L.Sharma of Lal Bahadur Shashtri Institute of Management, NewDelhi and Dr. Ashok Gupta, Executive Director, Power Finance Corporation Ltd for providing me an opportunity to undergo such a beneficial project in the organization. I would like to thank my teachers for their assistance and useful comments. Their caring and supportive attitude gives me a lot of support in doing my project.

I am especially grateful to my colleagues for their assistance, criticisms and useful insights. I am thankful to all the other students (past and present) of LBSIM Delhi with whom I share tons of fond memories. My sincere gratitude also goes to all those who instructed and taught me through the years.

Finally, this project would not have been possible without the confidence, endurance and support of my family. My family has always been a source of inspiration and encouragement. I wish to thank my family, whose love, teachings and support have brought me this far.

Shyam Sunder Gupta

PGDM-Finance



LIST OF ABBREVIATIONS

BTG Boiler, Turbine & Generator

BU Billion Units

CEA Central Electricity Authority

CERC Central Electricity Regulatory Commission

COD Commercial Operation Date

DPR Detailed Project Report

EPC Engineering, procurement & construction Contract

FSA Fuel Supply arrangement/agreement

FTA Fuel Transport Agreement

GCV Gross Calorific Value

GoI Government of India

IPP Independent Power Producer

Kcal Kilo Calories

KV Kilo Volts

KWh Kilo Watt Hour

LC Letter of Credit

MoP Ministry of Power

MoEF Ministry of Environment & Forest

NOC No Objection Certificate

O&M Operations & Maintenance

PFC Power Finance Corporation Ltd.

PGCIL Power Grid Corporation of India Limited

PLF Plant Load Factor

PPA Power Purchase Agreement

SPV Special Purpose Vehicle

TRA Trust and Retention Account



EXECUTIVE SUMMARY

Power projects are capital intensive and have long gestation period, therefore adequate long

term financing is a critical factor. Massive investment is needed for new projects,

expansions, undertaking of reforms and restructuring, debt refinancing and short term

working capital needs and to fulfill this capital needs, the companies generally raise money

from lending institutions. PFC is also a Non-Banking Financial Institution which provides

financial assistance for the power projects. Project analysis is an essential part of PFC. It

involves a thorough analysis of the ability of the project to fulfill the desired objectives.

This project report titled “Project Appraisal and Integrated Project Rating of Thermal Power

Projects at PFC”, studies the overall financing of project and the parameters and

methodology followed for examining the overall potential of the promoters and project.

Project Appraisal structure share common features but since every project is unique and

requires tailoring of particular circumstances and features of the project. The project is

examined to see if it meets the financial, economic and social criteria that must have been

set for investment expenditure. Thus, different parameters like requirement of permissions,

agreement & clearances, capital outlay, profitability, payback period, internal rate of return

(IRR) and other project related analysis is done. The study of the financial background of the

promoters and the project tells us about the ability of the promoter to handle the project

efficiently. A sensitivity analysis is made on the project to identify the key variables, which

determine its outcomes. For this, the accuracy of the available data is improved to the point

where an operational plan of action can be developed. The detailed project report is made

which involves setting down the basic programs, allocating tasks, determining the resources

and setting down in operational form from the functions to be carried out and their

priorities. The formal approval requires the acceptance of funding proposals and agreement

on contract document, including tenders and other contracts requiring the commitment of

resources. The project feasibility is checked assuming the worst case scenarios to analyze

the debt repayment capability of the company in these conditions. Integrated Project Rating

helps in evaluating the exposure limit, interest rate, and collateral securities against the loan

to individual borrower.

****************



1: INDUSTRY PROFILE

1. Indian Power Sector

Bullish economic growth story of any country depends on a robust power generation & delivery model. A weak power infrastructure impedes the growth potential & thus pulls back the growth initiative. The National Electricity Policy envisages “Power for all by 2012” and the per capita availability of power to be increased to over 1000 units by that period, which indicates an average consumption growth of about 13.81% every year. It is easy to make such a rosy projection for the future, but very difficult to attain it, especially when the capacity addition targets of every five year plan falls short of expectations. In this back droop, there comes the need for increased private participation in the power sector & initiating policies by more and more private companies to be self reliant on power front.

1.1 Introduction to the Power Sector in India

Electricity is one of the most vital infrastructure inputs for economic development of a country. The demand of electricity in India is enormous and is growing steadily. The vast Indian electricity market, today offers one of the highest growth opportunities for private developers.

Since independence, the Indian electricity sector has grown many folds in size and capacity. The generating capacity has increased from a meager 1,362 MW in 1947 to more than 148,265.4 MW by 2003, a gain of more than 110 times in capacity addition. India's per capita energy consumption is projected to grow from 6.2 million Btu in 1980 to 18.2 million Btu in 2010 -- a rise of almost 300 percent. Although, India's energy consumption per unit of output is still rising, but it is expected to level off and to decline in the future. India consumes two-thirds more energy per dollar of gross domestic product (GDP) as the world average. India consumes only about 18 percent of the energy per person as the world average. Nearly 64.4 per cent of India's electricity is produced in thermal facilities using coal or petroleum products. 25 per cent electricity is generated by hydroelectric facilities.

In its quest for increasing availability of electricity, the country has adopted a blend of thermal, hydro and nuclear sources. Out of these, coal based thermal power plants and in some regions, hydro power plants have been the mainstay of electricity generation. Of late, emphasis is also being laid on non-conventional energy sources i.e. solar, wind and tidal.

India is one of the main manufacturers and users of energy. Globally, India is presently positioned as the eleventh largest manufacturer of energy, representing roughly 2.4% of the overall energy output per annum. It is also the world’s sixth largest energy user, comprising about 3.3% of the overall global energy expenditure per year. In spite of its extensive yearly energy output, Indian Power Sector is a regular importer of energy, because of the huge disparity between oil production and utilization.

7

India’s power market is growing faster than most of the other countries. With an installed generation capacity of 141.5 GW, generation of more than 600 billion kWh, and a transmission & distribution network of more than 6.3 million circuit Kms, Iemerged as the fifth largest power market in the world compared to its previous position of eighth in the last decade.

Usually energy, especially electricity, has a major contribution in speeding up the economic development of the country. The existing production of per capita electricity in India is around 600 kWh per annum. Ever since 1990s, India’s gross domestic product (GDP) has been increasing very rapidly and it is estimated that it will maintain the pace icouple of decades. The rise in GDP should be followed by an increase in the expenditure of key energy other than electricity.

The gross electricity production capability of Indian Power Sector is placed at around 148,265.4 MW. A key portion ofenergy. Though, this is still not sufficient.

Installed Generation Capacities

Power Finance Corporation Ltd.

Project Appraisal and Integrated Project Rating

India’s power market is growing faster than most of the other countries. With an installed generation capacity of 141.5 GW, generation of more than 600 billion kWh, and a transmission & distribution network of more than 6.3 million circuit Kms, India has today emerged as the fifth largest power market in the world compared to its previous position of

Source: powermin.gov.in

Usually energy, especially electricity, has a major contribution in speeding up the economic development of the country. The existing production of per capita electricity in India is around 600 kWh per annum. Ever since 1990s, India’s gross domestic product (GDP) has been increasing very rapidly and it is estimated that it will maintain the pace icouple of decades. The rise in GDP should be followed by an increase in the expenditure of key energy other than electricity.

The gross electricity production capability of Indian Power Sector is placed at around MW. A key portion of this generated electricity i.e. 64.4 per cent is thermal

energy. Though, this is still not sufficient.

Installed Generation Capacities


2009


India’s power market is growing faster than most of the other countries. With an installed generation capacity of 141.5 GW, generation of more than 600 billion kWh, and a

ndia has today emerged as the fifth largest power market in the world compared to its previous position of

: powermin.gov.in

Usually energy, especially electricity, has a major contribution in speeding up the economic development of the country. The existing production of per capita electricity in India is around 600 kWh per annum. Ever since 1990s, India’s gross domestic product (GDP) has been increasing very rapidly and it is estimated that it will maintain the pace in the next couple of decades. The rise in GDP should be followed by an increase in the expenditure of

The gross electricity production capability of Indian Power Sector is placed at around this generated electricity i.e. 64.4 per cent is thermal

: powermin.gov.in

8

Total installed capacity is 148,265.4 MW

Electricity generation mix is heavily dependent on thermal at around 64.4% with hydro contributing to 25%

The following graph shows a near doubling of per capita consumption of electricity from about 350 units in 1998 to over 600 units in 2005.

1.3 Structural and regulatory reform conducive to PSP

In the past, the power sector growth has not kept pace with the economic expansion and this has resulted in India experiencing a 13 per cent shortage in peak capacity and 8 per centenergy terms, on an overall basis. Driven by the requirement to enhance the budgetary allocations to social sectors to meet the emerging requirements of sustainable growth, the Government has envisaged a manifold increase in the role of the private secfinancing and operations of the power sector. Significant structural and regulatory reforms have paved the way for increased private sector participation in all aspects of the sector. Many of the legal and regulatory requirements to enable this operational provisions are in different stages of implementation in different states.

1.2 Opportunities of growth in the Indian power sector

The Government of India’s blueprint for the power sector envisages a capacity addition of 100,000 MW between 2002 & 2012, and another capacity addition of 100,000 MW between 2012-2017 along with a required associated investment for the transmission and disnetwork. A similar substantial capital investment is required to develop the national grid, for renovation and modernization of inefficient and ageing generation plants and network, for



Total installed capacity is 148,265.4 MW

Electricity generation mix is heavily dependent on thermal at around 64.4% with hydro


The following graph shows a near doubling of per capita consumption of electricity from 600 units in 2005.

Structural and regulatory reform conducive to PSP

In the past, the power sector growth has not kept pace with the economic expansion and this has resulted in India experiencing a 13 per cent shortage in peak capacity and 8 per centenergy terms, on an overall basis. Driven by the requirement to enhance the budgetary allocations to social sectors to meet the emerging requirements of sustainable growth, the Government has envisaged a manifold increase in the role of the private secfinancing and operations of the power sector. Significant structural and regulatory reforms have paved the way for increased private sector participation in all aspects of the sector. Many of the legal and regulatory requirements to enable this are in place, while the operational provisions are in different stages of implementation in different states.

Opportunities of growth in the Indian power sector

The Government of India’s blueprint for the power sector envisages a capacity addition of 100,000 MW between 2002 & 2012, and another capacity addition of 100,000 MW between

2017 along with a required associated investment for the transmission and disnetwork. A similar substantial capital investment is required to develop the national grid, for renovation and modernization of inefficient and ageing generation plants and network, for

2009


Electricity generation mix is heavily dependent on thermal at around 64.4% with hydro

: powermin.gov.in

The following graph shows a near doubling of per capita consumption of electricity from

In the past, the power sector growth has not kept pace with the economic expansion and this has resulted in India experiencing a 13 per cent shortage in peak capacity and 8 per cent in energy terms, on an overall basis. Driven by the requirement to enhance the budgetary allocations to social sectors to meet the emerging requirements of sustainable growth, the Government has envisaged a manifold increase in the role of the private sector in the financing and operations of the power sector. Significant structural and regulatory reforms have paved the way for increased private sector participation in all aspects of the sector.

are in place, while the operational provisions are in different stages of implementation in different states.

The Government of India’s blueprint for the power sector envisages a capacity addition of 100,000 MW between 2002 & 2012, and another capacity addition of 100,000 MW between

2017 along with a required associated investment for the transmission and distribution network. A similar substantial capital investment is required to develop the national grid, for renovation and modernization of inefficient and ageing generation plants and network, for



electrification of rural areas, and to improve adequacy, reliability and the quality of power supply.

1.5 Growth Blue-print of Ministry of Power:

• An investment requirement of US$ 90 billion in generation of which US$ 19 billion is expected from the private sector • An investment requirement of US$ 90 billion in transmission and distribution of which nearly US$ 15 billion is needed for the National Grid• An investment of US$ 6 billion for the National Grid is expected to come from the private sector, the rest from the Central sector• The rest of the investment in transmission and distribution will be financed through a mix of the state and the private sector• Implies at least US$ 25 billion of investments from the private sector. The large capital and knowledge requirements cannot be met by the Government alone. Further, given the magnitude of actual and opportunity loss, these investments and efforts must be brought in at the earliest. • In Generation, the development of the power market and deregulation of supply to large consumers, presents options for the sale of power to distribution utilities and to contestable consumers.• In Transmission, competitive bidding guidelines are being finalized, and the Central Transmission Utility has identified specific elements of interstate transmission systems. The JV or BOT model may be adopted in the intra-state transmission segment as well.• In Distribution, privatization continues to remain on the agenda of states (e.g. Uttar Pradesh), though the actual timing of initiation of any privatization process remains uncertain. The Act envisages the possibility of more than one distribution licensee in an area. Some applications for such licenses have been made to the relevant SERCs, and the guidelines for issue of such licenses (including minimum service obligations) are expected to evolve.• Power trading has been recognized as a separate activity, and a number of private firms have obtained trading licenses. The trading volumes have increased manifold over the last few years, and are expected to increase further as the national grid is strengthened and inter-regional flows increase. The trading business offers opportunities as a stand-alone business, as well as a strategic adjunct to investments in other segments.

• The “investment” required is not restricted to financial capital. The electricity sector incurs a commercial loss of about Rs 20,000 crores (nearly US$ 4 billion) per annum; a significant part of which is attributed to inefficient operation. To plug this, the power sector, and specifically, the distribution companies must re-engineer their business processes, invest in modern IT systems for billing, MIS, tracking, energy audit etc., train their operating staff to improve their management, commercial and technical skills, and undertake other such performance improvement measures. All of this provides significant business opportunities to various service providers.



1.6 Ultra Mega Power Projects by Government of India

Reorganizing the fact that economies of scale leading to cheaper power could be secured through large size power projects and for introducing the efficient super critical technology in a big way, a unique initiative has been launched for development of Ultra Mega Power Projects (UMPPs) under tariff based international competitive bidding route. 9 sites for development of 4000 MW project each have been identified so far.

Government of India (GoI) has launched Ultra Mega Power Projects initiatives to step up power generation capacity at rapid speed

Seven projects of capacity 4000 MW each identified to be allocated to the developers on tariff based competitive bidding

Tariff determined in this manner to be accepted by the regulator under Electricity Act

GoI to acquire land, secure environment clearance, arrange water linkage and secure Captive Coal Mine (for pit head plants) before handing over the projects

Payment Security Mechanism in terms of Letter of Credit, Escrow Arrangement and Third Party Sale

1.7 Transmission: Policy Initiatives

1.7.1 Guidelines for encouraging competition in development of transmission projects

Policy was issued on 13th April, 2006.

Promote competitive procurement of transmission services.

Encourage private investment in transmission lines.

Facilitate transparency and fairness in procurement processes.

Facilitate reduction ‘of information asymmetries for various bidders’.

Protect consumer interests by facilitating competitive conditions in procurement of transmission services of electricity.

Enhance standardization and reduce ambiguity and hence time for materializationof projects.

Ensure compliance with standards, norms and codes for transmission lines whileallowing flexibility in operation to the transmission service providers.



High Voltage Transmission Capacity:

Capacity MVA Circuit KM

765/800 KV 1,500 439

400 6,170 7,390

220 7,863 4,927

HVDC 3,000 5,872

1.7.2 Distribution

In principle approval accorded for 90 projects with an outlay for Rs.1588 crore to strengthen the distribution system in urban areas.

More than Rs.2030 crores utilized under APDRP for strengthening & up gradation of electricity distribution network.

Incentive for cash loss reduction has been disbursed to Kerala, Punjab and West Bengal.

Andhra Pradesh, Goa, Himachal Pradesh, Punjab, Gujarat, Meghalaya, Chattisgarh and West Bengal have reported profits during 2005-06. Jharkhand, Madhya Pradesh, Haryana, Rajasthan, Uttaranchal, Karnataka, Kerala and Assam have reported reduction in losses during 2005-06.

Andhra Pradesh, Goa and Tamil Nadu have AT&C losses below 20% during 2005-06. Punjab and 2 DISCOMs of Gujarat (Madhya & Uttar) have AT&C losses below 25% during 2005-06.

Action plan prepared for franchising in urban areas to reduce AT&C losses and improve efficiency in distribution. Maharashtra, Rajasthan and Madhya Pradesh have invited tenders for franchisee in urban areas. The first urban franchisee has been awarded by Maharashtra in Bhiwandi town.

5304 engineers of State distribution utilities were trained under Distribution Reforms capacity building program.

Started the Advanced Certificate Programme in Distribution Management in collaboration with IGNOU, about 1212 have registered so far.

1.8 Privatization

Many countries facing high electricity demand growth favor privatizing their electric power sectors and opening their markets to foreign firms. This approach can free up large amounts of public capital, which can be used instead for social programs. In addition, private ownership allows managerial accountability, market efficiency, and better customer service while reducing government deficits and international debt. The reasons for electric utility privatization are numerous and vary from country to country.



Some of the more evident reasons include the following:

Raising revenues for the state through asset sales Acquiring investment capital Improving managerial performance Moving toward market-determined prices Technology transfer Reducing the frequency of power shortages Reducing the cost of electricity to consumers through efficiency gain Taking advantage of creating national and regional power grids, and Re-thinking whether electric power generation in today's economy constitutes a

natural monopoly.

In 1991, the Government began to encourage private sector participation in the power industry. Since this date, a total capacity of approximately 7,400 MW from 37 private power plants has been commissioned. As of March 31, 2006 an additional capacity of around 4,500 MW from 12 projects is reported to be under construction. Orissa was the first state in the country to privatize the state's electricity distribution. This was followed by the privatization of Delhi Vidyut Board. Various other states including Uttar Pradesh, Haryana, Karnataka, Andhra Pradesh, Madhya Pradesh, Delhi and Rajasthan have restructured their boards into separate entities for generation, transmission and distribution. Some states are also attempting to corporatize the former SEB entities.

Reliance Energy Limited and Tata Power Limited dominate the private sector. Tata Power, with a generation capacity of 2278 MW. Tata Power recently bagged

4000 MW UMPP contract. Reliance Energy has a 933 MW of generation capacity. GMR Infrastructure Limited with a combined generation capacity of 420 MW and

an additional 389 MW plant to be commissioned in the near future is another serious private sector participant.

Private investment in Power sector

Post Electricity Act 2003, private sector interest has revived.

100% FDI allowed in generation, transmission & distribution, 100% FDI also allowed in power trading (License given to British Gas).

Inter Institutional Group (IIG) and Green Channel constituted to facilitate financial closure of Independent Power Projects (IPPs).

11 IPPs of more than 4000 MW capacity have achieved financial closure.

Another 3 IPPs have been agreed in principle by FIs for financial closure.

Another 8 IPPs of about 9500 MW capacity are under active consideration.



1.9 Highlights of performance of Power sector in 2007

(i) Capacity Addition: 9050 MW (5093 MW)(ii) Placement of Award (generation projects): 9354MW (9701 MW)(iii) Growth in Power Generation: 6.9% (7.2%)(iv) Plant Load Factor: 76.7% (75.77%)(v) Villages Electrified: 39,383 villages(vi) Ultra Mega Power Projects: LOI issued in case(vii) Important policies notified:

Tariff PolicyRural Electrification PolicyPolicy for development of Merchant PlantsGuidelines for encouraging competition in development of Transmission projects.

