SUMMER INTERNSHIP REPORT - National Power Training Institute ...

SUMMER INTERNSHIP REPORT PROJECT APPRAISIAL AND FINANCIAL MODELLING OF A THERMAL POWER PLANT

UNDER THE GUIDANCE OF Mrs Indu Maheshwari, Dy Director, CAMPS, NPTI & Mrs. Priya Kumar, Senior Manager, Project Division, Power Finance Corporation Limited At Power Finance Corporation, New Delhi Submitted By Ankit Doveriyal Roll No. 15 MBA (POWER MANAGEMENT)

(Under ministry of Power, Govt. of India) Affiliated to

MAHARSHI DAYANAND UNIVERSITY, ROHTAK AUGUST 2013

DECLARATION

I, Ankit Doveriyal, Roll No 15, student of MBA-Power Management (2012-14) at National Power Training Institute, Faridabad hereby declare that the Summer Training Report entitled “PROJECT APPRAISIAL AND FINANCIAL MODELLING OF A THERMAL POWER PLANT” is an original work and the same has not been submitted to any other Institute for the award of any other degree.

A Seminar presentation of the Training Report was made on ________________________ and the suggestions as approved by the faculty were duly incorporated.

Presentation In-Charge (Faculty)

Signature of the Candidate

Countersigned Director/Principal of the Institute

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ACKNOWLEDGEMENT It is often said that life is a mixture of achievements, failures, experiences, exposures and efforts to make your dream come true. There are people around you who help you realize your dream. I acquire this opportunity with much pleasure to acknowledge the invaluable assistance of Power Finance Corporation and all the people who have helped me through the course of my journey in successful completion of this project. I wish to express my sincere gratitude to my Company Guide, Mrs. Priya Kumar (Senior Manager, Project Appraisal Division, PFC) for her guidance, help and motivation. Apart from the subject of my study, I learnt a lot from her, which I am sure, will be useful in different stages of my life. I would like to thank Mrs. Shweta Vithal (Dy Manager, Project Appraisal Division) for her help in understanding and formulating the model design and methodology as well as help me in acquitting to the Power Sector and clearing my concepts and Mr. Natesh Sarma (Officer, Project Appraisal Division) for his review and helpful comments. I would like to thank Mr. Rakesh Mohan, Senior Manager (HR) for providing me with this wonderful opportunity to work at Power Finance Corporation. I express my thanks to Mrs. Indu Maheshwari, Dy. Director, Faculty guide, NPTI for her kind cooperation during the period of my summer internship. I feel deep sense of gratitude towards Mr S.K.Chaudhary, Principal Director, CAMPS(NPTI), NPTI and Mrs. Manju Mam, Director, Mrs. Indu Maheshwari, Dy. Director, NPTI for arranging my internship at Power Finance Corporation and being a constant source of motivation and guidance throughout the course of my internship. I am grateful to my friends who gave me the moral support in my times of difficulties. Last but not the least I would like to express my special thanks to my family for their continuous motivation and support.

Regards, Ankit Doveriyal Class of 2012- 2014 (NPTI)

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EXECUTIVE SUMMARY

Rapid economic growth has increased the burden of India’s infrastructure, one of the country’s week spots. An infrastructure deficit is widely considered to be one of the factors that could severely affect the economic growth of the country. In the past few years, policy makers have recognized the importance of infrastructure in economic growth and have made concrete efforts to accelerate infrastructure development. Power Sector continues to lag behind despite the introduction of progressive measures. Power shortages, increased tariffs, shortage of coal and dependence on imported fuel are on rise, while the poor health of the distribution continues to inhibit the inflows of investments which have possessed growth risk for the Indian Electricity Sector. India's demand for electricity is likely to cross 300 GW, in few years earlier than most estimates. Meeting this demand will require a fivefold to tenfold increase in the pace of capacity addition. With the growing demand of power, there is huge potential of investment in power sector of India. The power sector which is in the concurrent list of the Indian Constitution is under the purview of both the central government and the state government. The power sector which was earlier dominated by public sector undertaking is now seeing effective participation of the private sector which is now accountable for 28% of power generation in the country. Power Finance Corporation Ltd. (PFC) a public financial institution established In 1986 by the Ministry Of Power as a Financial Institution (FI) to provide financing solution to large capital intensive power project across India including generation, transmission, distribution and RM&U projects. My Summer Internship Project is “Project & Entity Appraisal of Thermal Power Plant”. It resolves around the appraisal of the power project promoted by the company ABC Power Limited, which has come for financial assistance of its Capital Expenditure and Working Capital Requirements. The project is being appraised after evaluating it on the various parameters set by Central Electricity Regulatory Commission (CERC) and the set parameters at PFC. My work also include appraisal of Promoters of the project which is based on set parameters at PFC .The aim of the appraisal is to finally arrive at the decision: whether PFC should finance the project or not. As per the guidelines of PFC the project is evaluated into two parts: Project Appraisal and Entity Appraisal. The format of the project report will be in the form of Agenda Note as per PFC norms. “Project Appraisal” is carried out by “Project Appraisal Department” which evaluate the financial and technical viability of the project.

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“Entity Appraisal” is carried out by “Entity Appraisal Department” and involves evaluation of the promoter of the company on its financial flexibility and stability, the analysis of their business operations and the competence of the management. In the end the project involves the subjective analysis on both Project & Entity fronts and come up with the risk involved. The project reports ends with the Recommendations on whether to finance the project or not.

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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

IDC

Interest During Construction

Kcal

Kilo Calories

KV

Kilo Volts

KWh

Kilo Watt Hour

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

REC

Rural Electrification Corporation

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LIST OF FIGURES Figure 1: Power Sector Structure……………………………………………………...4 Figure 2: Energy Production in Billion kWh (2010)…………………………………..5 Figure 3: All India Generation capacity……………………………………………….7 Figure 4: Business Strategy of PFC………………………………………………….13 Figure 5: Project Finance Structure…………………………………………………..19 Figure 6: Actual power supply position in Tamil Nadu……………………………...40

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LIST OF TABLES Table 1: All India Region wise generation capacity…………………………………..6 Table 2: Different Rating by major rating agencies………………………………….11 Table 3: Sanctions & Disbursements for the respective financial years……………..14 Table 4: Major Projects Funded by PFC……………………………………………..14 Table 5: Financial Highlights for the year 2011-12………………………………….14 Table 6: Approvals and Agreement Status…………………………………………...22 Table 7: Preliminary appraisal…………………………………………………….…24 Table 8: Detailed Appraisal…………………………………………………………..26 Table 9: Approval and Agreement Status………………………………………........38 Table 10: Project Cost Details…………………………………………………….….39 Table 11: Power requirement and availability for Tamil Nadu………………………40 Table 12: Project details……………………………………………………..……….41 Table 13: Snapshot of project financial projections………………………………….45 Table 14: Sensitivity analysis sheet………………………………………………….46

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TABLE OF CONTENTS DECLARATION………………………………………………………………………i ACKNOWLEDGEMENT…………………………………………………………… ii EXECUTIVE SUMMARY…………………………………………………………. iii LIST OF ABBREVIATIONS………….…………………………………………….. v LIST OF FIGURES…….…………………………………………………………… vi LIST OF TABLES…………….……………………………………………………. vii