1.10 Total Installed Capacity:Sector Capacity MW %age

State Sector 76,115.77 52.5

Entral Sector 48,970.99 34.0

Private sector 22,628.75 13.5

1,47,715.51 100%

source:- ministry of power

1.11 Capacity Addition –Targets & Achievements

In India, the power sector is controlled by ministry of power; some targets are established to minimize the electricity deficit and the future expectation of need of power. These plans are 5 yearly and some details of last 4 five years plan are summarized below?

Five Year Plan Year Target MU Achievement MU

Eighth Plan 1992-1997 30,538 16,423

Ninth Plan 1997-2002 40,245 19,015

Tenth Plan 2002-2007 41,110 21,180

Eleventh Plan 2007-2012 78,577 N.A.

Source: powermin.gov.inRenewable energy sources include Small hydro project, Biomass project, Biomass power, urban and industrial water power, renewable sources.

14

Type

Thermal

Hydro

Nuclear

Bhutan Import

Total

1.12 Highlights of the XIth Five Year PlanCapacity Addition Projections (as on 28 Feb. 2008)

Figures in MW

1.13 Power Situation:

Despite significant growth in electricity generation over the years, the shortage of power continues to exist primarily on account of growth in demand for power outstripping the growth in generation and capacity additions in power generation.the long-term projected energy requirement across various regions in the country.

PeriodPeak Demand (MW)

Peak Deficit (MW)

2003-04 84,574 9,508

2004-05 87,906 10,254

2005-06 93,255 11,463

2006-07 1,00,715 13,897

2007-08 1,07,791 19,998

2008-09 109,809 96,785

2009-10* 1,18,794 1,03,816



Generation Target MU

6,48,479

19,000

1,15,468

6,564

Total 7,89,511

Highlights of the XIth Five Year PlanCapacity Addition Projections (as on 28 Feb. 2008)


Despite significant growth in electricity generation over the years, the shortage of power to exist primarily on account of growth in demand for power outstripping the

growth in generation and capacity additions in power generation. The following table shows term projected energy requirement across various regions in the country.


Peak Deficit (MW)

Peak Deficit (%)

Energy Requirement (MU)

Energy Deficit (MU)

9,508 11.2 5,59,264 39,866

10,254 11.7 5,91,373 43,258

11,463 12.3 6,31,757 52,938

13,897 13.8 6,90,587 66,092

19,998 15.8 6,08,053 63,862

96,785 11.9 7,77,039 6,91,038

1,03,816 12.6 8,40, 544 7,62,115

2009


: powermin.gov.in

Despite significant growth in electricity generation over the years, the shortage of power to exist primarily on account of growth in demand for power outstripping the

The following table shows term projected energy requirement across various regions in the country.

: powermin.gov.in

Energy Deficit (%)

7.1

7.3

8.4

9.6

9.5

11.1

9.3



1.14 Region wise Power Supply Position

All the Regions in the Country namely Northern, Western, Southern, Eastern and North-Eastern regions continued to experience energy as well as peak power shortage of varying magnitude on an overall basis, although there were short-term surpluses depending on the season or time of day. The energy shortage varied from 4.4% in the Eastern Region to 16.0% in the Western Region. Region-wise picture in regard to actual power supply position in the country during the year 2008 -09 in energy and peak terms is given below:

Region

Energy Peak

Requirement

Availability

Surplus/ Deficit(-)

Requirement

Availability

Surplus/ Deficit (-)

MU MU MU % MU MU MU %

Northern 227,104 201,951 -25153 -11.1 33,034 29,504 -3,530 -10.7

Western 254,475 213,715 -40760 -16 37,240 30,153 -7,087 -19

Southern 204,012 188,794 -15,218 -7.5 28,958 26,245 -2,713 -9.4

Eastern 82,041 78,444 -3,597 -4.4 12,901 11,789 -1,112 -8.6

North- Eastern 9,407 8,134 -1,273 -13.5 1,820 1,358 -462 -25.4


1.15 Expected Surplus/Deficit in year 2009-10 (Region wise)

Region

Energy Peak

Requirement

Availability

Surplus/ Deficit(-) Requirement

Availability

Surplus/ Deficit (-)

MU MU MU % MU MU MU %

Northern 241,461 222,875 -18,586 -7.7 35,460 29,970 5,490 -15.5

Western 276,827 234,819 -42,008 -15.2 37,330 34,276 -3,054 -8.2

Southern 220,126 201,222 -18,904 -8.6 31,384 27,216 -4,168 -13.3

Eastern 91,386 93,613 2,227 2.4 15,110 14,165 -945 -6.3

North-Eastern

10,744 9,586 -1,158 -10.8 1,804 1,537 -267 -14.8




1.16 Demand side Management Recommendations Encourage Non-conventional energy usage, Raising energy efficiency awareness Turning the Computer Monitors off when not in use There is a need to boost:

Energy audits reports by energy managers – consumption of >1MVA Commercial buildings to use only energy efficient lighting and equipment. Energy efficient equipment manufacturing incentives. TOD tariff Buildings with natural ventilation and lighting – “Passive Houses” Penalty for power factor Evaluate the major facilities for interruptible load opportunities.

1.17 Supply side Management Recommendations There is a need to boost:

Upgrading existing Supply Load Aggregation On-Site Generation Use of Captive Power Plants Peak Power development through Hydro Encourage capacity addition through various fuels Distributed Generation Setting up Big size – High efficiency plants Setting up Merchant Power Plants

***************



2: COMPANY PROFILE

2. Power Finance Corporation

2.1 Background

PFC was established in July 1986 as a Development Public Financial Institution (PFI) under Section 4A of the Companies Act, 1956. It is dedicated to the Power Sector. It is a wholly owned by Government of India. A Nav-Ratna public Sector Undertaking. It has highest safety ratings from domestic and international credit rating agencies and also ISO 9001-2000 Certification for the Project Appraisal System.

PFC provides financial assistance to all types of power projects like Generation, R&M, Transmission, Distribution, system improvement, etc. PFC encourages optimal growth and balance development of all segments of power sector through assigning priorities for financing different categories of projects. The state sector utilities are the main beneficiary of PFC’s financial assistance. PFC has also been funding private sector projects for last 5-6 years.

2.2 Mission

PFC's mission is to excel as a pivotal developmental financial institution in the power sector committed to the integrated development of the power and associated sectors by channeling the resources and providing financial, technological and managerial services for ensuring the development of economic, reliable and efficient systems and institutions. Received awards from Hon'ble President, Hon'ble Vice President & Hon'ble Prime Minister for being in the top ten Public Sector Undertakings of Government of India.

*Consistently rated ‘Excellent’ for its overall performance against the targets set in Memorandum of Understanding (MoU) by the Government of India (GoI) since 1993-94.

*Nav-Ratna Public Sector Undertaking.

*Ranked among the top 10 PSUs for the last four years.

*Employee profit stands at Rs.3.9 crores per head.

2.3 Credit Ratings

Placed at Sovereign Rating by International Rating Agencies - Moody’s and Standard & Poor’s for long term foreign currency debt.

Placed at the highest safety ratings by accredited rating agencies in India - CRISIL and ICRA

Domestic borrowings include term loans and bonds; External borrowings take the form of Syndicated Loans, Fixed & Floating Notes.

Consistently rated ‘Excellent’ by the Government of India (GOI) for overall performance against the targets set in Memorandum of Understanding (MoU) between GOI and PFC.

18

Different Rating by major rating agencies:

2.4 Objective of PFC:

PFC in its present role has the following main

To rise the resources from international and domestic sources at the competitive rates and terms and conditions and on-ward lend these funds on optimum basis to the power projects in India.

To act as catalyst to bring institutional, managerial, operationathe functioning of the state power utilities

To assist state power sector in carrying out reforms and to support the state power sector during transitional period of reforms



Different Rating by major rating agencies:

PFC in its present role has the following main objectives: -

To rise the resources from international and domestic sources at the competitive rates and ward lend these funds on optimum basis to the power projects in

To act as catalyst to bring institutional, managerial, operational and financial improvement in the functioning of the state power utilities

To assist state power sector in carrying out reforms and to support the state power sector during transitional period of reforms

2009


To rise the resources from international and domestic sources at the competitive rates and ward lend these funds on optimum basis to the power projects in

l and financial improvement in

To assist state power sector in carrying out reforms and to support the state power sector



2.5 Clients of PFC:

i. State Electricity Boards

ii. State Power Utilities

iii. State Electricity/Power Departments

iv. Other State Departments (like irrigation Department) engaged in the development of power projects

v. Central Power Utilities

vi. Joint Sector Power Utilities and Co-operative Societies

vii. Municipal Bodies

viii. Private Sector Power Utilities

2.6 Range of Services

2.6.1 Fund Based

I. Rupee Term Loan

II. Foreign Currency Term Loan

III. Buyer’s Line of Credit

IV. Working Capital Loan

V. Loan to Equipment manufacturers

VI. Debt Restructuring/ Refinancing

VII. Take out Financing

VIII. Bridge Loan

IX. Lease Financing

X. Bill Discounting

2.6.2 Non-Fund Based

Guarantees

Exchange Risk Management

Consultancy Services



2.7 Institutional Development of Power Utilities

Formulation and Implementation of Operational and Financial Action Plan (OFAP) for its borrowers - to achieve qualitative improvement in the functioning of the State Power

Utilities in managerial, technical and financial areas through: -

Participative approach in formulation of OFAPs - prepared in consultation and agreement with the Utility and State Government concerned.

Organizing seminars, workshops and training for Power Sector personnel - in India and abroad.

Studies and Consultancy Services

2.8 Reforms & Restructuring Initiatives

PFC has been actively persuading State Govts. to initiate reform and restructuring of their power sector in order to make them commercially viable. In this regard following initiatives have been taken:-

PFC is providing financial assistance to reform-minded States under relaxed lending criteria/exposure limit norms

PFC has decided to provide technical/financial assistance to State Govts. / Power Utilities for structural reforms of the State Power Sector.

Reform Group constituted in PFC to advice and assists the State Govt. /Power Utilities to formulate suitable restructuring programmes.

2.9 Major Projects Funded by PFC:

Name of the Project Capacity (MW) Cost (Crs) Amount Funded by

Malwa TPS 2x500 4054 2730

Khaperkheda TPS Extn. 1x500 2191 1753

Kameng HEP 4x150 2485 1740

Koradi TPS 3x660 10019 6250

Mejia Extn. Unit 2x250 280 1456

Sagardighi TPS PH1 2x300 2754 1925

Chandrapura Extn. Unit 7&8 2x250 2053 1435

Panipat TPS Stage V 2x250 1785 1428



2.10 Financial Position

Financial Highlights for the year 2008-09 (Unaudited)

Profit After Tax Rs. 1,355 Crores

Sanctions Rs. 57,030 Crores

Disbursements Rs. 21,054 Crores

Net Interest Margin 3.84 %

Resource Mobilization Rs. 52,421 Crores

Net Worth Rs. 9,065 Crores

Realization 99%

2.10 Resources as on 31 March, 2009

5962 64668043 8688 9605

0

5000

10000

15000

FY 05 FY 06 FY 07 FY 08 FY 09

Networth

Networth

Resources FY 09 FY 08

Amount % Amount %

Share holder's Fund 10329 16% 9330 18%

Reserve for bad & doubtful debts 724 642

Deferred Tax liability 1376 2% 1240 2%

interest subsidy Fund 909 1% 1067 2%

Bonds (Domestic) 35479 55% 23,543 45%

Ruppes Term loan 12691 20% 12,391 24%

Short tertm loan 1400 2% 2,480 5%

Foreign Currency loans 2589 4% 2,234 4%

Total 64775 100% 52,285 100%



2.13 Recent Initiatives:

Exploring possibilities of faster capacity addition through Special Purpose Vehicles.

Made a foray into renewable energy sector.

Extended tenor of loans up to 20 years for Hydro and 15 years for other schemes.

Policy for short term financial assistance for import of coal introduced

Expense limit increased for reforming GENCOS.

Short-term loan extended to TRANSCOS against receivable from DISCOMS.

Aims to capture a share of 20-25% of the total investment to be made in the Power Sector during the Xth and XIth Plan period.

2.13.1 Accomplishments:

First Developmental Financial Institution to introduce Operational and Financial Action Plans to improve efficiency in the State Power Sector.

Long term financial resources to the power sector from multilateral agencies channeled through PFC.

Tapped international financial markets to raise ECBs, setting benchmark rates for Indian corporate.

Complementing the efforts of Govt. of India, for its sponsored programmes Accelerated Generation & Supply Programme and Accelerated Power Development & Reform Programme.

Introduced new tailor-made products and services like debt re-financing, interest restructuring, funding to equipment manufacturers, short term loans, buyers' line of credit and loans for asset acquisition.

2.13.2 Future Plans:

Aims to capture a share of 20-25% of the total investment to be made in the Power Sector during the 11th Plan period.

To consolidate and expand present business.

To introduce new financial initiatives such as Universal Banking Services, Insurance, Equity Participation and Merchant Banking.

To spread into allied sectors.

To make a foray into global markets.

Diversification in terms of forward or backward integration in the power sector (financing for fuel tie ups and laying down of gas pipelines).



2.14 SWOT Analysis:

Strengths

Govt. of India’s undertaking.

Good quality management

Well established, long standing relations in the power industry

Implementing agency for Mop’s schemes including AG &SP and APDRP

Highest credit rating (due to government ownership)

Weaknesses

Poor asset quality with most of the lending to SEBs, whose loan repaymentcapabilities in the long run is doubtful.

Concentration risk attributed to lending in single sector.

Opportunities

Power sector presents significant investment opportunities.

Providing investment gateways & consultancy for domestic and external financial agencies.

Having new business opportunities to cover the entire range of activities in the Power sector.

Threats

PFC has significant exposures entities which are loss making, financially weak andare defaulting to most of their creditors. Delinquencies by these entities to PFC could impair the currently sound Balance Sheet of PFC.

Under the Tenth Five-year Plan, REC has been allowed to disburse funds through AG & SP. Since this scheme gave a price advantage to PFC, its competitive edge is diluted.

With increasing exposure to SEB’s, their weak balance sheet may affect PFC’s creditworthiness.

Currently, borrowers of PFC are unable to attract other sources of funding. If the reform programme is successful, and these entities become creditworthy, PFC’s ability to lend against quality assets would be weakened.

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3: OBJECTIVE AND METHODOLOGY

3.1 Objectives of the project:

Project Appraisal of thermal power project: 2x660 MW Coal Based Super critical Thermal Power Project.

Assigning Integrated Project Rating to the project.

3.2 Methodology:

Project Appraisal: To evaluate the project rating and conducting the feasibility report of a project based on the DPR/information memorandum/application form and other related materials submitted by the borrower.

Assesses the capital needs of the business project and how these needs will be met.

Calculation of DSCR, IRR and sensitivity analysis.

Calculating the cost of generation and relevance.

Entity Appraisal: To assess the financial health of organizations that approach PFC for credit for power projects. This would entail undertaking of the following procedures:

Analysis of past and present financial statements

Examination of Profitability statements

Integrated Rating: Financial feasibility of the project is checked by the calculation of IRR and DSCR, various cost estimates, tariff calculation, Interest during Construction, working capital requirement, levellised tariff, etc. On the basis of above data, sensitivity analysis is done at different input conditions. With the help of these data project is rated and then composite with entity rating to reach at Integrated project rating.

To assess the suitability of the company for disbursement of credit. This would involve the following actions:

Quantification & Assessment of risks

Determination of interest rate, exposure limit and collateral security.

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4

4.1 Project Finance: Project financing is an innovative and timely financing technique that has been used on many highpower. Employing a carefully engineered financing mix, it has long been used to fund largescale natural resource projects, from pipelines and refineries to electricand hydro-electric projects. Increasingly, project financing is emerging as the preferred alternative to conventional methods of financing infrastructure and other larworldwide.

Project Financing discipline includes understanding the rationale for project financing, how to prepare the financial plan, assess the risks, design the financing mix, and raise the funds. In addition, one must understand the succeeded while others have failed. A knowledgecontractual arrangements to support project financing; issues for the host government legislative provisions, public/private infrastructure partnerships, public/private financing structures; credit requirements of lenders, and how to determine the project's borrowing capacity; how to analyze cash flow projections and use them to measure expected rates of return; tax and accounting considerations; and analytical techniques to validate the project's feasibility.

Project finance is different from traditional forms of finance because the credit risk associated with the borrower is not as important as in an ordinary limportant are the identification, analysis, allocation and management of every risk associated with the project.

Project finance is the financing of longa complex financial structure where project Usually, a project financing scheme involves a number of sponsors, as well as a syndicate of



4: LITERATURE REVIEW

Project financing is an innovative and timely financing technique that has been used on many high-profile corporate projects, including infrastructural and power. Employing a carefully engineered financing mix, it has long been used to fund large

tural resource projects, from pipelines and refineries to electric-generating facilities electric projects. Increasingly, project financing is emerging as the preferred

alternative to conventional methods of financing infrastructure and other large-

Project Financing discipline includes understanding the rationale for project financing, how to prepare the financial plan, assess the risks, design the financing mix, and raise the funds. In addition, one must understand the cogent analyses of why some project financing plans have succeeded while others have failed. A knowledge-base is required regarding the design of contractual arrangements to support project financing; issues for the host government

public/private infrastructure partnerships, public/private financing structures; credit requirements of lenders, and how to determine the project's borrowing capacity; how to analyze cash flow projections and use them to measure expected rates of

ax and accounting considerations; and analytical techniques to validate the project's

Project finance is different from traditional forms of finance because the credit risk associated with the borrower is not as important as in an ordinary loan transaction; what are most important are the identification, analysis, allocation and management of every risk associated

Project finance is the financing of long-term infrastructure and industrial projects based upon a complex financial structure where project debt and equity are used to finance the project. Usually, a project financing scheme involves a number of equity investors, known as sponsors, as well as a syndicate of banks which provide loans to the operation. The loans are

2009


Project financing is an innovative and timely financing technique profile corporate projects, including infrastructural and

power. Employing a carefully engineered financing mix, it has long been used to fund large-generating facilities

electric projects. Increasingly, project financing is emerging as the preferred -scale projects

Project Financing discipline includes understanding the rationale for project financing, how to prepare the financial plan, assess the risks, design the financing mix, and raise the funds. In

cogent analyses of why some project financing plans have base is required regarding the design of

contractual arrangements to support project financing; issues for the host government public/private infrastructure partnerships, public/private financing

structures; credit requirements of lenders, and how to determine the project's borrowing capacity; how to analyze cash flow projections and use them to measure expected rates of

ax and accounting considerations; and analytical techniques to validate the project's

Project finance is different from traditional forms of finance because the credit risk associated oan transaction; what are most

important are the identification, analysis, allocation and management of every risk associated

and industrial projects based upon nance the project.

investors, known as to the operation. The loans are



most commonly non-recourse loans, which are secured by the project itself and paid entirely from its cash flow, rather than from the general assets or creditworthiness of the project sponsors. The financing is typically secured by all of the project assets, including the revenue-producing contracts. Project lenders are given a lien on all of these assets, and are able to assume control of a project if the project company has difficulties complying with the loan terms.