CHAPTER 1: INTRODUCTION…….……………………………………………..1 1.1 INDIAN POWER SECTOR………………………………..……………..1 1.2 POWER SECTOR REFORMS……………………………………………2 1.3 INTRODUCTION TO INDIAN POWER SECTOR……………………...5 1.4 POWER SECTOR: DEVELOPMENTS & CURRENT STATUS………..7 1.5 MAJOR ISSUES…………………………………………………………..8 1.6 INITIATIVES…………………………..…………………………………8 1.7 OPPORTUNITIES………………………………………………………...9

CHAPTER 2: COMPANY PROFILE………………………………………..…...10 2.1 BACKGROUND...………………...……………………………………..10 2.2 MISSION……….……………….………………………………………..10 2.3 CREDIT RATINGS………………………………...……………………10 2.4 OBJECTIVE OF PFC………………………………………..…………...11 2.5 CLIENTS OF PFC…………………………...…………………………..12 2.6 RANGE OF SERVICES…………………………………………………12 2.7 REFORMS……………………………………….………………………13 2.8 SWOT ANALYSIS………………………………………….…………...15

CHAPTER 3: OBJECTIVE AND SCOPE………………………………………..16 3.1 OBJECTIVE OF THE PROJECT………………………………………..16 3.2 SCOPE……………………………………………………........…………16

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CHAPTER 4: LITERATURE REVIEW AND RESEARCH METHODOLOGY………………………………………………...17 4.1 LITERATURE REVIEW…...……………………………………………17 4.2 PROJECT FINANCE…………………………………………………….18 4.3 PROJECT APPRAISAL…………………………………………………19 4.4 CALCULATION OF TARIFF…………………………………………...20 4.5 RESEARCH METHODOLOGY………………………………………...21

CHAPTER 5: PROJECT APPRAISAL & FINANCIAL MODELLING……....22 5.1 GUIDING PRINCIPAL FOR PROJECT APPRAISAL…………………22 5.2 PROJECT & ENTITY APPRAISAL…………………………………….23 5.3 FINANCIAL MODELLING……………………….…………………….28

CHAPTER 6: CASE STUDY………………………………………………………29 6.1 PROJECT PURPOSE & SCOPE………………………………………...29 6.2 PROJECT DETAILS………………….………………………………….29 6.3 PROJECT COST…………………………………………………...…….38

CHAPTER 7: RISK ANALYSIS & SWOT ANALYSIS………………………...47 7.1 RISK ANALYSIS………………………………………………………..47 7.2 SWOT ANALYSIS………………………………………………………49 7.3 LIMITATIONS…………………………………………………………..50 CHAPTER 8: CONCLUSION, RECOMMENDATION & LEARNING………52 8.1 CONCLUSION…………………………………………………………..52 8.2 RECOMMENDATIONS………………………………………………...53 8.3 LEARNING…………………………………….………………………...53

BIBILIOGRAPHY……………..…………………………………………………...54

ANNEXURE…………………………………………………………………...……55

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CHAPTER 1: INTRODUCTION 1.1.

INDIAN POWER SECTOR

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. At the time of independence in 1947, the country had a power generating capacity of 1,362 MW. Prior to independence the power sector was regulated by “The Indian Electricity Act, 1910” which was the first basic legal framework for the electricity sector in the country. “Supply of energy” was the main concept around which various provisions were woven. The act talked about the Licence for generating and supplying electricity, Competition in generation and supply areas, Framework of wires and works, Licensee and Consumer relationship, Safety Measures and Theft of electricity in the power sector. Post independence our priorities changed, the supply of electricity which was limited to cities and towns was to be spread across the country, especially in rural areas. This was seen as a social responsibility of the Government to provide electricity to all. Thus “The Electricity Supply Act, 1948” was passed in the Central legislature to facilitate the establishment of regional co-ordination in the development of electricity which envisaged formation of State Electricity Boards (SEB) as an arm of State Government to discharge their responsibility of providing electricity to all. The act mandated that every State shall constitute a SEB. SEB’s were entrusted with the task of developing power generation, transmission as well as distribution facilities. The Act also called for formation of Central Electricity Authority (CEA), which was envisaged as the main technical arm of the Central Government. It also had to perform the role of technical advisor to the State Government, SEB, Generation Company or any other agency and form regulations on certain aspects of which the most important was the technoeconomic clearance of generation projects. However, in 1970s SEBs started making losses largely on account of political interference, mismanagement and inefficiencies in operations. Flat rate tariff (near zero usage charge) were introduced for the agricultural connections and high tariff was imposed on industrial & commercial users, such cross-subsidy led to increase in theft and the losses increased. As the boards were not able to make money, they became increasingly dependent on the government for funding. Because of the shortage of funds, SEB’s were unable to increase generation capacity and were not maintaining their assets. Therefore, SEB’s went into a vicious cycle that led to further drop in the performance of their operations and subsequently increased their losses. In 1980s, the SEBs were able to show about 3% of statutory returns with the help of flawed accounting system but in practice the accruals were not sufficient for growth and the boards sought assistance from state governments. In this situation, the government decided to create central generating utilities i.e. National thermal power corporation (NTPC) & National Hydro Power Corporation (NHPC) to improve the condition of power sector. The government also tried to connect the generating entities scattered all over the country non-uniformly   Project Appraisal & Financial Modeling   

 

 

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by forming “The National Grid” and thus trying to overcome generation demand supply gap prevalent in different states. In response to the balance-of-payment crisis in 1991, the government of India decided to open up various sectors in the economy including power sector. The power generation sector was de-licensed and the private parties were allowed to setup generating facilities. The change in notification gave numerous incentives to private sector such as 16% return on equity for plants that operated at plant load factor (PLF) of 68.5%, five year tax holiday, two part tariff, equity requirements as low as 20% of project cost and selective guarantees from central government for payment default by SEBs. This liberal set of policies initially created excitement among the private investors to setup plants. However, the excitement soon subsided because of the large political risks and payment capacity of the already bleeding SEBs. The state board’s losses were increasing mainly due to theft and had to increasingly depend upon government subsidy. Less than 17,000 MW were added vis-à-vis a planned addition 40,000 MW in the period 1971-1992. Further, such generous incentives given by the government to the foreign investors wherein almost all the risks were borne by the state board drew lot of criticism. SEBs were earning 12.2% internal rate of return on their own plants and therefore paying 16% return to IPPs which did not make sense. Under the 1910 and 1948 Acts, powers of regulation including tariff regulations were vested on the Government. This concentration of power in the Government and Government organizations resulted in inefficiencies of various sorts, the most prominent manifestation was being lack of rational and professional approach to tariff fixation. As part of reforms strategy, it was, therefore, considered necessary to distance the sensitive aspect of tariff regulation from the political executives on the independent Regulatory Commissions. Thus, Government brought in “The Electricity Regulatory Commissions (ERC) act, 1998” which was the first step taken by the government to move itself away from the regulatory aspect of the power sector and fixation of tariff for the energy being used by the consumer. By this act the various losses occurring at the SEBs level and the bottleneck caused due to bureaucracy prevalent in the government organizations and political interference were tried to minimize by formation of Central Electricity Regulatory Commissions (CERC) at central level and State Electricity Regulatory Commissions (SERC) at every state. The CERC and SERC had main responsibility of tariff determination for Central Government and State Government owned generating stations respectively. Bullish economic growth story of any country depends on a robust power generation & delivery model.

1.2. POWER SECTOR REFORMS 1.2.1. THE ELECTRICITY ACT 2003: A REVOLUTION Competition with regulatory oversight is the framework around which the Electricity Act, 2003 is woven - competition to encourage efficiency in performance and regulatory oversight, to safeguard consumer’s interest and at the same time ensure recovery of costs for the investors. The journey of distancing of Government from regulations that started in 1998 has culminated in The Electricity Act of 2003. According to the new law The   Project Appraisal & Financial Modeling   

 

 

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Government is distanced from all forms of regulation, viz., licensing, control over generation, captive generation, tariff fixation etc. Now the Government remains there only as a facilitator. The Act talks about the need and ways of implementing Competition in the power sector while considering the concerns associated with it, about the electrification of rural areas and about liberalization of power sector. While Liberalization is the mantra, the Electricity Act does not encourage an unbridled growth for the sector. The regulatory Commission have been envisaged as the watchdogs which have a responsibility to put a check on the cost of generation through powers to regulate tariffs for supply of electricity from a generating company to the distribution licensees on long term power purchase agreements, as also with power to look into the costs of generation. The act also provides the bases for formation of National Electricity Policy (NEP), National Tariff Policy (NTP), Rural Electrification, Open access in transmission, phased open access in distribution, Mandatory SERCs, licence free generation and distribution, power trading, mandatory metering and stringent penalties for theft. SERCs provide Regulatory guidelines on quality of service standards that are to be achieved and maintained by the utility and ensure their compliance by providing for Complaint Redressal Mechanism & Appointment of Ombudsman. SERCs mentions about the consequences that are to be followed by the utility for non-compliance of the guidelines. 1.2.2. NATIONAL ELECTRICITY POLICY In pursuance of the provisions of the Electricity Act, 2003 the Central Government came out with National Electricity Policy on 6th February 2005. The policy prescribes the following objectives:  Providing universal access in next five years for which significant capacity addition and expansion would be required.  Meeting the demand fully by 2012 and to have spinning reserves after meeting peak requirements.  Bringing about improvements in quality of supply at reasonable rates.  Increasing per capita availability to over 1000 kWh per year by 2012.  Ensuring a minimum lifeline consumption of 365 kWh per year per household as a merit good by 2012.  Financial turnaround and attainment of commercial viability of all entities in the sector.  Protection of consumers’ interest. 1.2.3. NATIONAL TARIFF POLICY In pursuance with section 3 of the Electricity Act 2003, the Central Government notified the Tariff Policy on 6th January 2006. According to the Act, the CERC and SERCs are to be guided by the Tariff Policy in framing its regulations. It lays out the following objectives:  Ensuring availability of electricity to consumers at reasonable and competitive rates;   Project Appraisal & Financial Modeling   

 

 

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  

Ensuring financial f viaability of thee sector and d attracting investmentss; Promotingg transparen ncy, consisteency and predictability y in regulattory approaaches across jurisdictions an nd minimiziing perceptiion of regullatory risks;; Promotingg competitio on, efficienncy in operaations and improvemen i nt in qualitty of supply.

1.2.4. R RURAL EL LECTRIFIICATION P POLICY Electriicity has beeen recogniized as a bbasic human n need. It is the key to acceleraating econom mic growthh, generatio on of empployment, elimination n of povert rty and hu uman development espeecially in ru ural areas. T The Rural Electrificatiion Policy was notifieed in Augustt 2006, withh the objecttive of imprroving acceess and quallity of electtricity supplly in rural aareas so as to ensure rapid r econoomic develo opment by providing p eelectricity as a an input for producctive uses in i agricultuure, rural industries etc. For thhis the Cen ntral governnment has launched in April, 20005 an ambittious schem me ‘Rajiv G Gandhi Gram meen Vidhyuutikaran Yoojana (RGGVY) aimedd to establish h 1. Rural Electricity Disstribution B Backbone (REDB) with w at leasst a 33/11 KV substation; 2. Village Electrificatio E on Infrastruucture (VE EI) with at a least onne Distribu ution transformeer in a villag ge or hamleet; 3. Stand alonne grids with h generationn where grid d supply is not feasiblee. penditure too the tune of o 90% is channelized c d through REC, R Subsiddy towards capital exp which is a nodaal agency for f implem mentation off the schem me. Electriffication off unelectriffied Below Poverty Lin ne (BPL) hhouseholds is i financed with 100% capital sub bsidy @ 15000/- per connnection in all a rural habbitations. Th he Managem ment of Ruural Distribu ution is undeertaken throough franchisees. A thrree-tier quallity monitorring has beeen built into o the schemee. RGGVY Y has thuss resulted in huge investments i s in providding electrricity connecctions in rurral India. OWER SECTOR STR RUCTURE E 1.2.5. IINDIAN PO Figure 1: P Power Secto or Structure

Sourrce: powerm min.gov.in   al & Financiaal Modeling  Projject Appraisa  

 

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1.3 INTRODUCTION TO INDIAN POWER SECTOR 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 meagre 1,362 MW in 1947 to more than 225,113 MW by May 2013, a gain of almost 200 times in capacity addition. India's per capita energy consumption is 778kWh in 2011 -- a rise of almost 400 percent since 1980. 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. Over 65 per cent of India's electricity is produced in thermal facilities using coal or petroleum products. Almost 19 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 which constitutes about 12 percent of the total energy generation.

Figure 2: Energy Production in Billion kWh (2010) 5,000 4,500

4,326  4,207 

4,000 3,500 3,000 2,500 2,000 1,500

1,145  1,037 

1,000

922 

630 

621 

500

573 

497 

485 

381 

0

Source: wikipedia.org

India is one of the main manufacturers and users of energy. Globally, India is presently positioned as the fifth largest manufacturer of energy, representing roughly 2.4% of the overall energy output per annum. It is also the world’s fifth largest energy user, comprising about 3.3% of the overall global energy expenditure per year. In spite of its   Project Appraisal & Financial Modeling   

 

 

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extensive yearly energy output, Indian Power Sector is a regular importer of energy, because of the huge disparity between oil production and utilization. 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 above 778 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 couple 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 2,25,133 MW as on May 2013. Though, this is still not enough. All the Regions in the Country namely Northern, Western, Southern, Eastern and NorthEastern 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 19.1% in the Southern Region to 1.2% in the Western Region. As per CEA’s forecast for 2013-2014 among the regions, only the Eastern region would have a surplus of 10.2%. Region-wise picture in regard to actual power supply position in the country during the year 2013 -14 is given below: Table 1: All India Region wise generation capacity Sl No. 1 2 3 4 5

Region

Coal

Gas

DSL

Northern 33073.50 5031.26 12.99 49584.51 8988.31 17.48 Western Southern 25182.50 4962.78 939.32 23727.88 190.00 17.20 Eastern 60.00 1187.50 142.74 N. Eastern 0.00 0.00 70.02 6 Islands 7 All India 131628.39 20359.85 1199.75 Source: Power ministry as on 31-5-2013

Total

Nuclear

Hydro

R.E.S

Total

38117.75 58590.30 31084.60 23935.08 1390.24

1620.00 1840.00 1320.00 0.00 0.00

15467.75 7447.50 11353.03 4113.12 1242.00

5589.25 8986.93 12251.85 454.91 252.68

60794.75 76864.73 56009.48 28503.11 2884.92

70.02 153187.99

0.00 4780.00

0.00 39623.40

6.10 27541.71

76.12 225133.10

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. 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. As per CEA’s forecast for 2013-14 18,432 MW of capacity is expected to be added, comprising 15,234 MW of thermal power, 1,198 MW of hydropower and 2000 MW of nuclear power. Capacity addition during 2012-13 stood at 20,502 MW.