Generally, a special purpose entity is created for each project, thereby shielding other assets owned by a project sponsor from the detrimental effects of a project failure. As a special purpose entity, the project company has no assets other than the project. Capital contribution commitments by the owners of the project company are sometimes necessary to ensure that the project is financially sound. Project finance is often more complicated than alternative financing methods. It is most commonly used in the mining, transportation, telecommunication and public utility industries.

Risk identification and allocation is a key component of project finance. A project may be subject to a number of technical, environmental, economic and political risks, particularly in developing countries and emerging markets. Financial institutions and project sponsors may conclude that the risks inherent in project development and operation are unacceptable (unfinanced able). To cope with these risks, project sponsors in these industries (such as power plants or railway lines) are generally completed by a number of specialist companies operating in a contractual network with each other that allocates risk in a way that allows financing to take place. The various patterns of implementation are sometimes referred to as "project delivery methods." The financing of these projects must also be distributed among multiple parties, so as to distribute the risk associated with the project while simultaneously ensuring profits for each party involved.

4.2 Project Appraisal: It is an assessment of a project in terms of its economic, social and financial viability. A lending financial institution makes an independent and objective assessment of various aspects of an investment proposition. It is defined as taking a second look critically and carefully at a project by a person who is in no way involved or connectedwith its preparation. He is able to take independent, dispassionate and objective view of the project in totality, along with its various components. There are some steps for Project appraisal.

4.2.1 Management Appraisal: Management appraisal is related to the technical and managerial competence, integrity, knowledge of the project, managerial competence of the promoters etc. The promoters should have the knowledge and ability to plan, implement and operate the entire project effectively. The past record of the promoters is to be appraised to clarify their ability in handling the projects.

4.2.2 Technical Feasibility: Technical feasibility analysis is the systematic gathering and analysis of the data pertaining to the technical inputs required and formation of conclusion there from. The availability of the raw materials, power, sanitary and sewerage services, transportation facility, skilled man power, engineering facilities,



maintenance, local people etc are coming under technical analysis. This feasibility analysis is very important since its significance lies in planning the exercises, documentation process, and risk minimization process and to get approval.

4.2.3 Financial feasibility: One of the very important factors that a project team should meticulously prepare is the financial viability of the entire project. This involves the preparation of cost estimates, means of financing, financial institutions, financial projections, break-even point, ratio analysis etc. The cost of project includes the land and sight development, building, plant and machinery, technical know-how fees, pre-operative expenses, contingency expenses etc. The means of finance includes the share capital, term loan, special capital assistance, investment subsidy, margin money loan etc. The financial projections include the profitability estimates, cash flow and projected balance sheet. The ratio analysis will be made on debt equity ration and current ratio.

4.2.4 Commercial Appraisal: In the commercial appraisal many factors are coming. The scope of the project in market or the beneficiaries, customer friendly process and preferences, future demand of the supply, effectiveness of the selling arrangement, latest information availability an all areas, government control measures, etc. The appraisal involves the assessment of the current market scenario, which enables the project to get adequate demand. Estimation, distribution and advertisement scenario also to be here considered into.



4.2.5 Economic Appraisal: How far the project contributes to the development of the sector; industrial development, social development, maximizing the growth of employment, etc. are kept in view while evaluating the economic feasibility of the project.

4.2.6 Environmental Analysis: Environmental appraisal concerns with the impact ofenvironment on the project. The factors include the water, air, land, sound, geographical location etc.

4.3 Calculation of tariff: The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components) and energy charge (for recovery of primary fuel cost and limestone cost where applicable).

4.3.1 Annual Fixed Cost: The annual fixed cost (AFC) of a generating station or a transmission system shall consist of the following components

Return on equity: 15.5% tax free return on total equity. Only 30% of the project cost can be treated as equity.

Interest on loan capital: Year to year loan interest is calculated on full debt amount by weightage average rate of interest.

Depreciation: Depreciation up to 90% of the capital cost of asset is allowed.Depreciation shall be calculated annually based on Straight Line Method and rate defined in CERC guidelines.

Interest on working capital: Working capital shall include

Cost of coal or lignite and limestone, if applicable, for 1½ months for pit-head generating stations and two months for non-pit-head generating stations.

Cost of secondary fuel oil for two months.

Maintenance spares @ 20% of operation and maintenance expenses.

Receivables equivalent to two months of capacity charges and energy charges for sale of electricity.

Operation and maintenance expenses for one month.

4.3.2 Energy Cost: It is also calculated on norms of CERC, the yearly consumption of primary fuel and secondary fuel is taken for the calculation

** Other parameters like escalation, discounting, exchange rate are taken as per latest CERC norms.

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5: GUIDING PRINCIPLE FOR PROJECT APPRAISAL AT PFC

“Offering credit is an operation fraught with risk. Before offering credit to an organization, its financial health must be analyzed. Credit should be disbursed only after ascertaining satisfactory financial performance. Based on the financial health of an organization, PFC assigns credit ratings. These credit ratings are used to fix the interest rate, exposure limit and security criteria.”

5.1 Entity Eligibility Criteria: While considering the eligibility of an entity, last two year Auditor’s report and notes to annual accounts along with Income tax assessment order for last three years be also examined. Type of securities and mode of repayments is also to be suggested by the help of entity rating.

5.2 Statutory Clearances: All statutory clearances requires at Central/State level for the implementation of the project are to be ensured. Depending on the cost of project, techno economic clearances of CEA/SEB may be asked.

Clearances/Agreements required for implementation of project:

1. Land Acquisition2. Water Availability3. Stack Height: Airport Authority of India4. Forest Clearance: Such that no sanctuary, reserve, national park within the project5. No defense establishment6. Ministry of environment and Forest7. Fuel Supply Arrangement/Agreement through various coal linkages8. Fuel Transportation Arrangement9. PPA for selling Electricity10. Transmission agreement with Transmission agency11. Pollution Control Board

5.3 Cost Estimate: The base date for estimation of cost shall not be more than six month old at the time of talking up the project for appraisal. Physical contingencies shall be limited to 3% of the base cost and the price contingencies provision of 7%, 12%, 16%, 19% and 22% shall be made depending on the project completion period of 1,2,3,4 and 5 years as per PFC guidelines. Also IDC, to be considered to arrive at project cost.

5.4 Project Cost-Benefit Analysis: Calculate FIRR and EIRR. Techno-economically sound with FIRR and EIRR not less than 12%. Sensitivity analysis is also done.

5.5 Integrated project Rating: The project is evaluated on various parameters and then ranked according to the PFC guidelines. The method is explained later on.

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6: PROJECT APPRAISAL PROCESS AT PFC

Submit the application in prescribed format and replicate for financial assistance

One copy---Project Appraisal (PA) division;

one copy---Entity Appraisal (EA) division;one copy---finance division

Scrutinize the application for PA & EA division; List all the additional information required;

collect the additional information for the applicant

Preparation of preliminary appraisal note by PA & EA division for consideration of task force

Task force meeting – PA and EA division and minute’s preparation

Preliminary appraisal note for consideration for screening committee; Screening committee shortlist the proposal for consideration of financial assistance

If shortlisted; detailed PA will be prepared by PA division; detailed entity report by EA division;

Pre-commitment- pre-disbursement, other condition will be decided

Detailed Appraisal Report for approval

Sanction of term loan

Constant monitoring the activities

Get project to completion by providing any consultancy if required



7: FINANCIAL MODEL: A TOOL FOR PROJECT APPRAISAL

In every project finance deal, where everyone’s financial security rests on the future performance of a new undertaking, a thorough analysis of the project’s finances under a arrange of assumptions is prerequisite for arranging debt and equity funding, financial model play a crucial role in decision-making.

6.1 Steps taken for designing a model: The essential steps to be taken for designing a financial model for any infrastructure project financing through private participation are as follow:

Determining the scope of the project and the related EPC cost.

Determining other expenditure such as Development expense, Preliminary & Preoperative expenses, financial costs, etc.

Determine the total Cost of the project with interest during construction.

Assessment of tariff in order to determine revenue potential for the project.

Determine O&M cost through the concession period.

Calculating the fixed and variable cost relating to the project.

Financial analysis to determine the most efficient means of financing.

6.2 Purpose and uses of financial model: The financial model provide a basic analysis, usually based on relatively raw, preliminary data and simplified financing assumptions, to establish weather a given project is worth pursuing further. The required output may be:

Basic Project IRR

Debt service Coverage Ratios and other debt ratios.

Establishing a financial structure that is sustainable by the project.

Reassuring lenders and investors as to the attractiveness of the deal as a home for their funds.

An indication of tariff levels required for achieving appropriate returns.

Preparation of sensitivity analysis.

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8: INTEGRATED PROJECT RATING

The integrated rating exercise is carried out at the end of the detailed appraisal of projects. The integrated rating model is intended for arriving at a relative measure of merit for the project. The integrated rating model involves:1. Entity rating2. Project rating 3. Integrated rating: Through combination of above two.

8.1 Appraisal Methodology:

Analysis and critical comments on the strength and weakness of organization, management, its working result, financial position etc. are made on the basis of organization set up, capital/financial structure, operating/working results, credit worthiness, financial result, entity related risks and mitigation measures proposed. Power Sector entities are evaluated with reference to a set of qualitative and quantitative factors to arrive at the Aggregate Entity Score. In addition to the performance parameters, milestones giving weightage to core reform activities have also been included in the overall grading mechanism. Both the public and private entities are evaluated separately on different set of measures.

8.1.1 Policy of State/Central Sector Entities: These entities are ranked on the basis of following parameters

EXTERNAL FACTORS: State Government support (equity, subsidy, etc.) Formulation of Business Plan/FRP Implementation of Electricity Act 2003 – Corporatization of entities Regulatory safeguards of SERC Investment support from State government (equity)

INTERNAL FACTORS: Reduction trend between Average Revenue and Average Cost of supply DSCR, Net worth Receivables, AT&C Losses Debt servicing record PLF/Plant Availability Availability of Audited Annual Accounts Capacity Addition / Increase in Capital expenditures Metering (DISCOMS), Payables (DISCOMS)

These milestones/parameters have been classified as External and Internal Factors with following score allocation:



Categorization of Entities:

The Aggregate Entity Score is used for categorization of entities. For this purpose the prescribed score is as under:

The assessment of the score is done through the detail study of the entity and evaluating the score with the help of some set of standards as per the model. Some set of parameters are DSCR>1, Subsidy by government, Payment mechanism, PLF>80%, AT&C losses<20%, Average cost of supply<1.50 RS. Then the further allocation is done on pro-rata basis.

8.1.2 Policy of Private Power Projects AppraisalIt is a two-stage process i.e. preliminary evaluation and detailed evaluation in which all the promoters are evaluated for their ability to contribute equity, carry the project to completion and operate the project as per the contracts.

Preliminary Appraisal

The promoter, prior to approaching PFC should identify 50% of equity to be eligible for preliminary evaluation. In this, the scrutiny is based on the analysis of quantitative parameters and qualitative parameters, so as to access the financial strength of the promoters, track record of the project implementation and the credit worthiness.

Detailed Appraisal:

The detailed appraisal is taken up subject to the promoters identifying 76% of equity in the project tying up 50% equity so as to be in a position to achieve financial closure as early as possible. The scoring for the promoters is based on an analysis of the promoters in the descending order of equity contribution (up to 76% of equity).The final scores of the promoters by aggregating the scores of each of the equity contributors weighted by their equity contribution. Additionally the equity contributors are broadly analyzed with respect to their performance on the following parameters:

Factors Scores

External Factors (State Sector) 30

Internal Factor (Entity Specific) 70

Total 100

Category Prescribed Score

Category A+ Not less than 75

Category A Less than 75 but 50 or above

Category B Less than 50 but 25 or above

Category C Less than 25 or those not submitting the details



Credit rating obtained in the past Capital structure and shareholding pattern Profitability trends and Cash flows Market conditions in the present business and any synergies for the project Track record in project implementation Commitment of foreign promoters to the project Selling arrangements for the power produced

Any current default with Banks/ FIs has an override over any rating obtained through the above procedure.

8.2 Scoring

Quantitative Factors:

The scoring of all the factors is on a six- point scale, with 6 being the best and 1 being the worst. It involves analysis under 2 categories: Business analysis Financial flexibility

Business Analysis:

Business analysis evaluates the performance of the present business of the promoters. The analysis involves evaluation of the market position and financial position of the company along with a view on management expertise and integrity of the promoters.The parameters and factors used in business analysis have been enumerated below:

Market Position (20%)

Here relative market share of the company is determined. It is calculated as the ratio of the turnover of the promoting company divided by the turnover of the market leader in the business. In case of diversified companies the same process is repeated for each division.

Financial Risk (80%)

Ratios WtMeans of Scoring

Attribute

Return on Capital Employed 20% QuantitativeReturn on Investment

Operating margin 20% QuantitativeProfitability of the Business

Debt Service Coverage 20% Quantitative Coverage Ratio

Total Debt to Net Worth 20% Quantitative Gearing

Cash flow from Operation to Total Debt 20% Quantitative Cash Flow



It evaluates the past financial performance of the promoting companies. Performance of at least the last three years is evaluated. Financial risk parameter is represented by 5 ratios, which cover various aspects of company’s financial performance:

Return on Capital Employed (ROCE)

ROCE = PBIT/ Opening capital employed

Here, Capital Employed = (Capital + Reserves + Short term debt + Long term debt –Revaluation reserves –Capital work in progress)

ROCE is scored as a simple average of the last three years but if the latest ROCE is lower than one for the preceding year then the latest ROCE should be used for calculation instead of the average.

Operating Margin

OM = Operating Profit before Depreciation, Interest and Taxes/ Income from operations

Debt Service Coverage Ratio (DSCR)

DSCR = (PBIT – Taxes)/ (Repayment due to Long term Loan + Interest on long term and Short term loans)

Total Debt/Total Net Worth

Total debt/ total net worth = (Long term loans + Short term loans + Working Capital loans)/ (Capital + Reserves – Revaluation reserve – Loss brought forward – Intangible Assets)

Cash Flow from Operation / Total Debt

Cash flow from operations/ Total debt = Cash flow from Operations/ (Long term loans + Short term loans + Working Capital Loans from Banks)

Detailed Entity Appraisal:

After preliminary appraisal, a detailed appraisal is taken place according to the following process:

Risk Parameters Weightage Means of Scoring

Industry Risk 10% Qualitative

Market Position 10% Quantitative

Financial Risk 80% Quantitative



Business Analysis: In addition to the risk parameters included in preliminary evaluation, detailed evaluation also included industry risk score.

Industry Risk: The industry risk score measures the competitiveness of the industry in which the promoting company is operating. The industry factor would be a qualitative factor to be scored on a six-point scale. The industry expertise for scoring the industry risk factor can be developed internally or alternatively the score for the industry risk can be outsourced from an independent agency.

Financial Risk: In detailed evaluation, the projections of future financial performance are also evaluated with past financial performance. The projections for the next two years are taken into account. The above five ratios are keeping same in both the cases. But the ratio in their past and future is as follow:

Ratios Weightage

Past financial Performance 70%

Future Financial Performance 30%

Accounting Quality: This factor is use to penalize companies with poor accounting quality.

Accounting Quality Score

Good Quality 2

Average Quality 1

Poor Quality 0

Financial Flexibility: It is used to judge the ability of promoters to financially manage the project. Thus, key points evaluated are:

Ability to contribute equity to the project

Ability to bring the project to financial closure

Ability to fund temporarily funding mismatches

Ratio Wt Means of Scoring Attribute being evaluated

Equity funding potential 50% Quantitative Equity Raising Potential

Bridge finance ability 15% QuantitativeQuarterly cash surpluses from operations

Track record of funds raised

20% Quantitative Funds raised in last 10 years

Aggregate project cost handled

15% QuantitativeProjects established in the last 10 years



Equity Funding Potential: A Promoting company can contribute equity to the project by raising debt on its books or raising equity or through cash surpluses in the books.

The equity funding potential is the aggregate of:

Ability of company to raise debt up to certain debt-equity ratio (1.5:1) and DSCR of 1.5

Ability to raise equity from the markets by diluting the equity of the promoting company. Up to 10% of the average market capitalization of the company may be diluted. (the average market capitalization is calculated as the average of last 1year)

Ability to use marketable securities to raise equity for the project

Any other source of injecting funds to contribute equity to the project

The aggregate amount that can be raised by the above methods as a percentage of the equity contribution of the company is compared to the benchmark to arrive at a score on a six-point scale.

Bridge Financing Ability: This parameter basically judges the ability of company to fund short term cash flow imbalances in the project. This attribute is useful to prevent delay in project implementation due to small disbursals from the institutions.

Cash surplus = cash flow from operation + marketable securitiesHere, Cash flow from Operations = PAT + Depreciation + Non Cash Expenses in Working Capital Requirements.In this quarterly cash surplus of the promoting company is calculated as a proportion of the project cost of the company and comparing it with the benchmark to arrive at a score on the six point scale.

Track Record of Fund Raised: This technique is basically used to judge the promoter’s ability to achieve financial closure and tie up funds for the project. This factor is scored by comparing the aggregate fund raised in the last ten years as a proportion of the project cost with the benchmark, to arrive at a score.

Aggregate Project Cost: This factor evaluates the ability of the promoters to manage new project. Scoring is done by comparing the aggregate cost of the project implemented by the promoting group in the last years as a proportion of the cost of the present projects with the benchmark, to arrive at a score.

Quantitative Factor Grade: Thus various scores obtained from various parameters are multiplied by their respective weights (weights are predefined by the scoring authority) to come at final score. The benchmark of scores for the different grades is given below:



FINAL SCORE GRADES RANK

1.0 –2.00 VI Worst

2.0 –2.75 V

2.75 – 3.50 IV

3.50 – 4.25 III

4.25 – 5.00 II

5.00 – 6.00 I Best

Qualitative Factors

The scoring of all the factors is on a four-point scale, with 4 being the best and 1 being the worst. The factors are judgmental and the model provides broad guidelines for the evaluation for the same. It involves analysis under two categories: Management risk (40%) Management past experience (60%)

Management risk: It evaluates two factors:

Management Competency: It is based on the quality of past decision making as well as the general efficiency of company’s system and procedures. Educational qualifications may serve as one of the tool.

Business and Financial Policy: It is based on past business and financial policies. These are indicative of possible future strategies, and have a bearing on future debt bearing levels. Expansion strategies of company in comparison to existing size of the firm are used as a measure of risk taking ability of the company. Moreover large one time expansion is seen as less favorable option and that too in diversified businesses.

All other factors of experience in power sector and experience in setting up projects, is evaluated at an aggregate level in the management experience category.

Management experience of the promoting group: The key factors evaluated are:

Experience in Power Sector: Companies having past experiences in power generation, transmission, power generating equipment supply and other associated activities of powers

Ratio Wt Means of ScoringAttribute being evaluated

Managerial competency 20% QualitativeCompetency in running the business

Business and financial policy 20% Qualitative Risk propensity



sector would be considered eligible for being accorded marks under this head. Other issues like period of experience, management teams, and depth of expertise will also make an impact. The exact marks are left to the discretion of the appraising officer.