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1.4 POWER SECTOR: KEY DEVELOPMENTS AND CURRENT STATUS Indian government forecasted the economic growth to be 6.1% - 6.7% for the year 20132014 and to sustain this growth it is imperative for the power sector to grow with the same pace. Therefore, it becomes essential to assess the power sector by analysing its current status, the key challenges faced by it, and its future growth drivers. Power is considered to be a core industry as it facilitates development across various sectors of the Indian economy, such as manufacturing, agriculture, commercial enterprises and railways. Though India currently has the fifth largest electricity generation capacity in the world pegged at 2,25,133 MW, the growth of the economy is expected to boost electricity demand in coming years. Figure 3: All India Generation Capacity 250000

225133.1 

200000 153188  150000

100000 39623 

50000

34444.12 

27542 

4780  0 Thermal

Nuclear

Hydro

RES

Total

Captive

Source: powermin.gov.in India saw a total capacity addition of approximately 54,000 MW during the 11th Five Year plan, of which approximately 47 per cent was contributed by the central government, 34 per cent from the state government, and a little over 19 per cent from the private sector. As per the Planning Commission report capacity addition of 88000MW is estimated in 12th five year plan. Some examples of top public sector companies include National Thermal Power Corporation (NTPC), Damodar Valley Corporation (DVC) and National Hydroelectric Power Corporation (NHPC). Some key companies in the private sector include Tata Power and Reliance Energy Limited. In India, power is primarily generated from thermal and nuclear fuels, hydro energy and renewable sources. India’s power generation capacity has significantly increased since 2008, and is also expected to show a strong growth in the future. However, India faced a power deficit of approximately 8.5 per cent and a peak demand deficit of over 10 per cent in FY11 primarily due to fuel shortage. This shortage can be attributed to aggregate technical and commercial (AT&C) losses, which is about 30 per cent with a high variance across various utilities. Therefore, it is essential for the government to work proactively to increase the sector’s generation capacity in a sustainable manner by addressing key   Project Appraisal & Financial Modeling   

 

 

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challenges, such as supply shortage and distribution losses without damaging the environment, to attain a high growth rate during the 12th Five Year Plan. To cope with the demand deficit, the Indian government has implemented various progressive measures to maximise the country’s power generation capacity and improve distribution. Some examples of such measures include rural electrification programmes and ultra mega power projects. In particular, the inflow of foreign direct investments is expected to step up capacity addition significantly. The government has allowed FDI of up to 100 per cent through the automatic route in all segments of the power sector except for nuclear energy. Consequently, the sector has drawn about US$ 4.6 billion investment over the past decade, of which US$ 1.6 billion came in FY12 alone. Hence, we can comfortably say that the Indian power sector has strong future growth prospects. Consequently, we need to assess the various policy initiatives that have had a positive impact on the sector, and capitalise upon them further to ensure a strong future growth.

1.5 MAJOR ISSUES The most important sector in infrastructure is the power sector. There is about 90 GW of capacity under various stages of construction and attending to the outstanding issues facing these projects must be given a high priority. However, given the time lag involved in implementing power projects, it is necessary to ensure that projects which will be commissioned only in the Thirteenth Plan can also move ahead satisfactorily. Almost half the capacity in the Twelfth Plan is projected to come from the private sector and the position is likely to be the same in the Thirteenth Plan. Private sector investors in power generation have faced many problems in recent times. They include (i) Inadequate supply of domestic coal and unanticipated increase in prices of imported coal. (ii) Difficulties with clearances for captive mines, as well as for generating stations. (iii) Land availability (iv) Poor financial health of some state electricity distribution companies which are the main customers and which suffer from insufficient tariff adjustment plus inefficiencies in collection. (v) Inadequate availability of domestic natural gas. (vi) Inadequate fuel supply agreements for coal. (vii) More recently, difficulties in obtaining finance from both external and domestic sources.

1.6 INITIATIVES PPP IN POWER To attract private sector participation, government has permitted the private sector to set up coal, gas or liquid-based thermal, hydel, wind or solar projects with foreign equity participation up to 100 per cent under the automatic route. The government has also launched Ultra Mega Power Projects (UMPPs) with an initial capacity of 4,000 MW to attract 160–200 billion of private investment. Out of the total nine UMPPs, four UMPPs at Mundra (Gujarat), Sasan (Madhya Pradesh), Krishnapatnam (Andhra Pradesh) and Tilaiya Dam (Jharkhand) have already been awarded. The remaining five UMPPs,   Project Appraisal & Financial Modeling   

 

 

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namely in Sundergarh District (Orissa), Cheyyur (Tamil Nadu), Girye (Maharashtra), Tadri (Karnataka) and Akaltara (Chattisgarh) are yet to be awarded. To create Transmission Super Highways, the government has allowed private sector participation in the transmission sector. A PPP project at Jhajjar in Haryana for transmission of electricity was awarded under the PPP mode. Further, to enable private participation in distribution of electricity, especially by way of PPP, a model framework is being developed by the Planning Commission. ADVANCED TECHNOLOGIES It has already been announced that 50 per cent of the Twelfth Plan target and the coalbased capacity addition in the Thirteenth Plan would be through super-critical units, which reduce the use of coal per unit of electricity produced. Supercritical (SC) power plants, which operate at steam conditions 560oC/250 bars, can achieve a heat rate of 2,235 kCal/kWh as against a heat rate of 2,450 kCal/kWh for sub-critical power plants. The specific CO2 emission for super-critical plants is 0.83 kg/ kWh as against 0.93 kg/kWh for sub-critical plants. Super-critical technology is now mature and is only marginally more expensive than sub-critical power plants. Determined efforts are needed to achieve these results, and prioritisation of coal linkages will be necessary to incentivise adoption of super-critical technology. ULTRA SUPER CRITICAL An Ultra Super Critical (USC) coal-based power plant has an efficiency of 46 per cent compared with 34 per cent for a sub critical plant and 40 per cent for a Super Critical (SC) plant. Thus, with an USC or SC plant, the savings in coal consumption and reduction in CO2 emission can be substantial. A 10,000 MW power plant will generate 60 billion units of electricity per year at around 70 per cent load factor. It has a specific heat of 1,870 kcal/kwh compared to 2,530 kcal/kwh for a sub-critical plant. Thus, every unit generated with USC will save 0.165 kg [(2,530-1,870)/4,000] coal of 4,000 kcal/kg; and 60 billion units will save 9.9 million tonnes of coal per year.

1.7 OPPORTUNITIES 1. Long-term health of power sector seriously undermined (losses Rs 70,000 crore per year). However, aggregate technical and commercial (AT&C) losses are slowly coming down. State Governments must push distribution reform. 2. Hydropower development seriously hindered by forest and environment clearance procedures. Need to look at special dispensation for these States, especially Arunachal Pradesh. 3. A time-bound plan to operationalize development and evacuation of hydropower from NER required. Road connectivity is an issue for expeditious project completion. 4. Given limited connectivity of NER with other parts of the country (through Siliguri corridor), access through Bangladesh needs to be explored. 5. Electricity tariffs not being revised to reflect rising costs. Regulators are being held back from allowing justified tariff increases.

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CHAPTER 2: COMPANY PROFILE 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 channelling the resources and providing financial, technological and managerial services for ensuring the development of economic, reliable and efficient systems and institutions. * 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.

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.