Expertise in Setting up Projects: Here due weightage will be given to:

Managing projects of like size should be given higher weightage

Core sector projects include infrastructure projects and projects in other industries like cement, steel etc should be accorded higher weightage than in non-core project.

Experience of past ten years will be taken into account while scoring.

Experience in India/Developing Countries: This factor is used to evaluate the exposure of promoting company in developing countries and specifically in India. As previous experience of working in Indian conditions and dealing with various regulatory and government entities helps in getting project clearances faster and also helps in managing various other stake holders in the project.

Project Preparedness of the Promoting Group: This is promoter’s preparedness to execute the project while approaching PFC. The progress of the project, clearance from various regulatory authorities etc parameters are taken in consideration. This factor is again subjective.

There is a model used for measuring the score and categorizing the entity on their score, the benchmarking is fixed on the basis of practical knowledge and it is reviewed from time to time. The benchmarking includes various ranges of input parameters and their relative score, which are helpful in summation of total score.

The past track record, company’s ability to raise fund, the operating profit and market position are assessed through the various score and then the relative score are assigned. The quantification of various parameters is done by some set of standard ratios. The score are then passed on the two legs qualitative factors and quantitative factors.

The various scores are summed up and grading from A to D is done on qualitative factors.

Ratio WtMeans of Scoring

Attribute being evaluated

Experience in the power sector 30% Qualitative Power sector experience

Experience in setting up project size in relation to the size of the project being set-up

10% QualitativeProject management capability

Experience in India/ Developing countries 10% QualitativeExperience in dealing with developing economies

Project preparedness of the promoting group

10% QualitativePreparedness of the group to execute the project



Qualitative Factor Grade:

FINAL SCORE GRADE

WORST D

C

B

BEST A

Final Output

A matrix having two legs of qualitative and quantitative parameters is formed and based on their score and grade, entities are ranked from 1 to 6. In this the qualitative grade is then combined with the risk grade (Grade I to Grade VI) obtained from the quantitative analysis by way of a matrix to give the final grade.

The matrix formed is as follows:

RISK GRADES

QUALITATIVE GRADING

QU

AN

TIT

AT

IVE

GR

AD

ING

A B C D

I 1 1 2 3

II 1 2 3 5

III 2 3 4 6

IV 2 4 5 6

V 5 5 6 6

VI 6 6 6 6

Here, IA, IB, IC, IIA, IIB, IIC, IIIA, IIIB, IIIC, IVA and IVB are considered as investment grade, while other grade combinations are considered as speculative grade.

The degree of safety with reference to the above rating is given in Annexure-I.



8.2 Project rating:

The project is rated against a set of qualitative and quantitative parameters. The qualitative parameters being Cost/MW, first full year of generation, levellised cost of generation and DSCR. The qualitative parameters are type of implementation structure, security of fuel, power sale agreement and satisfactory operation and maintenance.

The weightage of parameter in calculating the score of qualitative and quantitative parameters is assigned on the company norms and policies.

The upper and lower limits of qualitative and quantitative parameters are fixed and then on basis of pro-rata basis, assigning of rank is done. The parameter’s point and their allocation are also discussed on the set of standards.

Quantitative Parameters: First full year cost of generation w/o RoE: A range of 1.9-2.75 is taken as standard

and then allocation of score is done on that basis.

Levellised tariff/ cost of generation with RoE and tax: 2.35-3.50 is a set of standard range and then scoring is further allocated.

Average DSCR: Less than 1.0 is taken as bad condition of loan recovery while the value greater than 1.0 is rated high.

Qualitative Parameters: Power off take

o IPP- Status of PPA & PSM and/or Captive- Payment Security Mechanismo Buyers rating

Fuel supplyo Long term agreemento Short term agreemento Captive Coal mineo Transportation facility

Construction Contracto Warrantyo Market standardo Performance

Type of contract and biddingo Competitive Biddingo Equipment Supplies

Experience of the EPC contractor

Commercial terms of Contract

O&Mo Past Experienceo Management Team and efforts



Weightage to different parameters are placed in Annexure-II. The criteria of two parameters are evaluated, assessed and quantified on the above factors, there is a set of scoring range and on the basis of that model project is ranked.

The quantitative parameters are quantified on the basis of type and quality of contract and their competitiveness. The past experience in the same sector and their present status helps in evaluating these parameters. There is a fixed set of standards and on the basis of them the score is measured. The contractor and terms and conditions of the contract is also one part of standard.

The qualitative and quantitative parameters form two axes of a matrix and depending on the score in each parameter. The above project rating model enables rating of the project from P1 to P6. P1 being the best and P6 the worst (rejection grade). The entity rating procedure which rates the promoter/s of entity from E1 to E6, is then combined with the project rating model to produce the integrated rating from 1 to 6, 1 being the best and 6 the worst (rejection level).

Project Rating Matrix

Quantitative parameters

Range of scores

>44 38-44 32-37 26-31 20-25 0-19

Qua

litat

ive

Para

met

ers 45-50 P 1 P 1 P 2 P 3 P 4 P 6

39-44 P 1 P 2 P 2 P 3 P 5 P 6

33-38 P 2 P 2 P 3 P 4 P 5 P 6

27-32 P 3 P 3 P 4 P 4 P 5 P 6

20-26 P 4 P 4 P 5 P 5 P 5 P 6

0-19 P 6 P 6 P 6 P 6 P 6 P 6



8.3Integrated Composite Rating:

With the help of detailed analysis of the entity and project parameters, these two scores are combined with their corresponding ranking (the project rating is combined with entity rating)to arrive at the integrated matrix. With project rating and entity rating forming the two arms of the integrated rating is assigned based on the relative position of a project proposal in the matrix.

Integrated Rating Matrix

Entity Rating

Rating E 1 E 2 E 3 E 4 E 5 E 6

Pro

ject

Rat

ing

P 1 1 1 2 3 3 6

P 2 1 2 2 3 4 6

P 3 2 2 3 3 4 6

P 4 3 3 3 4 5 6

P 5 3 4 4 5 5 6

P 6 6 6 6 6 6 6

Any loan proposal getting a composite rating of 6 is proposed to be rejected. All other rating (i.e. 1-5) is sought to be suitably captured in an exposure/interest rate matrix as placed below, and financial support will be considered accordingly. Terms and conditions for the sanction and disbursement are decided on the basis of integrated composite rating.

8.4Linkages of integrated rating with interest rate, exposure limit and security with reference to PFC policies:The following methodology is proposed for linkages Interest rate, exposure limit and requirement of collateral securities to integrated rating model.

8.4.1 Interest rate: At present interest rate is decided by entity rating.

Integrated rating Interest rate

1-4 As applicable to Entity Grade 1-4

5 As applicable to Entity Grade 5

6 Rejection, as applicable to Entity Grade 6



8.4.2 Exposure Limit:

Project exposure is primarily decided by the category of the project in the line with OPS. As per the existing policy, additional project exposure is allowed based on the entity grading.

Integrated rating Additional project exposure in addition to basic exposure, as per OPS

1-2 30% of project cost

3-4 15% of project cost

5 Nil

6 Rejection

The exposure in single project should not be more than 50% of the project cost.

8.4.3 Collateral Securities:

The policy guideline for requirement of Collateral Securities depends upon the PFC condition as a lead FI or not. In case of lead FI the detail is placed in Annexure-III. In case of PFC is not leading FI, the collateral securities requirement would be considered on case to case basis, prescribed by Lead FI/Bank.

The detail about the interest rate, exposure limits and collateral securities under OPS norms and prudential norms for different entities are discussed in Annexure-IV.



Case Study: Appraisal of loan proposal for financial assistance to

2 X 660 MW Supercritical Thermal Power Project


46 Project Appraisal & Integrated Project Rating

9: CASE STUDY

Project Purpose and Scope

Purpose

To bridge the nation’s energy deficit, both average and peak load, by capacity addition of 1320 (2x660) MW by setting-up Coal fired Thermal Power Project based on super critical technology.

Scope

Scope of project covers installation, commissioning, operation and maintenance of 2X660 MW coal fired Thermal Power Project based on super-critical technology. The project will be implemented by way of a turnkey EPC Contract finalised through International Competitive Bidding process. The scope shall broadly cover:

1320 MW (1x660MW) power plant and associated systems.

Development of ash disposal area

Township

Development of the Green Belt

Transportation Arrangement for Coal to the Project site.

Barrage/Dam on near River, pump house, water reservoir and raw water pipeline

Power evacuation system including transmission lines

Coal Mining Facility at aggrieved coal blocks.



9.1: PROJECT DETAILS

9.1.1 Project Structure

The Company proposes to implement the Project as per following structure.

9.1.2 Location of the Project

The site was selected considering the followings:

Availability of adequate habitation-free, non-agriculture land which is partially

developed and above flood level.

The location is not in environmentally fragile area. The closest airport is about

150 kms far from site thus reducing any flight hazard because of chimney

height

Near round availability of water from the perennial river which is located

about 20 km from the site.

The site is well connected to coal mines, Port and Airport by Railways and by

State/National Highways.



9.1.3 Land

The land requirement of the Proposed Project is about 305 Ha. The break up of the land

requirements is as follows:

Description Area (Ha)

Main Power Plant 65

Ash Dyke 70

Water Reservoir 40

Railway Siding 30

Housing Colony 50

Green Belt 50

Total requirements 305

The site identified for the Project is primarily industrial corporation land with some areas of

agriculture land (Single crop) and other of forest land. The land will be on lease from MIDC

for 95 years, renewable for further term of 95 years. The Company has paid Rs. 8.53 Crore

towards allotment of land and development works.

The Company proposes to use the allotted land for setting up Main Power Plant, water

reservoir and Ash Dyke requiring about 175 Ha. The remaining allotted land, about 29 Ha,

would be used for Green Belt development.

The balance land of about 101 Ha, required for Township (50 Ha), Railway Siding (30 Ha)

and balance green belt (21 Ha), would be acquired by the Company in due course. The

balance land would be acquired at an estimated cost of Rs. 5.44 Crore.

The site development for the Proposed Project site, covering levelling, boundary wall,

internal and approach roads and other miscellaneous requirements, is estimated to cost about

Rs. 25.50 Crore.

9.1.4 Generation Process

The process of generation of power from coal (water steam cycle) essentially entails two

main stages. In the first stage, the chemical energy stored in coal is converted into heat

energy in the coal-fired boilers. In the second stage, the high-pressure steam, which is

generated in the boilers, is passed through turbines (conversion of heat energy into



mechanical energy) which in turn is coupled to generators (conversion of mechanical energy

into electrical energy), thereby generating electricity.

The water steam cycle essentially contains the coal fired steam generator, the steam turbine

with condenser, feed-water tank, low-pressure (LP) heaters and high-pressure (HP) heaters

and the connecting pipelines. The superheated steam produced in the steam generator is

supplied to the steam turbine, which drives the three-phase AC generator. After leaving the

HP turbine, the steam is reheated in the steam generator and fed to the Intermediate Pressure

(IP) turbine. In the LP turbine the steam coming directly from the IP turbine expands to

condenser pressure and is condensed in the condenser.

Closed cycle water system is used for cooling of the condenser. The condensate collected in

the condenser hot well is discharged by the condensate pumps and supplied via the LP

condensate heaters into the feed water tank. The feedwater is further heated by bled steam

from turbine and dissolved gases from the feed-water are liberated. The boiler feed pumps

discharge feed water from the feed-water tank via the HP heaters to the economizer.

Steaming starts from this point onwards. The high temperature steam-water mix is further

converted into steam in water walls and finally passed through the superheaters sections for

converting the saturated steam into superheated steam.

The power station would be designed with two power generating units of 660 MW each,

along with the auxiliaries and common utility services like plant water system, coal handling

system, ash handling plant, and switchyard for power evacuation, plant electrical system and

workshop.

The main sections of the power generating unit include Steam Generator along with milling

system and electrostatic precipitator, integral piping, integral control system, turbine and

generator unit, boiler feed pump, regenerative heaters, condensate extraction pump,

circulating and auxiliary cooling water pumps and the generator transformer with bus duct.

The main sections of the utility system are the coal handling system, ash handling system,

fire fighting system, AC & Ventilation system, switchyard and the plant water system.

The main generating equipment will consist of two Steam Turbo Generators (STG) and two

Pulverized Coal Fired Boilers (PCFB.). The power generated at lower voltage would be

stepped up to 400 KV and will be connected to the proposed 400 KV switchyard for dispatch.



9.1.5 Super Critical Technology

The Proposed Project is based on Super Critical Boiler Technology instead of more prevalent

Sub-Critical Boiler Technology in India. The basic difference between the two technologies

is the steam pressure at which the boiler is operated. In case of Sub Critical Technology the

operating pressure in boiler is less than 19 MPa as against 24 MPa in typical subcritical

power plant. The supercritical power plant can achieve considerably higher cycle efficiencies

with resulting savings in fuel costs and reductions in CO2 and other emissions.

Plant costs are comparable for both the technologies. However, overall economics for super

critical technology are more favorable because of the increase in cycle efficiency. Economic

performance is also influenced by other factors, including plant availability, flexibility of

operation and auxiliary power consumption. The once-through boiler design used in super

critical technology based plants is inherently more flexible than drum designs used in sub-

critical technology based plant, due to fewer thick section components allowing increased

load change rates. Typical average availability of super critical technology based power

plants is about 85%. However, with appropriate design and materials, a plant availability of

>90% is achievable. Efficiencies of supercritical power generation are also less affected by

part load operation, with efficiency reductions less than half those experienced in subcritical

plant.

The major environmental benefit of supercritical power generation is from reduced coal consumption per unit of electricity generated, leading to lower CO2 and other emissions. CO2

emissions for supercritical plant would be 17% lower than for a typical subcritical plant. Similarly, all other emissions e.g. NOx and SOx, would also be reduced pro-rata with the reduction in coal consumption.

However, for optimum environmental performance, supercritical power generation

technology can benefit from advanced emissions-control technologies to minimize harmful

emissions. These include flue gas desulphurization (FGD), low-NOx combustion, selective

catalytic reduction (SCR), selective non-catalytic reduction (SNCR), air staging and reburn

technologies.

The lower CO2 emissions from super critical plants are quantifiable and the project can be

registered as a CDM project for accruing CERs which can be traded with international

markets. This can potentially work as an additional revenue stream for the project.



9.1.6 Primary Fuel

The primary fuel for the Proposed Project would be domestic coal. The Company proposes to

use coal available from mines.

Ministry of Coal has allotted the Coal Blocks to the company for use in the Proposed Project.

The Company is in process of finalizing the mining plan. These blocks are expected to have

extractable coal reserves of 169.832 MT and the break-up is given as below.

The average calorific value of the coal is expected to be about 4895 kcal/kg. Considering this

Gross Calorific Value and PLF of 85% the coal requirement of the Project works out to be

about 4.12 MTPA.

The cost of mining of coal is estimated to be Rs. 750 per ton (in the year 2011-12) including

Royalty, Stowing Excise Duty and Local Area & Environment Cess. The coal cost is

escalated at 5% p.a. to account for inflation for the input factors for mining of coal. The

Company proposes to carry out the mining by itself. Therefore, any savings in the cost of coal

will get reflected in lower cost of generation of power from the Project.

The Company has estimated the capital investment of Rs. 400 Crore for open cast mine

development and the same has been incorporated in the overall Project Cost.

9.1.7 Coal Transportation

The distance of Coal Blocks from site is about 260 km. The coal will be transported from

mines by rail in rake loads in Box/Box-N wagons through rail network to Project site. Coal at

mines end would be loaded from bunkers / silos to the wagons through flash loading system

and unloaded at the plant by wagon tipplers to optimize on turn around time.

For transportation of coal, the Company would enter into Coal Transportation Arrangement

(CTA) with the Indian Railways. The transportation cost as estimated by the Company is Rs.

250 per ton of coal (in the year 2011-12), which includes the loading, unloading and handling

cost. Further, escalation of 5% has been assumed on the transportation cost of coal from

2011-12 onwards.

9.1.8 Secondary Fuel

Secondary fuel in the form of LDO / HFO would be required primarily for start up operations

and for stabilization. The annual requirement of secondary fuel - LDO/HFO is estimated at

about 9,251 KL per annum. The secondary fuel would be sourced from the nearby depot of

Oil Marketing Companies to be transported through road tankers.



9.1.9 Water

The total consumptive water requirement is estimated to be 5000 m3 per hour for the

Proposed Project. The Company has already received Letter of Intent from Water Resources

Department (WRD), for allocation of 2.5 Lacs m3/day (10,417 m3 per hour) of water from

River. To ensure year-round availability of water to Project, the Company proposes to build

barrage/dam, where the adequate quantity of water will be stored.

The overall cost of water arrangement as estimated by the Company is about Rs. 205.83

Crore and has been considered in the Project cost.

9.1.10 EPC Contract

The Company proposes to implement the Project by way of a turnkey Engineering

Procurement and Construction (EPC) contract to be awarded by way of International

Competitive Bidding process.

The scope of the EPC contract would cover the following:

Complete design and execution of the Civil, Structural and Architectural work

of the Main Power Block, including Cooling towers, RCC chimney, Various

Pump house building, storage tanks, CHP, AHP, internal roads and drains etc.

along with some general facilities.

Complete design, supply of equipments, transportation, loading, unloading,

storage, erection and commissioning of the BTG works, complete mechanical

and electrical systems of the plant including 400 KV switch yard and interface

with existing switchyard, water system supply to various consumption point

and effluent discharge up to the plant boundary, control and instrumentation

system of the main plant & Balance of plant equipments and systems.

Commissioning, trial operation, reliability run and performance guarantee test

of the entire plant.

The Company may choose to implement the Project through package contracts, which will be

awarded to reputed vendors though competitive bidding process as it entails savings in cost.

The final decision will be based on the detailed evaluation of both the options. The cost

estimates are, however, based on the EPC method.



Company has executed EPC Contract for its 2X660 MW Supercritical power project with a Chinese EPC Contractor, in September 2007. The EPC Contract was split into two parts- one for Supply and other for Erection and Commissioning.

9.1.11 Operation & Maintenance Arrangements

The operations & maintenance (O&M) of the power plant would be undertaken by the

Company in-house with the support of its technical team and expert engineers. The

Company would build a strong team of experienced and qualified

engineers/technicians to look after the operations of the Proposed Project.

The O&M team of the power station would be headed by a Senior Vice President,

under whom separate groups viz. Operation, Mechanical, Electrical, Civil and C&I

maintenance would operate. In addition to these groups, operation and efficiency

improvement group and maintenance planning group would monitor the efficiency in

operations and maintenance management respectively and suggest continual

improvements.

9.1.12 Utilities

Construction Power

The requirement of power for construction at site would be sourced from the 33KV substation of State Discom which is about 10 km from the Project Site. The Company proposes to obtain power from Express Feeder during construction. The consumers which are connected on express feeder are exempted from load shedding by State Discom ensuring continuous supply of power for the Proposed Project. Further, there is 11 KV connection already existing at the site to meet initial requirement of power.

Construction Water

The requirement of construction water for potable and service purposes will be met by the existing 2.2 MLD Water Treatment (WT) Plant located within the allotted land for the Project. The Company has taken over the Water Treatment Plant along with pipeline, elevated water reservoir, office building etc and paid about Rs. 3.42 Crore for the same.

9.1.13Evacuation of power

Power Evacuation from the Project would be at 400 KV level. There are 400 KV

substations of State Transmission Company which can be utilized to dispatch power to

State Distribution Company. Similarly, there are four 400KV substations of PGCIL at

which can be used to dispatch power to consumer in other states.



The Company proposes to sell about 746 MW gross power output (i.e. 56.50% of

gross capacity) under the long term PPA to a Private Company BEL, a power trading

licensee.

The cost of both the transmission lines as estimated by the Company is about Rs. 316

Crore.

Further, the Company proposes (a) to get the system study done by PGCIL & State

Transco (b) obtain open access permission along with BEL (c) obtain necessary

permissions, clearances for transmission line in due course of time.

9.1.14 Environmental Aspects

There is no sanctuary, national park or archaeological monument within 25 km radium

of the proposed site. The Proposed Project would be equipped with state of the art

pollution control devices to bring down the emission / discharge of pollutants within

the acceptable norms of the country.

Some features of the Project addressing the environmental concerns are as follows.

An efficient electrostatic precipitator is proposed that would keep the stack

emission of particulate within limits.

The stack height of 275 m is proposed to limit the ground level concentration

of pollutants (SOx, NOx etc).

Adequate silencing equipments would be provided to attenuate the noise to

acceptable level.

Adequate green belt would be developed in and around the Project area and the

ash disposal area satisfying the requirement of State as well as Central

Pollution Control Board.

The Company has applied for Environmental Clearance and for NOC from Pollution

Control Board.



9.1.15 Schedule of Implementation

The Project is expected to achieve commercial operations (COD) within 45 months

from the date of issuance of Notice to Proceed (NTP) for EPC contract. The first unit

is expected to be completed within 39 months and second unit will be commissioned

with a time gap of 6 months. The Company proposes to issue the NTP for the Project

by April 1, 2008. The overall time schedule for implementation of the Project is as

follows:

Particulars Completion

Notice to Proceed for EPC Contract April 1, 2008

Unit I Trial Runs April 1, 2011

Commercial Operation Date (Unit I) July 1, 2011

Unit II Trial Runs October 1, 2011

Commercial Operation Date (Unit II) January 1, 2012

Total Implementation Period 45 Months

It may be noted that the above-mentioned schedule is tentative and the final schedule will be

firmed up on award of the turnkey EPC contract.

**********



9.2: COST OF THE PROJECT

9.2.1 Components of Project Cost

The Project is estimated to be set up at an aggregate cost of Rs. 6560 Crore comprising of

expenditure towards Land, EPC Cost, Mining Cost, Transmission Line, Coal Transportation

Arrangement, Water Arrangement, Preliminary & Preoperative Expenditure, Contingencies,

Interest During Construction Period and Margin Money for Working Capital. A summary of

the components of Project cost is presented below:

(In Rs. Crore)

Particulars Estimated Cost

Land & Site Development 39

Engineering, Procurement & Construction Cost 4544

Supply Contract (USD 949,960,000) 3800

Service Contract 704

Escalation due to Re Depreciation 40

Mining Cost 400

Coal Transportation Arrangement 40

Water Arrangement 206

Transmission Line 316

Township 50

Total Hard Cost 5595

Pre-operative Expenditure 80

Interest During Construction Period 1167

Contingencies 145

Margin Money for working capital 104

Total Cost 7091



Land & Site Development

Land requirement for the Project is about 305 Ha. The Company has already acquired about

204 Ha Land on 95 years Lease. The Company has applied to State Govt. for allotment for

additional 101 Ha land for the Project. The cost of land acquisition and site development is

estimated to be about Rs. 39.47 Crore.

Engineering, Procurement and Construction Cost

The Project is proposed to be implemented through turnkey EPC contract to be awarded on

International Competitive Bidding Process for 1320 MW project. The EPC contract will be

split in two parts viz. Supply and Service Contracts. The Supply contract will include design,

engineering, procurement and supply of all plant equipments and auxiliaries system for the

Project. The supply contract price is estimated to be about 949,960,000 USD (Rs. 3799.84

Crore @40 Rs./USD) on CIF basis. Payment for Supply Contract will be through an

irrevocable, confirmed, negotiated and usance payable at sight basis Letter of Credit.

Mining Cost

The Company plans to carry out mining by itself for which Company proposes to install

equipment and systems required. The requisite equipments and system will be procured and

installed by one of the reputed vendor and the contract for the same would be awarded though

competitive bidding process. The capital expenditure for mining as estimated by the

Company is about Rs. 400 Crore.

The detailed breakup of the capital cost is as under:

(In Rs. Crore)

Land 81.00

Plant & Machinery 223.00

Buildings & Colony 45.00

Development Expenses 45.00

Miscellaneous 7.00

Total Mining Cost 400.00



Coal Transportation Arrangement

The Company proposes to transport the coal from mines in wagons preferably owned by the

railways.

The coal transportation infrastructure required for the Project as estimated by the Company is

about Rs. 40 Crore.

Water Arrangement

The water arrangement for the Project involves building a barrage/dam, raw water pipeline up

to plant, pump house and a raw water reservoir. The water arrangement is estimated to cost

about Rs.205.83 Crore. The detailed breakup of the capital cost is asunder:

(In Rs. Crore)

Particulars Estimated Cost

Barrage / Dam 125.00

Pump House 30.00

Buried Pipeline 30.00

Raw Water Reservoir 20.83

Total 205.83

Transmission Line

Transmission cost includes supply of transmission towers, earth wire, hardware fittings and

accessories for conductor, insulators and cost of ROU/ROW, land etc. to set up two double

circuit 400 KV transmission line. Total cost of transmission lines is estimated to be about Rs.

316 Crore.

Township

The Company proposes to develop a township for the employees of the Proposed Project.

The township will require about 50 Ha land, which has been included in the overall

requirement for the Project. Township will include the residential units, school, hospital,

community centre etc. Total cost of township development is estimated to be about Rs. 50

Crore.



Pre-Operative Expenses

Pre-operative Expenses are estimated to be Rs.81 Crore and include fees to be paid towards

technical studies conducted by owner’s engineer and lenders’ independent engineer, legal

expenses for fees payable to the lenders’ and owner’s legal counsel, insurance advisor’s fees,

appraisal fees, merchant banker’s fees, upfront fees to lenders, advisors fees, start up fuel,

employees recruitment, training and salaries, other expenses etc. A break up of the estimated

preoperative expenditures is as under:

Contingency

The Company proposes to implement the Project by way of a turnkey EPC contract which

will be a fixed price and fixed time contract. As contracts for the Project are not yet finalized,

the contingency provision of 2.5% of EPC Cost and 5% on non-EPC cost, amounting to

about Rs. 144.85 Crore has been made in the Project cost.

Interest during Construction Period

The interest during construction (IDC) period estimated at Rs. 1167 Crore has been

calculated assuming an implementation period of 39 months for Unit 1 and 45 months for the

entire plant from Notice to Proceed (NTP) to EPC contractor. The debt drawdown schedule

has been made with a provision for 35% equity being brought upfront, with the balance

coming pro-rata with the debt. Term Loan the rate of interest as applicable for rupee loan (i.e.

11.50%) has been considered.

Margin Money

The provision for margin money for working capital has been made at Rs. 103.79 Crore. The

margin money has been estimated at the rate of 25% of projected net working capital

requirement of Project in the first full year of operation. For the purpose of estimates, the

current assets comprising of receivables of 2 months, primary fuel stock of 1 month,

secondary fuel stock of 2 month, O&M expenses of 1 month and spares requirement equal to

20% of the O&M cost has been assumed.



9.3: MEANS OF FINANCE

The cost of the Project estimated at Rs. 7091 Crore is proposed to be financed with senior

debt and equity in ratio of 75:25. The proposed components of financing are as under. Equity

is broken in a ration of equity to sub-debt as 80:20.

Particulars Rs. Crore %

Capital Contribution

- Equity Capital1418.37

20%

Sub-debt Finance

- Loan354.59 5%

Senior Debt Finance

- Rupee Term Loans5318.89

75%

Total 7091.86 100%

Capital Cost Comparison

The total Project cost of the Project envisaging setting up a 1320 MW power plant using

super critical technology on a turnkey EPC contract basis is estimated at Rs. 7091 Crore.

Based on the total Project cost of Rs. 7091 Crore, including transmission lines and mining

cost, the per MW cost of the Project works out to Rs. 5.37 Crore. If we exclude the cost of

transmission line & mining and corresponding IDC, the Project Cost reduces to Rs. 5308

Crore and the per MW cost of the Project works out to be Rs. 4.02 Crore.

It may be observed that the cost per MW of the Project is competitive even with other thermal

power projects being developed using sub critical technology.



9.4: MARKET AND SELLING ARRANGEMENTS

Selling Arrangements

The Company proposes to sell the power generated by the Project as under:

I. 80% of total installed capacity, power output under 15 years take or pay power

purchase agreement to BEL at quoted tariff.

II. Remaining power to be sold on merchant basis on the best available terms and

conditions from time to time. For financial projections for the Project, the tariff as

above has been assumed.

As per financial projections, the power will be generated at Levelized (25 years) cost of generation of Rs. 2.61 per unit comprising Rs. 1.54 per unit towards fixed charges and Rs. 1.07 per unit towards variable charges. The cost of generation for the Project as per CERC norms is estimated to be about Rs. 2.21 per unit comprising Rs. 1.42 per unit towards fixed charges and Rs. 0.79 per unit towards variable charges.

The tariff of the Company is quite competitive because of captive coal mines. The cost of generation is Rs. 1.93 per unit and the tariff works out to be Rs. 2.21 per unit considering 15.5% ROE (levelized for 25 Years). As per CERC norms, the tariff works out to Rs. 1.96 per unit comprising of Rs. 1.25 per unit as fixed charges and Rs. 0.71 per unit as variable charges, with ROE of Rs. 0.25 per unit.



9.5: STATUS OF APPROVALS / CLEARANCES

The current status of the key statutory approvals and clearances is as follows:

Approval/

Consent

Authority / Agency Status

Environmental clearance for Power plant

MoEF The Company has applied for the clearance.

Environmental clearance for Coal Mines

MoEF To be applied.

Pollution control Board NOC for Power plant

State Pollution Control Board

The Company has applied for the clearance.

Pollution control Board NOC for Coal Mines

State Pollution Control Board

To be applied.

Stack height clearance Airport Authority of India (AAI)

To be applied.

Water availability Water Resource Department / State Govt.

The Company is to submit proposal for water availability certificate.

Land Availability State Government 204 Ha land has been already acquired. The Company has applied for allotment of balance 101 Ha of land.

Primary Fuel Ministry of Coal / Government of India

Ministry of Coal has allotted Coal block to company for the use in the Proposed Project. Company proposes to get the mining plan approval, mining lease.

Transportation of Fuel Indian Railways Company proposes transportation logistics from Coal mines to Plant Site and to get the requisite approvals for railway sidings.

Transmission Line PGCIL

State Transco

Company proposes to get the system study done and get open access permission from PGCIL & State Discom in conjunction with BEL.



9.6: PROFITABILITY PROJECTIONS

9.6.1 Financial Projections –Snapshot

The financial projections, based on the capital/project cost as specified by the borrower, would be as below:

Particular Value

Parameters

DSCR

Minimum 1.10

Average 1.35

Maximum 3.34

Project IRR, 25 years 16%

Equity IRR, 25 years 20%

Cost of generation, w/o RoE, Rs / kWh 2.13

Projected first full year cost of generation 2.18

The detail financial statements and cash flow statements, balance sheet are placed as Annexure-VI.



9.6.2 Sensitivity Analysis

A sensitivity analysis of the Company’s financial position has been carried to ascertain the

robustness of its financials. Various scenarios for which the sensitivities was carried out and

the results are as follows.

ScenarioAvg

DSCR

Min

DSCR

Project

IRR

Equity

IRR

Base Case 1.70 1.38 19% 31%

Case 1: PLF at 75% 1.28 0.91 13% 14%

Case 2: Increase in Fuel Cost by 20% 1.30 0.97 13% 15%

Case 3: Increase in Project cost by 10% 1.33 0.97 16% 19%

Case 4: Decrease in calorific Value of Coal by

20%1.29 0.96

13% 15%

Case 5: Increase in Interest Rate by 100 bps 1.42 1.02 16% 21%

Case 6: No power sold on Merchant basis 1.28 0.90 14% 15%

The key assumptions underlying the profitability projections for the Project are detailed in

Annexure VI. Based on these assumptions key financial parameters for first eight years of

operations are given below. Detailed Profit & Loss Account, Cash Flow Statement, Balance

Sheet and DSCR Calculations as projected are given in Annexure VI.

The above financials have been worked out considering 85% PLF. Higher PLF would

improve the financials of the Project. From the above financial projections, it may be

observed that the Project is financially viable. It may also be noted that the average DSCR for

the Project debt is 2.08 while minimum DSCR is 1.63. The DSCR levels of the Project are

satisfactory. Further, Project IRR is 20.54% which seems adequate.

It may be observed from above mentioned results that Project financials are quite robust in

various scenarios and the DSCR levels are satisfactory.



9.7: RISK ANALYSIS AND SWOT ANALYSIS

9.7.1 Risk Analysis – Allocation & Mitigation

a. Pre-Construction

S. No.

Risk Mitigation / Allocation

1 Grant of approvals / clearances

A suitable pre-disbursement condition has been stipulated:

Obtain all statutory and non statutory clearances including the MOEF clearance, Pollution Control Board NOC and agree to comply with all the conditionality of these clearances

2 Finalisation of Contracts The Company has already awarded the EPC Contract Project. The service contract has also been awarded by the Company. The EPC contract has provided for liquidated damages in case of delay in implementation and for plant’s various performance parameters below stipulated level.

3 Procurement of land Land has been already acquired which is sufficient for the main power block, Ash Dyke and Raw Water Reservoir (Both Phase I and Phase II). Balance 295 Ha of land required (for both Phase and Phase II) is being acquired.

b. Construction

S. No. Risk Mitigation / Allocation

1 Cost estimate Since the technology is based on super critical parameters, it is difficult to fairly compare costs. Cost overrun undertaking has been sought.

2 Cost increase and price escalation

Package contracts are expected to have suitable safeguards and will be subject to LIE review. Also, any increment in project cost would be met by the promoters without recourse to either the project or its lenders.

3 Completion delay and Equipment Supply delay

The package contract is expected to have suitable provision for timely project completion. Also, LDs



have been stipulated for delay in equipment supply.

4 Evacuation facility The Company proposes to evacuate the power to both State Discom and PGCIL sub-stations. Evacuation to State Discom will be for the capacity as specified in the PPA with State Discom. The remaining power would be evacuated to PGCIL sub-station.

5 Forex risk Adverse movements impacting the project cost is proposed to be mitigated by appropriate forex management, which may include hedging.

6 Equity infusion The equity in company will be infused by promoter’s Group as also by raising funds from financial/strategic investors. Suitable conditions have been stipulated to ensure that required amount of equity is infused.

c. Post Construction

S. No. Risk Mitigation / Allocation

1 Fuel supply risk The Company has also got the captive mine allotted for the Phase I of the project. The coal, if available, from there can also be used for Phase II.

Hence, fuel supply risk is perceived to be low.

2 Fuel price risk The fuel supply agreement is yet to be signed. The fuel supply agreement shall be subject to review by Lenders / Lenders’ agencies.

3 Performance shortfall The EPC Contract is expected to provide suitable defect liabilities / warranties. LD clauses would also be stipulated for ensuring performance. As a preventive measure, the design shall be subject to review by both the Owners Engineer and LIE.

4 O&M O&M is expected to be done in house. Condition has been stipulated that the O&M plan be prepared and be approved by LIE to ensure adequacy of the same.



5 Technology risk EPC contract have been awarded to a contractor having super critical technology and sufficient experience. Company is also implementing other project on the same technology, which again reduces the risk.

6 Force Majeure The risk will have to be borne by the project Company, and may prove to be damaging for the project and by extension the lenders. This may be mitigated to some extent by ensuring adequate security for the lenders.

7 Off take risk The Company would sell 1320 MW of net power to State Discom through a long term PPA at a levelized tariff of Rs. 2.61 per unit.

With CoG of approximately Rs. 2.21 per unit, the off take of balance power, to be sold on merchant basis, should not a problem.

8 Price risk The cost of generation, is lower than the assumed average purchase price of power of Rs. 2.78 / kWh. The risk may be perceived to be low.

9 Payment risk Payment risk is perceived to be low as the major portion of power is being sold to State Discom under a long term take or pay PPA.

Also, LDs have been specified in the PPA for payment security.

10 Environmental Hazards Appropriate conditions for obtaining MOEF Clearance and Pollution Control Board NOC have been specified.

11 Lower cost power producers With newer technology, the cost of energy generated might be significantly lower than cost of energy. Older plants, with depreciated assets would also be able to compete with company.



Integrated Rating

The entity is rated according to the financials submitted by the company and evaluating through the model.

Based on the model, the Promoters are evaluated and score is given on that basis

Promoter 1:- 5.36 {equity = 51%}

Promoter 2:- 2.56 {equity = 49%}

Combined Score = 5.36x0.51 + 2.56x0.49 = 3.988 i.e. III

SPV Rank

Quantitative Score III

Qualitative Score B

Combined Grade (by matrix) = 3 or E3 (i.e. IIIB).

Project Rating

Quantitative Parameters

SN. Parameter Wt Score Result

Score obtained

1 First full year cost of generation w/o RoE

25% 12.52.18 Rs. 9.44

2 Levellised tariff/ cost of generation with RoE and tax

25% 12.52.61 Rs. 10.24

3 Average DSCR 50% 25 1.35 20

Total 100% 50 39.68



Qualitative Parameters

1 Power offtake 20% 10 6

a IPP- Status of PPA & PSM and/or Captive-Payment Security Mechanism

70% 7 4.2

b Buyers rating 30% 3 N.A.

2 Fuel supply 30% 15 15

3 Construction Contract 35% 15 12.885

a Type of contract and bidding 35% 5.25 5.25

b Experience of the EPC contractor 35% 5.25 3.675

c Commercial terms of Contract 30% 4.5 3.96

4 O&M 20% 10 6

Total 100% 50 32.885

From the above scores the project is rated as P2 according to the matrix.

Integrated Project Rating

The grade combination of E3 (Entity Grading) and P2 (Project Grading) is overall Integrated Rating 2.



9.7.2 SWOT Analysis

Strength

The Project has been allocated Coal Blocks by Ministry of Coal for use in the Project.

The captive mines will be operated by the Company itself. This will ensure complete

control over the fuel supply and will also minimize the inventory costs, transportation

delays, shortages and leakages.

The captive mines allocated for the Project have good quality coal and the GCV of

coal is expected to be about 4895 kcal/kg. High GCV and control over mining costs

will ensure very competitive cost of generation at Rs.2.21 per unit and corresponding

tariff of Rs. 2.61 per unit (assuming 15.5% ROE).

The Project is located in severe power shortage region. State itself has been facing

severe power shortage and the power deficit is likely to continue in short and medium

term.