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Table 2: Different D Raating by majjor rating agencies a DOM MESTIC RA ATING AG GENCY

CRISIL L ICRA Internaational Ratinng Agency Moodyy’s Finch Standaard & Poor’ss Sourcee: PFC webssite

RUPEE BO ORROWING G

Long g Term AAA A LA AAA

Shoort Term P1+ A1+

Baa3 BB BBBB BB-

At ppar with “sovereeign” Rating g

2.4 OBJECTIV VE OF PF FC PFC inn its presentt role has thee followingg main objecctives: 

To rise thee resources from internnational and d domestic sources at tthe compettitive rates and terms t and co onditions annd on-ward lend these funds on opptimum bassis to the power projects in India.



To act as catalyst to o bring insttitutional, managerial, m operationaal and finan ncial improvement in the fu unctioning oof the state power utilitties



To assist state s power sector in caarrying out reforms r and d to support the state po ower sector duriing transitio onal period oof reforms  

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2.5 CL LIENTS OF PFC 

State Electtricity Boards



State Poweer Utilities



State Electtricity/Poweer Departmeents



Other Staate Departm ments (likee irrigation n Departmennt) engaged d in the deveelopment of the power project



Central Poower Utilitiees



Joint Secctor Powerr Utilities and Cooperative Societies S



Municipal Bodies



Private Secctor Power Utilities

2.6 RA ANGE OF SERVIICES Fund Based 

Rupee Terrm Loan



Foreign Cuurrency Terrm Loan



Buyer’s Liine of Crediit



Working Capital C Loan n



Loan to Eqquipment manufacturer m rs



Debt Restrructuring/ Refinancing R



Take out Financing F



Bridge Loan



Lease Finaancing



Bill Discouunting

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Noon-Fund Baased 

Guarantees



Exchange Risk Manag gement

2.7 RE EFORMS S & REST TRUCTU URING IN NITIATIV VES PFC haas been actiively persuaading State Govt. to iniitiate reform m and restruucturing of their t power sector in order to make m them commerciaally viable. In this reegard follow wing initiativves have beeen taken:

PFC is prroviding fin nancial assiistance to reform-min nded Statess under relaaxed lending criiteria/expossure limit noorms.



PFC has decided d to provide techhnical/financcial assistan nce to State Govts. / Po ower Utilities foor structurall reforms off the State Power P Secto or.



Reform Group G constiituted in PF FC to advicce and assissts the State te Govt. /Po ower Utilities too formulate suitable resstructuring programmes p s. Figure F 4: Buusiness Stra ategy of PFC

Sourcce: PFC Website We

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Table 3: Sanctions & Disbursements for the respective financial years Particulars

Financial Year 2007-08

2008-09

2009-10

2010-11

2011-12

Sanctions

69498

57030

65466

75197

69024

Disbursement

16211

21054

25808

34121

41418

Source: PFC website Table 4: Major Projects Funded by PFC Name of the Project

Capacity (MW)

Cost (Crs)

Amount funded

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

2800

1456

Sagardighi TPS PH1

2x300

2754

1925

Chandrapura Extn. Unit 7&8

2x250

2053

1435

Panipat TPS Stage V

2x250

1785

1428

Source: PFC website Table 5: Financial Highlights for the year 2011-12 Profit after Tax

Rs 3032 Crore

Loans and Grants Sanctioned

Rs 69024 Crore

Loans and Grants Disbursed

Rs 41418 Crore

Net Worth

Rs 19493 Crore

Reserves and Surplus

Rs 19388 Crore

No. of Employees

379

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2.8 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 repayment capabilities 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 an dare defaulting to most of their creditors. Delinquencies by these entities to PFC could impair the currently sound Balance Sheet of PFC.



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

 

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CHAPTER 3: OBJECTIVE AND SCOPE 3.1 OBJECTIVE OF THE PROJECT The objective of the Project Report is: 1. Finding out the factors affecting a project’s capital and operational expenditure which in turn have an impact on the cash outlay and revenue flow of the project and their study. Thus, performing Project Appraisal of a 660 MW Coal Based Supercritical Thermal Power Project. 2. A financial model of a 660 MW Coal Based Super-critical Thermal Power Project so as to study the effect of above factors on tariff and revenue flows. 3. To find out probable values of IRR, DSCR among other ratios using the financial model to study the feasibility and attractiveness of a 660 MW Coal Based Supercritical Thermal Project.

3.2 SCOPE Scope of project covers installation, commissioning, operation and maintenance of 660 MW coal fired Thermal Power Plant and associated systems. Indian power sector wants to ramp up the installed capacity to meet the growing demand. Large Power Projects enjoy economics of scale and help in lowering the tariff of supply. This project helps to find out the factors that will affect the project cost and thus have an impact on total investment and operational expenses of the project. The assessment and analysis of these factors will help in determining the project cost, the associated risks and ultimately the tariff for supply from the project and thus the revenue and cash flows. Such information is vital in making financial decisions and project appraisal. The study may also help in understanding of ways to mitigate the risks.

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CHAPTER 4: LITERATURE REVIEW AND RESEARCH METHODOLOGY 4.1. LITERATURE REVIEW The literature survey was carried out by reviewing various journals on project appraisal and financial model of a power plant. Few journals reviewed are: P.L.Kingston [1973] in IBM System Journals suggested, The use of computers in financial planning has become an area of increasing interest to financial management and data processing users. Computing systems facilitate the use of financial models in that they allow for the storage and retrieval of a representation of a financial plan and also for the evaluation of the consequences of “what if” conditions. Thus a financial model is a tool that can assist in the entire business planning process whether it be forecasting, cash management, or projection of profits. This paper presents introductory concepts that provide a basis for systems design and implementation of financial models. Described are the terminology, the basic components of financial models, and two general approaches to the construction of these models. W Wetekamp [2011] suggests how Net Present Value (NPV) can be used as a proper tool to ensure effective project management. The author proves that investment project's appraisal methods, such as e.g. NPV, can and should be used as an ongoing monitor of project health. What is more, even in case of project turbulences Net Present Value can be used as a key instrument for finding the most appropriate solutions. Robert Lundmark et al [2012] analyzed how market and policy uncertainties affect the general profitability of new investments in the power sector, and investigate the associated investment timing and technology choices. They developed an economic model for new investments in three competing energy technologies in the Swedish electric power sector. The model takes into account the policy impacts of the EU ETS and the Swedish green certificate scheme. By simulating and modeling policy effects through stochastic prices the results suggest that bio-fuelled power is the most profitable technology choice in the presence of existing policy instruments and under our assumptions. The likelihood of choosing gas power increases over time at the expense of wind power due to the relative capital requirement per unit of output for these technologies. Overall the results indicate that the economic incentives to postpone investments into the future are significant. Reports of similar projects for thermal power plants were also reviewed. The reports of previous batches on similar topic and the referenced data were helpful in determining data for this project. The literature available within the company helped a lot in understanding Project Finance and factors of project cost which are summarized as:

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4.2 PROJECT FINANCE 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 scale natural resource projects, from pipelines and refineries to electric-generating facilities and hydroelectric projects. Increasingly, project financing is emerging as the preferred alternative to conventional methods of financing infrastructure and other large-scale projects worldwide. 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 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 loan transaction rather the identification, analysis, allocation and management of every risk associated with the project is given more importance. 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 operations. 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.

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Figure 5: Project Finance Structure Debt

Equity 

Sponser(s) 

Lenders 

Dividend

Debt Service

O&M  Support 

Electricity Payments

Project Company 

Equipment Provider  Connections 

Construction  Contracts  Licenses  Certification

Civil Works  Zoning Local  Permits 

Electricity  Deliveries 

Regulatory Authorities 

Power Purchaser  Obligation to  buy electricity Tariff for such  electricity 

Source: PFC Library 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.

4.3 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 connected with 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. 

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.

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

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.



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, preoperative 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 ratio and current ratio.



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.



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.



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

4.4 CALCULATION OF TARIFF BASED ON CERC REGULATIONS 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). 

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.

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 



   



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. Operation and maintenance expenses for one month. Maintenance spares @ 20% of operation and maintenance expenses. Receivables equivalent to two months of capacity charges and energy charges for sale of electricity.

Energy Cost: It is also calculated on norms of CERC, the yearly consumption of primary fuel and secondary fuel is taken for the calculation. DPR (Detailed Project Report) of various projects of similar kinds helped in understanding the project technically. Reports and notifications available on various websites listed in bibliography also helped in adding value to the project. The data mainly obtained by interviews with experts and experience of plant operations and form the basis of assumptions taken for modelling. The data thus analysed was processed in model for finding out the required ratios and check the project feasibility.

4.5 RESEARCH METHODOLOGY Methodology used for the project: 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.



Calculating the cost of generation and relevance



Calculation of DSCR, IRR and sensitivity analysis.

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

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CHAPTER 5: OVERVIEW OF PROJECT APPRAISAL & FINANCIAL MODELLING 5.1. GUIDING PRINCIPAL FOR PROJECT APPRAISAL AT PFC “Offering credit is an operation fraught with risk. Before offering credit to an organization, its financial health must be analysed. Credit should be disbursed only after ascertaining satisfactory financial performance. Based on the financial health of an organization, PFC assigns integrated ratings. These credit ratings are used to fix the interest rate, exposure limit and security criteria.” 5.1.1. 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. 5.1.2. 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 Acquisition 2. Water Availability 3. Stack Height: Airport Authority of India 4. Forest Clearance: Such that no sanctuary, reserve, national park within the project 5. No defence establishment 6. Ministry of environment and Forest 7. Fuel Supply Arrangement/Agreement through various coal linkages 8. Fuel Transportation Arrangement 9. PPA for selling Electricity 10. Transmission agreement with Transmission agency 11. Pollution Control Board Table 6: Approvals and Agreement Status Major Clearances/ Agreements S No

Requirement

Agency

Status

1

Consent to establish / NoC

Tuticorin Airport

Certified

2

Environment Clearance

MoEF

3

Forest clearance

MoEF

4

Water Drawl

SG

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The Company has applied for the clearance. The Company has applied for the clearance Agreement made  

 

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Airport Authority of India (AAI) Tamil Nadu Pollution control board (TNPCB)

5

Stack height Clearance

6

Pollution control board NOC for power plant

7

Land Availability

State Government

8

Primary Fuel

Coal India Limited

9

Transportation of Fuel

Aspinwall Co Ltd

10

Transmission Line

PGCIL

EPC / package contract

Consolidated Construction Consortium Ltd.

11

Approved All the required standards of Pollution control board are met 600 acres has been acquired Long term agreement made on 15 April 2010 Fuel Transport Agreement made Open Access and Transmission Agreement made Agreement made on 18 June 2010

5.1.3. 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 and the price contingencies 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. 5.1.4. PROJECT COST-BENEFIT ANALYSIS: Calculate Financial Internal rate of return (FIRR). Techno-economically sound with Financial IRR not less than the minimum required rate. Sensitivity analysis is also done. 5.1.5. PROJECT ANALYSIS: The project is evaluated on various parameters and then ranked according to the PFC guidelines. The method is explained later on.

5.2. PROJECT & ENTITY APPRAISAL The Project Analysis is intended for arriving at a relative measure of merit for the project. This model involves: 1. Entity rating 2. Project rating 5.2.1. ENTITY 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 set of measures.   Project Appraisal & Financial Modeling   

 

 

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It 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 In this, the scrutiny is based on the analysis of quantitative parameters, so as to access the financial strength of the promoters, track record of the project implementation and the credit worthiness. 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 two categories for Preliminary Evaluation:  Business analysis  Financial flexibility

I. 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: a) Market Position 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. b) Financial Risk 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: Table 7: Preliminary appraisal Ratios Meaning of Scoring Attribute Return on Capital Employed Quantitative Return on Investment (ROCE) Operating Margin Quantitative Profitability of the Business Debt Service Coverage Ratio Quantitative Coverage Ratio (DSCR) Total Debt to Net Worth Quantitative Gearing Cash Flow From Operation Quantitative Cash Flow to Total Debt Source: PFC Library 

Return on Capital Employed (ROCE) ROCE = PBIT/ Opening capital employed

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Here, Capital Employed = (Capital + Reserves + Short term debt + Long term debt evaluation 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)

II. 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 Ratios Equity Funding Potential Bridge Finance Ability Track Record of Fund raised Aggregate Project cost Handled

Meaning Quantitative Quantitative

Attribute being Evaluated Equity Raising Potential Quarterly cash surplus from operations Funds raised in last 10 years Projects established in last 10 years

Quantitative Quantitative

Source: PFC Library 

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.



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.

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

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.

DETAILED APPRAISAL It involves Qualitative Analysis of Promoter Company. The scoring of all the factors is on a four-point scale. The factors are judgmental and the model provides broad guidelines for the evaluation for the same. It involves analysis under two categories parameters for Detailed Evaluation:  Management risk  Management past experience

I. MANAGEMENT RISK It evaluates two factors: Table 8: Detailed Appraisal Ratios Managerial Competency Business and Financial Policy Source: PFC Library

Meaning

Attribute being Evaluated

Quantitative

Competency in running the business Risk Propensity

Quantitative

II. MANAGEMENT EXPERIENCE Ratios

Meaning

Experience in Power Sector

Quantitative

Experience in Setting the Project Size

Quantitative

Experience in India

Quantitative

Experience in dealing with Developed Economies

Quantitative

Preparedness of the group to Execute the Project

Project Preparedness

Attribute being Evaluated Power Sector Experience Project Management Capability

Source: PFC Library   Project Appraisal & Financial Modeling   

 

 

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5.2.2. 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.



Levellised tariff/ cost of generation with RoE and tax



Average DSCR

Qualitative Parameters 

Power off take



Fuel supply o Long term agreement o Short term agreement o Captive Coal mine o Transportation facility



Construction Contract o Warranty o Market standard o Performance



Type of contract and bidding



Experience of the EPC contractor



Commercial terms of Contract



O&M o Past Experience o Management Team and efforts

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.

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5.3. FINANCIAL MODELING: 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.

5.3.1. 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.

5.3.2. 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.  An indication of tariff levels required for achieving appropriate returns.  Preparation of sensitivity analysis.

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CHAPTER 6: CASE STUDY 6.1 PROJECT PURPOSE AND SCOPE PURPOSE To bridge the nation’s energy deficit, both average and peak load, by capacity addition of 660 MW by setting-up Coal fired Thermal Power Project based on super critical technology at Tamil Nadu, India. SCOPE Scope of this project covers installation, commissioning, operation and maintenance of 660 MW with Super critical & Pulverised Coal fired boiler and associated systems. The Scope shall broadly cover: ‐ 660 MW power plant and associated systems. ‐ Construction and commissioning of the Balance of Plants (BoP) required for efficient reliable and safe operation of the plant. ‐ Installation of BTG, their auxiliaries and commissioning. ‐ Construction of water intake system for the project site. ‐ Transportation Arrangement for Coal to the Project site. ‐ Power evacuation system including transmission lines. ‐ Construction of facilitation infrastructure such as administration building.