The Company has already acquired 204 Ha land which is adequate for the main power

plant block. The work on site may start immediately without any delay.

Promoting Group has demonstrated its infrastructure project development and

execution skills in the port sector and is on the verge of completion of the power

project.

The Project is based on Super Critical Technology which is expected to provide

efficiency gains to the Company resulting in lower cost of generation. Use of Super

Critical Technology will reduce the pollution and the Project may be qualified to get

CER under CDM. This would act as additional revenue stream for the Project and

improve the financials of the Company.

The Project is expected to be accorded Mega Power Status which will render various

cost benefits to the Project and will keep the cost of generation competitive.

The promoter group company, undertake to fund the cost overruns, if any, for the

Project. It also undertake to fund the increase in cost if Mega Power Status is not

granted to the Project.



Weaknesses

Company shall be selling 574 MW power on Merchant Basis.

Environment and Forest Clearances still to be obtained.

Opportunities

The Electricity Act 2003 and subsequent National Electricity Policy and Tariff Policy

have opened up several opportunities for the power sector. The Act allows the IPPs

and captive power producers open access to transmission system, thus allowing them

to bypass the SEBs and sell power directly to bulk consumers. Slowly open access in

distribution is also being allowed. These provisions will give credence to the concept

of merchant power.

With the advent of the era of competitive bidding for tariff for procurement of power,

the new capacities would not be subject to regulated tariff and regulated return of

equity and thus provide investment opportunities to Developers in the power sector

where returns would be market determined.

There is huge power deficit in the country and the demand supply situation in the

country is expected to remain favourable to power generators for the next 8/10 years

at least. This presents huge opportunities in the power sector for power generators.

Threats

The super critical technology is not yet tested in India and the Company also does not

have any prior experience of operating such power plant.

A part of power generated will be sold on Merchant basis



9.8: CONCLUSIONS

Company has proposed to set-up 1320 MW (2x660MW) Coal fired Thermal Power Project based on Super Critical Technology. State Government has supported this Project and has issued letter of support to provide all kind of administrative support required.

The Company has already acquired the land required for the Main plant from Industrial Development Corporation and has made the requisite payments. The remaining required land has been identified and the process of acquisition is underway.

The Proposed Project will be implemented by way of a turnkey Engineering, Procurement and Construction (EPC) contract to be awarded on International Competitive Bidding Process (ICB).

The Project requires about 4.12 MTPA coal based on average GCV of 4895 kcal/kg and PLF of 85%. Ministry of Coal has allocated Coal block for the Proposed Project. The Company plans to mine the coal by itself and transport through rail route to the Project site. Appropriate arrangements are proposed to be done. The captive mines will make the cost of generation for the Project very competitive and will also give complete control over the primary fuel for the Project.

The Project will require about 5000 cubic meter per hour make-up water during operation. The Company has received letter of intent from Water Resource Department of State Government for allocation of 10,417 cubic meters per hour water from River which flows near by the Project site.

1056 MW of power is proposed to be sold on 15 years take or pay PPA to BEL at the quoted tariff from COD. Balance 264 MW will be sold on Merchant basis. Considering the cost of generation of Rs. 2.21 per unit, Company does not envisage any difficulties in selling the power through merchant route.

Power Evacuation will be through two double circuit 400 KV transmission lines connecting the Project to the PGCIL substation and State TRANSCO substation.

The Electricity Act 2003 and subsequent National Electricity Policy and Tariff Policy have opened up several opportunities for the power sector. The Act allows the IPPs and captive power producers open access to transmission system, thus allowing them to bypass the SEBs and sell power directly to bulk consumers. Slowly open access in distribution system is also being allowed.

Assessment of the financial feasibility of the Proposed Project, delivers satisfactory financial parameters as per base financial model. It has also assessed the viability of the Project under the impact of various scenarios, which could be at variance with the base case scenarioassumed.

Subject to the weaknesses and threats enumerated in the SWOT analysis and the impact of the various scenarios as envisaged under the sensitivity analysis, the Proposed Project is viewed as economically viable.



10: LIMITATIONS

This analysis is limited to an examination of annualized expenses and revenue and represents a prototypical year of operations in base year dollars. The development of a complete financial plan must include consideration of cash flows for expenses and revenues, both capital and operating, on a year-by-year basis from the current year through and beyond the design year selected for the estimation of tariff. This analysis should examine alternative pay-as-you-go and debt financed scenarios, be conducted in year-of-expenditure dollars, and address the underlying uncertainties associated with inflation, interest rates, project cost (exclusive of inflation), foreign exchange rate, grant funding levels and rates of payment, and other factors over which the project sponsor will have no direct control.

The assumptions and sources of information underlying the development of the capital and operating cost estimates are an integral part of the financial analyses documented in this report. Uncertainties associated with fluctuating economic conditions and other factors may result in the actual results of the financial program varying from the projections in the financial analyses, and the variations could be material.

Some of the major limitations and issues regarding the project appraisal are as follow:

1. The rate of escalation is taken as constant over the life of the project (about 25 years); being the life of project large it is not easy to predict the actual cost and inflationary effect on the price of fuels and other inputs with the change in market conditions.

2. Cash flows not really known until the project is in service – no history of cash flows 3. Value of debt and equity driven by cash flow.4. Measure the value of different securities supported by project cash flow5. Risk analysis depends on contracts used to allocate risk to different parties6. Foreign exchange rate is taken on regular depreciation of rupees and this will be a

limitation to the model.7. Monthly analysis of construction is used for accurate representation of IDC, but; the

expense schedule is given on annual basis. So, proper distribution of expense on monthly basis and allocation of funds (using debt, equity or sub-debt) is a problem.



11: LEARNINGS

The experience and know-how gained from this internship, has left me in more compliant

form and stature in order to fare better in areas of similar interest. Now I here make it sort

with few but most important points what I have learned:

A practical exposure of financial world.

Learnt about investment scenario in power generation.

Know about various complicacies in power generation and their mitigation.

Know about project implication and investment.

Learnt financing aspect of various investment related parameters.

Learnt the formulation and analysis of various financials sheets through model.

Quantification of various risk related parameters.

Learnt corporate culture.



12: RECOMMENDATIONS

Recommendation:

To minimize the risk, the extent of financing to a single project should be proportionate;

it will also affect the exposure limit for borrower or utilities and chance to fund in more

projects rather in some.

With the deficit of electricity in our country, there is need of many projects and the

exposure limit should be increased to effectively assist the new projects. The exposure

limit of some utility is going to reached, which resist PFC to fund.

With the increasing IPPs in power generation the exposure to them should be more and

the portfolio size for IPPs should be increased. It will increase the revenue because of

higher interest rate and some extra charges.

Currently PFC has less % funding in renewable energy, PFC should also concentrate to

increase its share in renewable energy.

Nuclear power projects should be taken as a future prospect business of PFC.

In project appraisal, during calculation of IDC, the sub ordinate debt part should be

properly discussed with promoter. Sometimes it is a part of debt or equity. The interest

charge on sub-debt should be checked correctly.

The entity appraisal is very detailed and sensitive part of project financing, manual work

should be replaced with good software.

With the changes in project parameters, the re-rating of project should be done at an

appropriate time and linkages of interest rate, exposure limit and security to the new

project rating should be done.

There should be more bifurcation in the linkages to integrated project rating. A detailed

and comprehensive model study should be made for accordingly.



13: ANNEXURES

Annexure - I

Degree of safety with reference to entity appraisal rating

Grade Combinations

Degree of Safety with

regard to setting up

the new project

Comments

1 Grade IA, IB, IIA Very High

The fundamentally strong ability of the

promoters to set up the new project and

is unlikely to be adversely affected by

changes in circumstances

2 Grade IC, IIB, IIIA High

Adverse business conditions are unlikely

to affect the promoters ability to set up

the project

3Grade IIC, IIIB,

IVASatisfactory

Promoters ability to set up the project is

less likely to be adversely affected by

changes in circumstances than for lower

grades

4 Grade IIIC, IVB Average

Changes in circumstances are more

likely to lead to weakened ability of

promoters to set up the project than for

higher grades

5Grade ID, IID,

IVC, VA, VBBelow Average

While such promoters are less

susceptible to default in setting-up of the

project than those in lower grades,

uncertainties faced by them could

adversely affect their ability to set-up the

project

6

Grade IIID, IVD,

VC, VD, VIA,VIB,

VIC, VID

Low

Adverse business or economic

conditions and poor capabilities are

likely to lead to promoters lack of ability

to set-up the project



Annexure –II

Weightages to various parameters in project rating:

S. No. Parameters Weightage Points

Quantitative Parameters

1 First full year cost of generation w/o RoE 25% 12.5

2 Levellised tariff/ cost of generation with

RoE and tax

25% 12.5

3 Average DSCR 50% 25

Total 100% 50

Qualitative Parameters

1 Power offtake 20% 10

a IPP- Status of PPA & PSM and/or Captive-

Payment Security Mechanism

70% State

Sector

buyer

Private

sector

Buyer

7 10

b Buyers rating 30% 3 N.A.

2 Fuel supply 30% 15

3 Construction Contract 35% 15

a Type of contract and bidding 35% 5.25

b Experience of the EPC contractor 35% 5.25

c Commercial terms of Contract 30% 4.5

4 O&M 20% 10

Total 100% 50



Annexure-III

Linkage of Collateral Security to Integrated Project Rating

Integrated Rating Collateral security/Additional covenants to be prescribed 1-2 Pledge of Share: At least 26% of project equity till currency of PFC loan with non

disposal undertaking for additional 25% till 50% of loan is repaid.

DSRA: At least 2 quarters

On repayment of 50% loan, DSRA requirement may be brought

down to 1 quarter

3 Pledge of Share: At least 51% of project equity till currency of PFC loan, However

25% may be considered for release after 50% of loan is repaid.


4 Pledge of Share: At least 51% of project equity till currency of PFC loan,

However 21% may be considered for release after 75% of loan is

repaid.


Personal Guarantee of at least two promoter directors, where promoters do not have

prior experience in setting up projects.

In case of subordinate debt, additional pledge of 10% share would be required, which

may be considered for release after 50% of entire project loan is repaid.

5Pledge of Share: At least 51% of project equity till currency of PFC loan, However

25% may be considered for release after 50% of loan is repaid.


Personal guarantee of at least two promoter directors.

Option to convert up to 10% of PFC loan disbursed, into equity shares at book value

any time up to 5 years after COD

In case of subordinate debt, additional pledge of 16% share would be required, which

may be considered for release after 50% of entire project loan is repaid.



Annexure-IV

PFC Guidelines for term loan:

1. Purpose

To provide finance to all types of projects in state & private sector viz. generation, transmission, distribution, renovation & modernization, uprating, environment upgradation, metering, etc. The infrastructure projects having forward and backward linkages with power projects are also covered.

2. Eligible entities

The entities engaged in generation, transmission, trading, distribution of power or any combination of these activities including captive / co-gen power producers. The entities engaged in the infrastructure projects with forward / backward linkages to power projects.

3. Extent of assistance (restricted to actual requirement of funds)

Central/State sector entities- Up to 70% of the project cost

Reforming State sector entities- Up to 80% of the cost of project

Private sector entities*- Up to 50% of the project cost

The extent of funding may vary from project to project.

* In case of thermal generation projects and hydro projects, the financial assistance is generally up to 20% and 25% of the project cost respectively. However, the enhanced limit can be considered for loan size of Rs. 500 crs and above or where PFC is a lead institution. In case of infrastructure projects with forward / backward linkages to power projects the financial assistance is up to 20% of the project cost.

4. Interest rates & other charges

Interest rates as notified by the Corporation from time to time. Special interest rates are also available for loans exceeding Rs. 700 crs for generation projects in state sector and Rs. 500 crs in private sector.

Interest rates prevailing on the date of disbursement(s) shall be applicable. Incentive / rebate available for timely payment of dues for state/central sector utilities. For all type of generation projects and infrastructure projects with forward and

backward linkages to power projects, reduction in interest rate after commissioning of projects / COD as per prevailing policy.

Penal interest payable on default-payments. Commitment fees / upfront fees as may be applicable for respective borrowers from

time to time. Processing fee, Lead fee & facility Agent fee for private sector entities as applicable

from time to time.



5. Interest rate reset option

Option to avail interest rate with reset after every 3 years or with reset after 10 years. Interest reset condition to apply from the standard due date following the date of first

disbursement after 3/10 years, as the case may be.

6. Moratorium

Moratorium on principal is available upto 6 months from the date of project commissioning / COD. There is no moratorium on interest payment.

7. Disbursement mechanism

Disbursement will be made, against bills, as per the ‘Disbursement Schedule’ submitted by the borrower. In case of small loans (below Rs. 20 Crs.), simplified disbursement procedure is applicable. In the case of private sector borrower, disbursement is made through Trust and Retention Account mechanism.

8. Interest payment

Interest is to be paid quarterly, on standard due dates i.e. 15/4, 15/7, 15/10 and 15/1 every year.

9. Repayment

Repayment is to be made in maximum years of:

Type of Project

State/ Central Sector Private Sector

3 years/10 years reset clause

3 years Reset Clause

10 Years Reset Clause

Hydro Generation Project 20 15 12

Thermal Generation Project 15 15 12

Studies, Consultancy, Training, R&D, S&I, Computerisation, Meters

5 5 5

All other Projects 15 12 10

The first repayment installment will become due on the standard due date immediately following the end of moratorium period. Borrower may also opt for a shorter repayment period.

10. Security requirements

State / Central government or bank guarantee or charge on assets, for state and central sector entities, while charge on project assets for others. and

Letter of Credit or Tripartite Escrow Agreement amongst the borrower, the bank PFC for state and central sector entities while Trust and Retention Account mechanism for others.



Corporate and/or personal guarantee of the promoters for private sector, if the outcome of appraisal establishes a requirement for the same.

Other securities, as may be necessary.

11. Exposure Limit

Maximum Admissible Exposure to entities would be linked to the exposure available in terms

of Prudential Norms adopted by PFC from time to time, as under:

a. For state/central sector Borrowers:

State Sector

Borrowers

As per OPS Norms As per Prudential Norms

Category A+ 100% 150% of PFC’s Net worth and 1.30 times

security coverage for exposure above 100%

Category A 100% 150% of PFC’s Net worth and 1.35 times


Category B 80% 125% of PFC’s Net worth and 1.40 times


Category C 25% 25%

b. Private Borrowers:

Single Company Single Group of Companies

Basic Limit 15% 25%

Additional Exposure for Infrastructure Loan

5% 10%

Total 20% 35%

Source: http://www.pfc.gov.in/termloan.pdf



Annexure-V

Year Total Tariff (Rs/KWh)

1 2.553

2 2.553

3 2.553

4 2.553

5 2.553

6 2.5748

7 2.5912

8 2.6095

9 2.6299

10 2.6523

11 2.6769

12 2.7038

13 2.5091

14 2.5729

15 2.6392

16 2.7081

17 2.7799

18 2.8545

19 2.932

20 3.0127

21 3.0966

22 3.1839

23 3.2746

24 3.369

25 3.4672



ANNEXURE VI: INPUTS

Project Capacity

No. of units 2

Capacity per unit MW 660Total project capacity MW 1320

Project Cost Without IDC Rs Crores

5925.00

IDC Rs Crores

1166.86

With IDC Rs Crores

7091.86

Financing Plan Equity (20%) Rs Crores

5318.89

Debt (75%) Rs Crores

1772.96

Upfront Equity (35%) Rs Crores

620.54

Sub debt as part of equity (20%) Rs Crores

354.59

Pre COD p.a. 11.50%Post COD p.a. 11.25%Working Capital p.a. 13.00%

Repayment Repayment Period Years 10Moratorium Period Months 6Principle Repayment Start Date Date Jul-2013Principle Repayment End Date Date Jan-2023Interest Repayment Start Date Date Jan-2012Interest Repayment End Date Date Jan-2023

PPA Details PPA with BEL(including all units) MW% of Total Capacity 80.00%PPA Tariff Rs /

unitAS Given Annexure V

No. of years Years 25Selling through Merchant Basis (including all units)

MW

% of Total Capacity 20.00%PPA Tariff Rs /

unit3 with escalation of 5%

No. of years Years 25Reduction Due to Wheeling 5%

Tax Rates Corporate Tax 33.99%MAT 11.33%



ANNEXURE VI: ASSUMPTION

Technical Parameters GSHR Kcal/KWH 2250Auxiliary Consumption % 9%Plant load factor % 85%

O&M Escalation 4%O&M Expense for COD yr(2010-2011) Rs.

Lakh/MW/yr13.08

Fuel : Primary Fuel Price Rs/tonne 750Price Escalation p.a. 5%Gross Calorific Value Kcal/Kg 4700

Secondary Fuel Price Rs/tonne 25000Gross Calorific Value Kcal/L 10000Secondary Fuel Consumption ml/KWH 1Price Escalation % 4%

Transportation & Handling Charges Rs/tonne 235.86Escalation % 5%

Working Capital Limits

Coal Stock months 2

Secondary Fuel months 2O&M Expenses months 1Maintenance Spares (% of O&M Expense) % 20%Receivables from Energy Sales months 2

Depreciation Rate For Tariff Calculation p.a 5.28%Land & Site Development Rs Crores 0

Depreciation for IT Calculation

Machinery 25%

Building 10%

Others Discount Rate (as per CERC norms as on 24-09-2007)

13%

Return on Equity 15.50%Project Life Years 25



ANNEXURE VI (A): DEBT SERVICING

Year ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

0 1 2 3 4 5 6 7 8 9 10 11

Debt Outstanding 5318.89 4919.98 4388.09 3856.20 3324.31 2792.42 2260.53 1728.64 1196.75 664.86 132.97 0.00

Prin

cipl

e Re

paym

ents

April 0.00 0.00 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97

July 0.00 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 0.00

October 0.00 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 0.00

January 0.00 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 132.97 0.00

Total FY Repayment 0.00 398.92 531.89 531.89 531.89 531.89 531.89 531.89 531.89 531.89 531.89 132.97

Cumulative Principle Repayment

0.00 398.92 930.81 1462.70 1994.59 2526.47 3058.36 3590.25 4122.14 4654.03 5185.92 5318.89

Inte

rest

Pa

ymen

ts

April 0.00 162.89 150.67 134.39 118.10 101.81 85.52 69.23 52.94 36.65 20.36 4.07

July 0.00 162.89 146.60 130.31 114.02 97.73 81.45 65.16 48.87 32.58 16.29 0.00

October 0.00 162.89 142.53 126.24 109.95 93.66 77.37 61.08 44.80 28.51 12.22 0.00

January 162.89 154.75 138.46 122.17 105.88 89.59 73.30 57.01 40.72 24.43 8.14 0.00

Total Yearly Interest payments 162.89 643.42 578.26 513.11 447.95 382.79 317.64 252.48 187.32 122.17 57.01 4.07

Total Debt Servicing 162.89 1042.34 1110.15 1045.00 979.84 914.68 849.53 784.37 719.21 654.06 588.90 137.04



ANNEXURE VI (B): IDC

Project Phasing Month Aug-2008

Sep-2008

Oct-2008

Nov-2008

Dec-2008

Jan-2009

Feb-2009

Mar-2009

Apr-2009

May-2009

Jun-2009

Jul-2009

Aug-2009

May-09

FY 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2009 2010 20101 2 3 4 5 6 7 8 9 10 11 12 13 14

Total 1.80%Percentage 100.00% 2.10% 2.10% 2.09% 1.30% 1.30% 1.30% 1.12% 1.12% 1.12% 1.80% 1.80% 1.80% 1.80% 127.65Amount 7091.86 148.93 148.93 148.22 92.19 92.19 92.19 79.43 79.43 79.43 127.65 127.65 127.65 127.65 1599.21

Upfront Equity 620.54 308.62 173.60 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Upfront Debt 1861.61 0.00 135.02 244.32 244.32 244.32 231.46 25.72 0.00 0.00 0.00 0.00 0.00 0.00 127.65

Matching Equity 1152.43 0.00 0.00 0.00 0.00 0.00 0.00 61.72 69.44 73.30 53.04 53.04 53.04 48.22 0.00Matching Debt 3457.28 0.00 0.00 0.00 0.00 0.00 0.00 144.02 162.02 171.03 123.77 123.77 123.77 112.52 0.00

Total Equity 1772.96 308.62 173.60 0.00 0.00 0.00 0.00 61.72 69.44 73.30 53.04 53.04 53.04 48.22 0.00Total debt 5318.89 0.00 135.02 244.32 244.32 244.32 231.46 169.74 162.02 171.03 123.77 123.77 123.77 112.52 127.65

Sub debt component 354.59 308.62 173.60 0.00 0.00 0.00 0.00 61.72 69.44 29.58 0.00 0.00 0.00 0.00 0.00Pure equity component

1418.37 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 43.72 53.04 53.04 53.04 48.220.00

Interest 1166.86 0.00 0.65 2.46 4.81 7.15 9.43 11.35 12.94 14.54 15.95 17.13 18.32 19.45 13.52



Project Phasing

Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10

2010 2010 2010 2010 2010 2010 2010 2010 2010 2010 2011 2011 2011 2011 2011 201115 16 17 18 19 20 21 22 23 24 25 26 27 28 29 301.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.80% 1.50% 1.50% 1.50%

Percentage 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 127.65 106.38 106.38 106.38Amount 1726.87 1854.52 1982.17 2109.83 2237.48 2365.14 2492.79 2620.44 2748.10 2875.75 3003.40 3131.06 3258.71 3365.09 3471.47 3577.84

Upfront Equity

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Upfront Debt

127.65 127.65 127.65 127.65 127.65 127.65 117.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Matching Equity

0.00 0.00 0.00 0.00 0.00 0.00 2.66 31.91 31.91 31.91 31.91 31.91 31.91 26.59 26.59 26.59

Matching Debt

0.00 0.00 0.00 0.00 0.00 0.00 7.98 95.74 95.74 95.74 95.74 95.74 95.74 79.78 79.78 79.78

Total Equity

0.00 0.00 0.00 0.00 0.00 0.00 2.66 31.91 31.91 31.91 31.91 31.91 31.91 26.59 26.59 26.59

Total debt 127.65 127.65 127.65 127.65 127.65 127.65 124.99 95.74 95.74 95.74 95.74 95.74 95.74 79.78 79.78 79.78

Sub debt component

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Pure equity component

0.00 0.00 0.00 0.00 0.00 0.00 2.66 31.91 31.91 31.91 31.91 31.91 31.91 26.59 26.59 26.59

Interest 14.85 16.18 17.51 18.84 20.17 21.50 22.81 23.96 24.96 25.96 26.95 27.95 28.95 29.86 30.69 31.53



Project Phasing Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11

2011 2011 2011 2011 2011 2011 2012 2012 2012 2012 2012 2012 2012 2012 201231 32 33 34 35 36 37 38 39 40 41 42 43 44 453.00% 3.00% 3.00% 3.00% 3.00% 3.00% 4.35% 4.35% 4.35% 4.50% 4.50% 4.50% 2.00% 2.00% 1.00%

Percentage 212.76 212.76 212.76 212.76 212.76 212.76 308.50 308.50 308.50 319.13 319.13 319.13 141.84 141.84 70.92Amount 3790.60 4003.35 4216.11 4428.87 4641.62 4854.38 5162.87 5471.37 5779.87 6099.00 6418.13 6737.27 6879.10 7020.94 7091.86

Upfront Equity 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Upfront Debt 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Matching Equity 53.19 53.19 53.19 53.19 53.19 53.19 77.12 77.12 77.12 79.78 79.78 79.78 35.46 35.46 17.73

Matching Debt 159.57 159.57 159.57 159.57 159.57 159.57 231.37 231.37 231.37 239.35 239.35 239.35 106.38 106.38 53.19

Total Equity 53.19 53.19 53.19 53.19 53.19 53.19 77.12 77.12 77.12 79.78 79.78 79.78 35.46 35.46 17.73Total debt 159.57 159.57 159.57 159.57 159.57 159.57 231.37 231.37 231.37 239.35 239.35 239.35 106.38 106.38 53.19

Sub debt component 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Pure equity component 53.19 53.19 53.19 53.19 53.19 53.19 77.12 77.12 77.12 79.78 79.78 79.78 35.46 35.46 17.73

Interest 32.77 34.43 36.10 37.76 39.42 41.08 43.12 45.53 47.94 50.39 52.88 55.38 57.18 58.29 59.12



ANNEXURE VI(C): WORKING CAPITAL

Year Ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20251 2 3 4 5 6 7 8 9 10 11 12 13 14

ITEMSNorm

Primary fuel 2 month 48.88 102.06 106.56 111.25 116.15 121.27 126.62 132.20 138.04 144.14 150.51 157.16 164.11 171.38Secondary fuel

2 month8.19 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38

O&M Expense

1 month7.19 16.08 17.00 17.97 19.00 20.09 21.24 22.45 23.74 25.09 26.53 28.05 29.65 31.35

Maintenance Spares (1% of capital cost)

20% O&M

17.27 38.59 40.80 43.14 45.60 48.21 50.97 53.89 56.97 60.23 63.67 67.31 71.16 75.23

Receivables from Energy Sales

2 month152.23 304.46 304.46 304.46 304.46 307.06 309.01 311.20 313.63 316.30 319.23 322.44 299.22 306.83

WORKING CAPITALTotal Working Capital 233.76 477.58 485.20 493.20 501.59 513.01 524.22 536.12 548.75 562.14 576.32 591.34 580.53 601.17Increase In Working Capital 233.76 243.82 7.62 8.00 8.40 11.41 11.21 11.90 12.64 13.38 14.18 15.02 -10.81 20.64WORKING CAPITAL DEBTWorking Capital Debt 175.32 358.19 363.90 369.90 376.20 384.76 393.16 402.09 411.56 421.60 432.24 443.51 435.40 450.88Increase In Working Capital Debt

175.32 182.86 5.71 6.00 6.30 8.56 8.41 8.92 9.48 10.04 10.64 11.27 -8.11 15.48

CURRENT ASSETSTotal Current Assets 226.57 461.50 468.20 475.22 482.59 492.92 502.98 513.67 525.02 537.04 549.79 563.30 550.88 569.82Increase in Current Assets 226.57 234.93 6.70 7.03 7.37 10.33 10.06 10.68 11.35 12.03 12.75 13.50 -12.42 18.94



Year Ending March 31 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 203615 16 17 18 19 20 21 22 23 24 25

ITEMSNorm

Primary fuel 2 month 178.97 186.90 195.18 203.84 212.89 222.34 232.22 242.54 253.33 264.60 276.38Secondary fuel 2 month 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38O&M Expense 1 month 33.14 35.04 37.04 39.16 41.40 43.77 46.27 48.92 51.71 54.67 57.80Maintenance Spares (1% of capital cost)

20% O&M 79.54 84.09 88.90 93.98 99.36 105.04 111.05 117.40 124.12 131.21 138.72

Receivables from Energy Sales

2 month314.74 322.95 331.52 340.41 349.66 359.28 369.29 379.70 390.51 401.77 413.48

WORKING CAPITAL

Total Working Capital 622.76 645.35 669.02 693.77 719.68 746.81 775.20 804.93 836.05 868.64 902.76Increase In Working Capital 21.59 22.59 23.66 24.76 25.90 27.13 28.40 29.73 31.12 32.59 34.12WORKING CAPITAL DEBTWorking Capital Debt 467.07 484.02 501.76 520.33 539.76 560.10 581.40 603.70 627.04 651.48 677.07Increase In Working Capital Debt 16.19 16.94 17.75 18.57 19.43 20.35 21.30 22.30 23.34 24.44 25.59CURRENT ASSETSTotal Current Assets 589.62 610.32 631.98 654.62 678.28 703.04 728.93 756.02 784.33 813.96 844.96Increase in Current Assets 19.80 20.70 21.66 22.64 23.66 24.76 25.89 27.09 28.32 29.63 31.00



ANNEXURE VI (D): EFFECTIVE TARIFF

Year Ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 20241 2 3 4 5 6 7 8 9 10 11 12 13

Energy Supplied thr PPA

Million Units 3577.65 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31

Energy Supplied on Merchant Basis

Million Units 894.41 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83

Total Energy Supplied

Million Units 4472.07 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Tariff for CSEB Rs/Unit 2.55300 2.55300 2.55300 2.55300 2.55300 2.57480 2.59120 2.60950 2.62990 2.65230 2.67690 2.70380 2.57290

Tariff Assumed for Sale on Merchant basis

Rs/Unit3.00000 3.06000 3.12120 3.18362 3.24730 3.31224 3.37849 3.44606 3.51498 3.58528 3.65698 3.73012 3.88082

Tariff Assumed Less Wheeling

RS/Unit 2.85000 2.90700 2.96514 3.02444 3.08493 3.14663 3.20956 3.27375 3.33923 3.40601 3.47413 3.54362 3.68678

Effective Tariff Rs/unit 2.61240 2.62380 2.63543 2.64729 2.65939 2.68917 2.71487 2.74235 2.77177 2.80304 2.83635 2.87176 2.79568



Year Ending March 31 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 203614 15 16 17 18 19 20 21 22 23 24 25

Energy Supplied thr PPA

Million Units 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31

Energy Supplied on Merchant Basis

Million Units 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83

Total Energy Supplied

Million Units 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Tariff for CSEB Rs/Unit 2.50910 2.63920 2.70810 2.77990 2.85450 2.93200 3.01270 3.09660 3.18390 3.27460 3.36900 3.46720

Tariff Assumed for Sale on Merchant basis

Rs/Unit3.80473 3.95844 4.03761 4.11836 4.20072 4.28474 4.37043 4.45784 4.54700 4.63794 4.73070 4.82531

Tariff Assumed Less Wheeling

RS/Unit 3.61449 3.76051 3.83572 3.91244 3.99069 4.07050 4.15191 4.23495 4.31965 4.40604 4.49416 4.58405

Effective Tariff Rs/unit 2.73018 2.86346 2.93362 3.00641 3.08174 3.15970 3.24054 3.32427 3.41105 3.50089 3.59403 3.69057



ANNEXURE VI (E): FUEL

Yr Ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20231 2 3 4 5 6 7 8 9 10 11 12

Primary Fuel Cost Rs Crores 293.29 612.39 639.34 667.49 696.89 727.61 759.70 793.22 828.23 864.82 903.03 942.96

Secondary Fuel Cost

Rs Crores 0.14 0.29 0.30 0.31 0.32 0.34 0.35 0.36 0.38 0.39 0.41 0.43

Total Fuel Cost Rs Crores 293.43 612.68 639.64 667.80 697.22 727.95 760.05 793.58 828.61 865.21 903.44 943.39

Capacity Commissioned

MW 880.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00Energy Generated Million

Units 4914.36 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72Energy Sold Million

Units 4472.07 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Energy Transmitted thr PPA

Million Units 3577.65 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31

Energy Transmitted on Merchant Basis

Million Units 894.41 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83

Capital Cost Component

Rs Crores per month

4255.12 6382.67 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86

Equity Cost Component

Rs Crores per month

3191.34 4787.01 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89

Debt Cost Component

Rs Crores per month

1063.78 1595.67 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96



Yr Ending March 31 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 203613 14 15 16 17 18 19 20 21 22 23 24 25

Primary Fuel Cost Rs Crores 1028.26 1073.80 1121.38 1171.09 1223.04 1277.31 1334.03 1393.30 1455.23 1519.95 1587.58 1658.27 1732.13

Secondary Fuel Cost

Rs Crores 0.46 0.48 0.50 0.52 0.54 0.56 0.58 0.61 0.63 0.66 0.68 0.71 0.74

Total Fuel Cost Rs Crores 1028.72 1074.28 1121.88 1171.61 1223.57 1277.87 1334.61 1393.90 1455.86 1520.61 1588.27 1658.97 1732.87

Capacity Commissioned

MW 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00 1320.00Energy Generated Million

Units 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72 9828.72Energy Sold Million

Units 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Energy Transmitted thr PPA

Million Units 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31 7155.31

Energy Transmitted on Merchant Basis

Million Units 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83 1788.83

Capital Cost Component

Rs Crores per month

7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86 7091.86

Equity Cost Component

Rs Crores per month

5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89 5318.89

Debt Cost Component

Rs Crores per month

1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96



ANNEXURE VI (F): TARIFF

Year Ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 20251 2 3 4 5 6 7 8 9 10 11 12 13 14

VARIABLE TARIFFEnergy Available for Sale

Million Units

4472.07 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Variable Fuel Cost Rs Crores 293.43 612.68 639.64 667.80 697.22 727.95 760.05 793.58 828.61 865.21 903.44 943.39 985.12 1028.72Variable Fuel Cost per Unit

Rs/KWH 0.66 0.69 0.72 0.75 0.78 0.81 0.85 0.89 0.93 0.97 1.01 1.05 1.10 1.15

FIXED TARIFFInterest Rs Crores 162.89 643.42 578.26 513.11 447.95 382.79 317.64 252.48 187.32 122.17 57.01 4.07 0.00 0.00Return on Equity Rs Crores 123.66 247.33 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81Depreciation Rs Crores 196.61 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 106.79 106.79Cumulative Depreciation

Rs Crores 196.61 458.77 720.92 983.07 1245.22 1507.37 1769.53 2031.68 2293.83 2555.98 2818.13 3080.29 3187.07 3293.86

O&M Expense Rs Crores 86.33 192.97 204.01 215.68 228.02 241.06 254.85 269.43 284.84 301.13 318.35 336.56 355.82 376.17Interest on Working Capital

Rs Crores16.44 44.77 45.49 46.24 47.02 48.09 49.15 50.26 51.45 52.70 54.03 55.44 54.42 56.36

Income Tax Rs Crores 46.75 66.93 71.11 133.65 186.70 234.27 272.30 304.37 331.89 355.86 377.07 391.96 387.67 336.23Fixed Cost Rs Crores 632.68 1457.58 1435.83 1445.64 1446.65 1443.18 1430.89 1413.50 1392.46 1368.82 1343.43 1324.99 1179.50 1150.36Fixed Cost per Unit Rs/KWH 1.41 1.63 1.61 1.62 1.62 1.61 1.60 1.58 1.56 1.53 1.50 1.48 1.32 1.29Fixed Cost w/o ROE Rs Crores 509.01 1210.25 1161.02 1170.83 1171.84 1168.37 1156.08 1138.69 1117.65 1094.01 1068.62 1050.18 904.69 875.55Fixed Cost per Unit w/o ROE

Rs/KWH1.42 1.69 1.62 1.64 1.64 1.63 1.62 1.59 1.56 1.53 1.49 1.47 1.26 1.22

Total Cost per Unit w/o ROE

Rs/KWH2.08 2.38 2.34 2.38 2.42 2.45 2.47 2.48 2.49 2.50 2.50 2.52 2.37 2.37

Total Cost per Unit Rs/KWH 2.0709 2.3147 2.3205 2.3629 2.3970 2.4274 2.4496 2.4676 2.4833 2.4978 2.5121 2.5362 2.4202 2.4363Effective Tariff Rs/KWH 2.61240 2.62380 2.63543 2.64729 2.65939 2.68917 3.20956 3.27375 2.77177 2.80304 2.83635 2.87176 2.73018 2.79568PV CalculationPV Factor 0.88 0.78 0.69 0.61 0.54 0.48 0.43 0.38 0.33 0.29 0.26 0.23 0.20 0.18DISCOUNTED TARIFFVariable Tariff Rs/KWH 0.58 0.54 0.50 0.46 0.42 0.39 0.36 0.33 0.31 0.28 0.26 0.24 0.22 0.21Fixed Tariff including ROE

Rs/KWH 1.25 1.28 1.11 0.99 0.88 0.78 0.68 0.59 0.52 0.45 0.39 0.34 0.27 0.23

Total Tariff including ROE

Rs/KWH 1.83 1.81 1.61 1.45 1.30 1.17 1.04 0.93 0.83 0.74 0.65 0.59 0.49 0.44

Total Tariff w/o ROE

Rs/KWH1.84 1.86 1.62 1.46 1.31 1.18 1.05 0.93 0.83 0.74 0.65 0.58 0.48 0.43

Effective Tariff Rs/KWH 2.31 2.05 1.83 1.62 1.44 1.29 1.36 1.23 0.92 0.83 0.74 0.66 0.56 0.51



Year Ending March 31 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 203613 14 15 16 17 18 19 20 21 22 23 24 25

VARIABLE TARIFFEnergy Available for Sale

Million Units

8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14 8944.14

Variable Fuel Cost Rs Crores 985.12 1028.72 1074.28 1121.88 1171.61 1223.57 1277.87 1334.61 1393.90 1455.86 1520.61 1588.27 1658.97Variable Fuel Cost per Unit

Rs/KWH 1.10 1.15 1.20 1.25 1.31 1.37 1.43 1.49 1.56 1.63 1.70 1.78 1.85

FIXED TARIFFInterest Rs Crores 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Return on Equity Rs Crores 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81 274.81Depreciation Rs Crores 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79Cumulative Depreciation

Rs Crores3187.07 3293.86 3400.64 3507.43 3614.21 3721.00 3827.79 3934.57 4041.36 4148.14 4254.93 4361.71 4468.50

O&M Expense Rs Crores 355.82 376.17 397.68 420.43 444.48 469.91 496.78 525.20 555.24 587.00 620.58 656.07 693.60Interest on Working Capital

Rs Crores54.42 56.36 58.38 60.50 62.72 65.04 67.47 70.01 72.68 75.46 78.38 81.43 84.63

Income Tax Rs Crores 387.67 336.23 336.38 335.48 333.68 331.01 327.53 323.31 318.32 312.59 306.06 298.76 290.64Fixed Cost Rs Crores 1179.50 1150.36 1174.05 1198.01 1222.48 1247.56 1273.38 1300.12 1327.83 1356.65 1386.61 1417.86 1450.47Fixed Cost per Unit Rs/KWH 1.32 1.29 1.31 1.34 1.37 1.39 1.42 1.45 1.48 1.52 1.55 1.59 1.62Fixed Cost w/o ROE Rs Crores 904.69 875.55 899.24 923.20 947.67 972.75 998.57 1025.31 1053.02 1081.84 1111.80 1143.05 1175.66Fixed Cost per Unit w/o ROE