6.2 PROJECT DETAILS 6.2.1 LOCATION The location of the proposed plant is in Tamil Nadu. The project site is located at a distance of about 14 kms from the National High way and 15 kms from Trichendur town. The site elevation is +12 m above mean sea level. The site terrain is generally plain requiring minimum efforts to grade them suitable for construction of the project. The site was selected considering the followings:

SNo

Geographic Items

1

Location

Tamil Nadu State

2

Nearest Railway Station

Thoothukkudi

3

Road Approach

Madurai –Tiruchendur- Manapad

4

Altitude

+12 m above MSL

5

Nearest Airport

Thoothukkudi

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Details

 

 

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6

Nearest Port

Thoothukkudi

7

Rainfall (Annual)

600 mm

8

Climatic Conditions

Tropical Climate

9

Latitude / Longitude

8o48’N / 78o10’E

10

Soil bearing capacity

25 T/M²

There is no cultivation in the project site and rehabilitation of resident population from the project site does not arise. Around the project site there is no reserve forest within 15 Km radius. 6.2.2 LAND The project is being implemented in Tamil Nadu. The company has already acquired 600 acres of land and site development works will commence shortly. The land is currently not in use and there are no inhabitants requiring rehabilitation or resettlement. Specifications

Land area(Acres)

Plant area

260

Ash disposal

130

Colony

10

Green belt others

100

Others

100 Total

600

The site identified for the Project is generally plain requiring minimum efforts to grade them suitable for construction of the project. . Around the project site there is no reserve forest within 15 Km radius. The Company has paid Rs. 50 Crore towards allotment of land and development works. The Company proposes to use the allotted land for setting up Main Power Plant, colony and Ash Dyke requiring about 400 acres. The remaining allotted land, about 100 acres, would be used for Green Belt development. The balance land of about 100 acres would be acquired by the Company in due course. 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. 20 Crore. 6.2.3 WATER The requirement of water for the plant will be for meeting the requirement of make up for the water system, dust suppression system in coal handling plants, ash disposal   Project Appraisal & Financial Modeling   

 

 

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system and the D.M. water plant which will be supplying the power cycle make up requirements. In addition the water requirements will be for drinking and service purposes. The total requirement of water for the plant will be around 150 m³/hr for the project. Water requirement for the plant Sl No.

Item

Quantity (m³/hr)

1

ACW System make up

80

2

Power Cycle make up

45

3

Service Water Requirement

15

4

Portable Water Requirement

10

Total

150

ABC Ltd. has made an agreement of minimum SG portable water supply of 4000m3/day of SG portable water by SG. A raw water reservoir of 25200m3 capacity to hold 7 days requirement for plant requirement of water will be constructed at the plant site. Air cooled condenser for turbine is proposed. Water drawl approval has been obtained by the company. The basic features of the sweet water system and auxiliary cooling water for the proposed station will be proposed to buy from prospective water suppliers. Air cooled condenser is proposed for condensing steam. At the Plant, a water reservoir will be installed to meet 7 days requirement of the plant. The overall cost of water arrangement as estimated by the Company is about Rs. 90 Crore and has been considered in the Project cost. 6.2.4 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 subcritical technology based plant, due to fewer thick section components allowing increased load change rates. Typical average availability of super   Project Appraisal & Financial Modeling   

 

 

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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.

6.2.5 TECHNOLOGY Thermodynamic cycle Thermodynamic reheat cycle. The thermodynamic reheat cycle consists of steam generator, steam turbine generator with condenser, the Condensate extraction and boiler feed pumps along with H.P & L.P feed water heaters & deaerator. Technical and performance parameters This project is based on supercritical technology. The critical pressure point of water and steam is 22.1 MPa, below this pressure it is called sub-critical pressure and above this pressure it is called as supercritical pressure. In the supercritical region, co-existence of water and steam is not present, therefore in the absence of steam/water mixture, the recalculating boiler technology adopted for subcritical pressure could not be used. This was the key to the advancement of cycle efficiency through the adoption of economic and reliable once-through supercritical boilers. The drive for enhancing the efficiency of generating plants in and environmentally friendly manner has been realized mainly through advancing the steam conditions, i.e. increasing pressure and temperature. This led to the development of some new power generation technologies like integrated gasification combined cycle (IGCC) and pressurized fluidized bed boilers (PFB). Boiler Feed Pump Three nos., horizontal, multistage, centrifugal type boiler feed pumps will be provided. Two nos. pumps will be turbine driven with steam extracted from turbine & one no pump will be motor driven as standby. Each boiler feed pump will have one matching capacity single stage booster pump. The booster pump will take suction from feed water storage tank and discharge into the suction of corresponding main boiler feed pump   Project Appraisal & Financial Modeling   

 

 

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which in turn, will supply feed water to boiler through the high pressure heaters and feed control station. Condensate extraction pumps The condensate extraction pumps will be vertical, multi stage enclosed canister type with flanged connection driven by electric motor. Two nos. condensate extraction pumps are used in this system. Supercritical Boilers Different boiler technology is used which is the critical requirement in the adoption of supercritical pressure and temperature. With supercritical pressure boiler need to increase the wall thickness of the pressure components and also use advanced materials for its effective working. Super critical steam turbine Steam turbine is of 3000rpm and is designed for main steam parameters of 247kg/cm2 & 540°C before emergency stop. High pressure steam turbines must be designed to withstand the higher pressure and temperature. Typical feedwater temperatures are around 275°C to 290°C compared to around 235°C to 250°C for sub-critical plants. With supercritical pressures, because of the greater steam pressure range in the turbine from inlet through to the condenser, there is greater scope for including an extra stage or stages of feedwater heating. This will further increase the cycle efficiency. 6.2.6 PRIMARY FUEL The primary fuel for the Proposed Project would be domestic coal. The Company proposes to use coal available from CIL mines. Coal India Limited has made a LoA with the company for use of coal in the Proposed Project. The Company has approved the agreement. The average calorific value of the coal is expected to be about 3400 kcal/kg. Considering this Gross Calorific Value and PLF of 85% the coal requirement of the Project works out to be about 3771700 TPA. The Company has estimated the capital investment of Rs. 900 per tonne at an escalation of 5% p.a and the same has been incorporated in the overall Project Cost. 6.2.7 SECONDARY FUEL HFO, which is the secondary fuel for pulverized coal, will be used for flame stabilisation at low loads and for supporting purposes. Heavy fuel oil will be supplied from oil depot by means of truck. Two HFO storage tanks each of capacity 1000m³ with necessary heating arrangement within the tank will be provided. The estimated maximum annual requirement of HFO is 4914 KL. Capital investment of Rs 50 per kg at an escalation of 4% p.a has been estimated. LDO system will be designed for 7.5 % of BMCR, which will be considered sufficient to introduce heavier grade fuel. The light diesel oil will have provision for supply to the steam generator for startup purpose. The estimated maximum annual requirement of LDO is 1000 KL.   Project Appraisal & Financial Modeling   

 

 