Rs/KWH1.26 1.22 1.26 1.29 1.32 1.36 1.40 1.43 1.47 1.51 1.55 1.60 1.64

Total Cost per Unit w/o ROE

Rs/KWH2.37 2.37 2.46 2.54 2.63 2.73 2.82 2.93 3.03 3.14 3.25 3.37 3.50

Total Cost per Unit Rs/KWH 2.4202 2.4363 2.5137 2.5937 2.6767 2.7629 2.8524 2.9458 3.0430 3.1445 3.2504 3.3610 3.4765Effective Tariff Rs/KWH 2.73018 2.79568 2.86346 2.93362 3.00641 3.08174 3.15970 3.24054 3.32427 3.41105 3.50089 3.59403 3.69057PV CalculationPV Factor 0.20 0.18 0.16 0.14 0.13 0.11 0.10 0.09 0.08 0.07 0.06 0.05 0.05DISCOUNTED TARIFFVariable Tariff Rs/KWH 0.22 0.21 0.19 0.18 0.16 0.15 0.14 0.13 0.12 0.11 0.10 0.09 0.09Fixed Tariff including ROE

Rs/KWH0.27 0.23 0.21 0.19 0.17 0.15 0.14 0.13 0.11 0.10 0.09 0.08 0.08

Total Tariff including ROE

Rs/KWH0.49 0.44 0.40 0.37 0.34 0.31 0.28 0.26 0.23 0.21 0.20 0.18 0.16

Total Tariff w/o ROE

Rs/KWH0.48 0.43 0.39 0.36 0.33 0.30 0.28 0.25 0.23 0.21 0.20 0.18 0.16

Effective Tariff Rs/KWH 0.56 0.51 0.46 0.42 0.38 0.34 0.31 0.28 0.26 0.23 0.21 0.19 0.17



ANNEXURE VI (G): PROFIT & LOSS

1 2 3 4 5 6 7 8 9 10 11 12 13Year ending March 31, 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024Revenue from energy sale to BEL

913.38 1826.75 1826.75 1826.75 1826.75 1842.35 1854.08 1867.18 1881.77 1897.80 1915.40 1934.65 1795.34

Revenue from energy sale on Marchant Basis

254.91 520.01 530.41 541.02 551.84 562.88 574.14 585.62 597.33 609.28 621.46 633.89 646.57

Total Revenue 1168.28 2346.76 2357.16 2367.77 2378.59 2405.23 2428.22 2452.80 2479.10 2507.08 2536.87 2568.54 2441.91Expenses

Fuel 283.55 590.99 615.88 641.84 668.90 697.11 726.53 757.19 789.17 822.51 857.26 893.51 931.30O&M expenses 86.33 192.97 204.01 215.68 228.02 241.06 254.85 269.43 284.84 301.13 318.35 336.56 355.82Depreciation 196.61 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 106.79Interest payments 179.21 687.85 623.38 558.94 494.53 430.41 366.26 302.17 238.15 174.20 110.32 58.73 53.58

Total expenditure 745.71 1733.96 1705.43 1678.61 1653.60 1630.73 1609.79 1590.95 1574.31 1559.99 1548.09 1550.95 1447.48

Profit before tax, PBT 422.58 612.80 651.74 689.16 724.99 774.49 818.43 861.85 904.79 947.09 988.78 1017.59 994.43

PBT+Deprn on books 619.19 809.41 913.89 951.31 987.14 1036.65 1080.58 1124.00 1166.95 1209.24 1250.93 1279.74 1256.58

PBT for IT purposes -99.93 -98.58 220.17 419.58 578.03 720.54 835.16 932.42 1016.50 1090.32 1156.26 1203.81 1195.19

Payable tax 47.88 69.43 74.84 142.61 196.47 244.91 283.87 316.93 345.51 370.60 393.01 409.18 406.25Applicable tax 47.88 69.43 74.84 142.61 196.47 244.91 283.87 316.93 345.51 370.60 393.01 409.18 406.25

Corporate tax -33.97 -33.51 74.84 142.61 196.47 244.91 283.87 316.93 345.51 370.60 393.01 409.18 406.25MAT 47.88 69.43 73.84 78.08 82.14 87.75 92.73 97.65 102.51 107.31 112.03 115.29 112.67

PAT 374.70 543.37 576.90 546.55 528.52 529.58 534.56 544.92 559.29 576.49 595.76 608.41 588.18Accumulated PAT 374.70 918.07 1494.97 2041.51 2570.03 3099.61 3634.17 4179.09 4738.38 5314.87 5910.64 6519.05 7107.23

Depreciation as per IT Act 719.12 907.99 693.71 531.74 409.11 316.11 245.43 191.58 150.45 118.92 94.67 75.93 61.38Machinery depreciation 658.53 823.17 617.38 463.03 347.27 260.46 195.34 146.51 109.88 82.41 61.81 46.36 34.77

Machinery, WDV 3292.67 2469.50 1852.13 1389.09 1041.82 781.37 586.02 439.52 329.64 247.23 185.42 139.07 104.30Buildings depreciation 60.59 84.82 76.34 68.71 61.83 55.65 50.09 45.08 40.57 36.51 32.86 29.58 26.62

Buildings, WDV 848.21 763.39 687.05 618.35 556.51 500.86 450.78 405.70 365.13 328.62 295.75 266.18 239.56



14 15 16 17 18 19 20 21 22 23 24 25Year ending March 31, 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036Revenue from energy sale to BEL

1840.99 1888.43 1937.73 1989.10 2042.48 2097.94 2155.68 2215.71 2278.18 2343.08 2410.62 2480.89

Revenue from energy sale on Marchant Basis

659.50 672.69 686.14 699.87 713.87 728.14 742.71 757.56 772.71 788.16 803.93 820.01

Total Revenue 2500.49 2561.12 2623.87 2688.97 2756.35 2826.08 2898.38 2973.27 3050.89 3131.24 3214.55 3300.90Expenses

Fuel 970.70 1011.79 1054.63 1099.31 1145.90 1194.48 1245.14 1297.98 1353.07 1410.54 1470.46 1532.96O&M expenses 376.17 397.68 420.43 444.48 469.91 496.78 525.20 555.24 587.00 620.58 656.07 693.60Depreciation 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79Interest payments 55.45 57.41 59.45 61.59 63.83 66.17 68.62 71.18 73.86 76.66 79.59 82.66

Total expenditure 1509.11 1573.67 1641.30 1712.17 1786.42 1864.22 1945.74 2031.18 2120.72 2214.56 2312.92 2416.02

Profit before tax, PBT 991.38 987.45 982.57 976.81 969.93 961.86 952.64 942.09 930.17 916.68 901.63 884.88

PBT+Deprn on books 1098.17 1094.24 1089.36 1083.59 1076.72 1068.65 1059.43 1048.88 1036.96 1023.47 1008.42 991.67

PBT for IT purposes 1048.14 1053.12 1055.29 1055.13 1052.75 1048.31 1042.06 1033.94 1024.03 1012.23 998.60 983.05

Payable tax 356.26 357.96 358.69 358.64 357.83 356.32 354.19 351.44 348.07 344.06 339.42 334.14Applicable tax 356.26 357.96 358.69 358.64 357.83 356.32 354.19 351.44 348.07 344.06 339.42 334.14

Corporate tax 356.26 357.96 358.69 358.64 357.83 356.32 354.19 351.44 348.07 344.06 339.42 334.14MAT 112.32 111.88 111.33 110.67 109.89 108.98 107.93 106.74 105.39 103.86 102.16 100.26

PAT 635.12 629.50 623.88 618.17 612.10 605.54 598.45 590.66 582.10 572.63 562.21 550.74Accumulated PAT 7742.35 8371.85 8995.73 9613.90 10226.00 10831.54 11429.99 12020.64 12602.74 13175.37 13737.58 14288.32

Depreciation as per IT Act 50.03 41.12 34.07 28.46 23.97 20.33 17.37 14.94 12.92 11.24 9.82 8.62Machinery depreciation 26.07 19.56 14.67 11.00 8.25 6.19 4.64 3.48 2.61 1.96 1.47 1.10

Machinery, WDV 78.22 58.67 44.00 33.00 24.75 18.56 13.92 10.44 7.83 5.87 4.41 3.30Buildings depreciation 23.96 21.56 19.40 17.46 15.72 14.15 12.73 11.46 10.31 9.28 8.35 7.52

Buildings, WDV 215.60 194.04 174.64 157.18 141.46 127.31 114.58 103.12 92.81 83.53 75.18 67.66



ANNEXURE VI (H): CASH FLOW1 2 3 4 5 6 7 8 9 10 11 12 13

Year ending, March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Inflow

Equity 1772.96 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Debt 5551.01 241.85 7.28 7.63 8.00 11.00 10.76 11.42 12.13 12.84 13.60 14.41 -11.47

Term loan 5318.89 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

WC debt 232.11 241.85 7.28 7.63 8.00 11.00 10.76 11.42 12.13 12.84 13.60 14.41 -11.47

PBT 422.58 612.80 651.74 689.16 724.99 774.49 818.43 861.85 904.79 947.09 988.78 1017.59 994.43Depreciation 196.61 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 106.79Total cash inflow 7746.55 1116.80 921.16 958.94 995.14 1047.64 1091.35 1135.42 1179.07 1222.08 1264.53 1294.15 1089.74

Outflow

Project expenditure 7091.86 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WC expenditure 224.92 232.96 6.36 6.66 6.98 9.91 9.61 10.21 10.84 11.48 12.17 12.89 -13.07Tax 47.88 69.43 74.84 142.61 196.47 244.91 283.87 316.93 345.51 370.60 393.01 409.18 406.25Loan repayments 0.00 398.92 531.89 531.89 531.89 531.89 531.89 531.89 531.89 531.89 531.89 132.97 0.00Total cash outflow 7364.66 701.31 613.08 681.16 735.34 786.71 825.37 859.03 888.24 913.97 937.07 555.04 393.17

Excess / shortfall 381.89 415.49 308.08 277.78 259.81 260.93 265.97 276.40 290.83 308.11 327.46 739.11 696.57Opening balance 0.00 381.89 797.38 1105.46 1383.25 1643.05 1903.98 2169.96 2446.36 2737.19 3045.30 3372.76 4111.87Closing balance 381.89 797.38 1105.46 1383.25 1643.05 1903.98 2169.96 2446.36 2737.19 3045.30 3372.76 4111.87 4808.44



14 15 16 17 18 19 20 21 22 23 24 25Year ending, March 31 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

Inflow

Equity 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Debt 19.94 20.85 21.80 22.82 23.86 24.95 26.12 27.32 28.59 29.90 31.30 32.76

Term loan 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WC debt 19.94 20.85 21.80 22.82 23.86 24.95 26.12 27.32 28.59 29.90 31.30 32.76

PBT 991.38 987.45 982.57 976.81 969.93 961.86 952.64 942.09 930.17 916.68 901.63 884.88Depreciation 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79Total cash inflow 1118.11 1115.09 1111.16 1106.41 1100.58 1093.60 1085.54 1076.20 1065.55 1053.37 1039.72 1024.42

Outflow

Project expenditure 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WC expenditure 18.24 19.05 19.90 20.82 21.74 22.71 23.75 24.82 25.94 27.10 28.34 29.63Tax 356.26 357.96 358.69 358.64 357.83 356.32 354.19 351.44 348.07 344.06 339.42 334.14Loan repayments 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Total cash outflow 374.51 377.01 378.60 379.45 379.57 379.03 377.94 376.25 374.01 371.16 367.76 363.77

Excess / shortfall 743.60 738.08 732.56 726.96 721.01 714.57 707.60 699.95 691.53 682.21 671.95 660.66Opening balance 4808.44 5552.05 6290.12 7022.68 7749.64 8470.65 9185.21 9892.81 10592.76 11284.29 11966.50 12638.46Closing balance 5552.05 6290.12 7022.68 7749.64 8470.65 9185.21 9892.81 10592.76 11284.29 11966.50 12638.46 13299.11



ANNEXURE VI (I): BALANCE SHEET

1 2 3 4 5 6 7 8 9 10 11 12 13Year ending; March 31, 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024LiabilitiesShareholders' equity 2147.66 2691.03 3267.93 3814.48 4342.99 4872.58 5407.14 5952.06 6511.35 7087.84 7683.60 8292.01 8880.19Equity capital 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96Reserves and surplus 374.70 918.07 1494.97 2041.51 2570.03 3099.61 3634.17 4179.09 4738.38 5314.87 5910.64 6519.05 7107.23Loan funds 5551.01 5393.94 4869.33 4345.07 3821.18 3300.29 2779.16 2258.69 1738.93 1219.88 701.60 583.03 571.56Term loan 5318.89 4919.98 4388.09 3856.20 3324.31 2792.42 2260.53 1728.64 1196.75 664.86 132.97 0.00 0.00WC loan 232.11 473.96 481.24 488.87 496.87 507.87 518.63 530.05 542.18 555.02 568.62 583.03 571.56Total liabilities 7698.67 8084.97 8137.26 8159.55 8164.18 8172.86 8186.30 8210.75 8250.28 8307.72 8385.20 8875.04 9451.76

AssetsProject assets 7091.86 6829.71 6567.56 6305.40 6043.25 5781.10 5518.95 5256.80 4994.64 4732.49 4470.34 4208.19 4101.40Depreciation 196.61 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 262.15 106.79Current assets 224.92 457.88 464.24 470.90 477.87 487.78 497.39 507.60 518.44 529.93 542.10 554.98 541.91Coal stock 47.24 98.45 102.60 106.92 111.43 116.13 121.03 126.14 131.46 137.02 142.81 148.85 155.14Secondary fuel 8.19 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38Maintenance spares 17.27 38.59 40.80 43.14 45.60 48.21 50.97 53.89 56.97 60.23 63.67 67.31 71.16Receivables from energy sale 152.23 304.46 304.46 304.46 304.46 307.06 309.01 311.20 313.63 316.30 319.23 322.44 299.22Cash 381.89 797.38 1105.46 1383.25 1643.05 1903.98 2169.96 2446.36 2737.19 3045.30 3372.76 4111.87 4808.44Total assets 7698.67 8084.97 8137.26 8159.55 8164.18 8172.86 8186.30 8210.75 8250.28 8307.72 8385.20 8875.04 9451.76

Difference 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00



14 15 16 17 18 19 20 21 22 23 24 25Year ending; March 31,

2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

LiabilitiesShareholders' equity

9515.32 10144.81 10768.69 11386.86 11998.96 12604.50 13202.95 13793.61 14375.71 14948.33 15510.54 16061.29

Equity capital 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96 1772.96Reserves and surplus

7742.35 8371.85 8995.73 9613.90 10226.00 10831.54 11429.99 12020.64 12602.74 13175.37 13737.58 14288.32

Loan funds 591.50 612.35 634.15 656.97 680.83 705.78 731.89 759.21 787.80 817.70 849.00 881.76Term loan 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WC loan 591.50 612.35 634.15 656.97 680.83 705.78 731.89 759.21 787.80 817.70 849.00 881.76Total liabilities 10106.82 10757.16 11402.84 12043.83 12679.79 13310.28 13934.84 14552.82 15163.51 15766.04 16359.55 16943.05

AssetsProject assets 3994.62 3887.83 3781.04 3674.26 3567.47 3460.69 3353.90 3247.12 3140.33 3033.54 2926.76 2819.97Depreciation 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79 106.79Current assets 560.15 579.21 599.11 619.93 641.67 664.38 688.13 712.94 738.89 765.99 794.33 823.96Coal stock 161.71 168.55 175.69 183.13 190.89 198.99 207.43 216.23 225.41 234.98 244.96 255.38Secondary fuel 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38 16.38Maintenance spares

75.23 79.54 84.09 88.90 93.98 99.36 105.04 111.05 117.40 124.12 131.21 138.72

Receivables from energy sale

306.83 314.74 322.95 331.52 340.41 349.66 359.28 369.29 379.70 390.51 401.77 413.48

Cash 5552.05 6290.12 7022.68 7749.64 8470.65 9185.21 9892.81 10592.76 11284.29 11966.50 12638.46 13299.11Total assets 10106.82 10757.16 11402.84 12043.83 12679.79 13310.28 13934.84 14552.82 15163.51 15766.04 16359.55 16943.05

Difference 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00



ANNEXURE VI (J): RATIOS

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Cash outflow -1276.81 -1299.40 -1581.12 -1767.66 0.00Cash inflow 544.78 1457.83 1418.23 1322.78 1239.65 1175.62 1115.50 1060.77 1010.05 962.17Cash to the project

-1276.81 -1299.40 -1581.12 -1222.88 1457.83 1418.23 1322.78 1239.65 1175.62 1115.50 1060.77 1010.05 962.17

Project IRR,life 16.30%NPV, life @ 12% 1319.80

Cash outflow -1276.81 -1299.40 -1581.12 -1767.66 0.00Cash inflow 374.70 918.07 1494.97 2041.51 2570.03 3099.61 3634.17 4179.09 4738.38 5314.87Cash to the equity holder

-1276.81 -1299.40 -1581.12 -1392.96 918.07 1494.97 2041.51 2570.03 3099.61 3634.17 4179.09 4738.38 5314.87

Equity IRR, life 20.33% MIRRNPV, life @ 12% 31677.952022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

916.36 876.16 696.57 743.60 738.08 732.56 726.96 721.01 714.57 707.60 699.95 691.53 682.21 671.95 660.66916.36 876.16 696.57 743.60 738.08 732.56 726.96 721.01 714.57 707.60 699.95 691.53 682.21 671.95 660.66

5910.64 6519.05 7107.23 7742.35 8371.85 8995.73 9613.90 10226.00 10831.54 11429.99 12020.64 12602.74 13175.37 13737.58 14288.325910.64 6519.05 7107.23 7742.35 8371.85 8995.73 9613.90 10226.00 10831.54 11429.99 12020.64 12602.74 13175.37 13737.58 14288.32



Annexure – VI (K): DSCR Calculation

1 2 3 4 5 6 7 8 9 10 11Year ending March 31 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Debt servicing sources 544.78 1146.21 1418.23 1322.78 1239.65 1175.62 1115.50 1060.77 1010.05 962.17 916.36Debt servicing requirements 162.89 1042.34 1110.15 1045.00 979.84 914.68 849.53 784.37 719.21 654.06 588.90DSCR 3.34 1.10 1.28 1.27 1.27 1.29 1.31 1.35 1.40 1.47 1.56Minimum DSCR 1.10Average DSCR 1.35Maximum DSCR 3.34


105 Project Appraisal & Integrated Project

REFERENCES

i. Chandra Prasanna, Project Management, 4th Edition, 2005.

ii. Financial Management: by I.M.Pandey

iii. A Report on Indian Energy Sector by SBICAP.

iv. PFC website: www.pfcindia.com

v. www.cerc.gov.in

vi. www.powermin.nic.in

vii. Operational policy statement of PFC

viii. Project Appraisal Manual

ix. Entity Appraisal Manual

x. Integrated Project Rating Model Manual

xi. Computerized model of PFC for Entity Appraisal

xii. Detailed Project Report of the Company

Documents

FINAL REPORT Power project financing