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6.2.8 TRANSPORTATION Coal will be transported from the Indian Coal fields to the Paradeep Port by Rail and from the port to the Manappadu Port located near to the project site by ship. Coal unloaded from ship will be stored in a separate coal yard to be set up by prospective Coal sellers at Manappadu port and coal will be supplied at the plant boundary by conveyors. Calorific value of Indian F grade coal will be in the range of 3400 kcal/kg. Rail route already exists upto Tiruchendur. About 12 km of rail route from Tiruchendur to project site is under approval. For transportation of coal, the Company would enter into Coal Transportation Arrangement (CTA) with the Indian Railways. Due to the availability of port facilities for transportation of coal from the mines, it is convenient and economical to unload and transport the coal to the plant. Coal will be also be transported from the port to the Manappadu Port located near to the project site by ship. Alternatively trucks will also be used for coal transfer from port to plant. Company has made a logistic agreement with Aspinwall Co Ltd for transportation of coal from port and railway station to the plant. 6.2.9 EPC CONTRACT Under an EPC contract, the contractor designs the installation, procures the necessary materials and builds the project, either directly or by subcontracting part of the work. EPC contract for this project is been given to Consolidated Construction Consortium Ltd. It is proposed to entrust the entire work of project execution covering all civil works, electrical and mechanical systems to a single EPC (Engineering, Procurement and Construction) Contractor who will take overall responsibility for timely project execution and plant performance and provide guarantees for the same. SCOPE  



The EPC Contractor’s scope of work includes design, engineering, manufacture, supply, erection, testing and commissioning within the Power Plant site. The EPC Contractor would be responsible for all basic and conceptual engineering, detailed system engineering, design & drawings for all mechanical and electrical systems, detailed designs and construction drawings for all civil works, manufacture of equipment as applicable, procurement of sub-contracted equipment and materials, review of sub-contractor’s design and engineering, inspection and expediting of sub- contracted equipment, transport of equipment and materials to site, stores management at site, overall site management covering construction, erection and commissioning activities and performance testing for the complete Power Plant. The contractor agrees to provide all civil and structural works including supplies of cement, reinforcement steel and structural steel etc.

The lump sum amount of Rs 524 crore represents the lump sum fixed price towards the services to be provided by the contractor, pursuant to the scope of work under this Agreement. The contractor shall complete all the works as per project schedule approved by owner, pursuant to various conditions of this agreement, within 30 months from the start of project commencement date.   Project Appraisal & Financial Modeling   

 

 

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6.2.10 OPERATION AND MAINTENANCE In order to ensure a high level of performance of the power station, it is proposed to entrust the operation and maintenance of the power station to an experienced O&M Contractor. In order to ensure that the design and construction of the power station incorporates all necessary features required for easy and efficient operation and maintenance of the proposed power plant, the proposed O&M Contractor will also be consulted during the review of EPC contract documents, plant design features, operational and maintenance features of plant systems and equipment. O&M Contractor’s general manager would have primary responsibility for the operation & maintenance of the power station. O&M Contractor’s site organisation is expected to comprise four broad functional areas viz. operations, maintenance, engineering and administration. Operation of Power Plant, coal and ash handling systems, water systems including water treatment system, switchyard and other auxiliary plant. Operations manager would be overall in charge of operations, all other operation personnel would work on three - shift basis. Shift personnel manpower planning for key areas has been generally done on (3+1) concept to take into account leave taken by shift personnel. Maintenance of all mechanical and electrical plant, control systems, buildings, roads, drainage and sewage systems, etc., operation of the plant workshop, planning for scheduled maintenance works and deciding requirement of spare parts. 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. 6.2.11 INFRASTRUCTURAL REQUIREMENTS Construction Power The company has received approval for drawl of construction power from nearby substation of Tamil Nadu Power Distribution Company Ltd. (TNPDCL). Construction Water The total water requirement for the project is 2000 m3/day. This water will be sourced from nearby desalination plant. The requirement of construction water for potable and service purposes will be met by the nearby desalination plant located within the allotted land for the Project. The Company has taken over the desalination plant along with the auxiliary and paid about Rs. 50 Crore for the same. 6.2.12 EVACUATION OF POWER The power generated from the plant will be evacuated at 400 KV through PGCIL / TNEB grid lines. Three / Four 400 KV transmission line circuits are proposed from   Project Appraisal & Financial Modeling   

 

 

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400KV switch yard to Udangudi STPP Substation for further connectivity to southern grid. Company’s generation project shall implement, maintain and operate dedicated transmission system for immediate evacuation of power from their generation projects. a)

Company’s Power generation switchyard-tuticorin pooling station 400kV D/c quad/high capacity line.

b)

Two nos of 400kV bays each at Company’s switchyard & Tuticorin Pooling POWERGRID station.

The cost of the transmission line is estimated by the Company is about Rs. 52 Crore. 6.2.13 ENVIRONMENTAL ASPECTS The project site is located at a distance of about 14 kms from the National High way and 15 kms from Trichendur town. There is no cultivation in the project site and rehabilitation of resident population from the project site does not arise. Around the project site there is no reserve forest within 15 Km radius. Since all necessary pollution control measures to maintain the emission levels of dust particles and sulphur dioxide within the permissible limits would be taken and necessary treatment of effluents would be carried out, there would be no adverse impact on either air or water quality in and around the power station site on account of installation of the proposed plant. Ash Handling System The fly ash generated in thermal power stations has commercial value because of its usage in cement and construction industries in various forms. Fly ash generated from the proposed power plant would be commercially utilized in one or more of the following industries, to the extent possible a. Manufacture of fly ash bricks b. Manufacture of aerated wall blocks and panels c. Fly ash Aggregate d. Land reclamation e. Ready Mixed Fly Ash Concrete f. Utilisation in Roads/Paving g. Use in cement manufacturing using fly ash in combination h. Manufacture of fly ash bricks i. Export of Fly ash to countries like Bangladesh and Middle East.

Water Handling System Hydrochloric acid and caustic soda would be used as reagents in the proposed water treatment plant. The acid and alkali effluents generated during the regeneration process of the ion exchangers would be drained into an underground neutralising pit. The effluent would be neutralised by the addition of either acid or alkali to achieve the required pH.

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Waste water from the Coal yard suppression system and leaching water is collected in the settling tank. The clear water will be disposed to the nallah through CEMS. The Sludge will be dried in a Drying Pond and then Reused. Sewage water from power plant and canteen will be collected in the Anaerobic treatment pond and from there it will be sent to the clarifier. The treated water will be used for horticulture purpose. The oily waste water will be treated in an Oily Water Separator. The clear water is disposed through CEMS and the Oily Sludge is disposed offsite. Air Handling System The height of the stack which disperses the pollutants have been fixed based on the above guidelines of the Indian Emission Regulations. The electrostatic precipitators which remove most of the fly ash from the flue gas, thereby limiting the quantity of fly ash emitted to atmosphere. By selecting a suitable furnace and burner for the steam Generator, NOx formation has been avoided and no additional equipment for NOx control is required. Although there is no statutory stipulation for regulation of NOx emission, the boiler will be designed for maximum of 750 mg/Nm3 with provision of low NO burners. Dust nuisance due to Coal handling would be minimised by providing suitable dust suppression/extraction systems at crusher house, junction towers etc. For the coal stockyard, dust suppression system would be provided. Boiler bunkers would be provided with ventilation system with bag filters to trap the dust in the bunkers. Noise Handling System As per State Pollution Control Board, Ambient noise level for Industrial area will be Sl. No

Time

dB (A)

1. 2.

Day Time 6 AM to 9 PM Night Time 9 PM to 6 AM

75 70

The above noise level at plant boundary during normal operation is ensured by proper selection of the system. Controlled noise level from originating equipment and green belts around the plant area. Project clearances received from statutory authorities, Tamil Nadu State Pollution Control Board (TNPCB) and the concerned agencies of the Government of Tamil Nadu and India. 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 Acquisition 2. Water Availability 3. Stack Height: Airport Authority of India 4. Forest Clearance: Such that no sanctuary, reserve, national park within the project 5. No defense establishment   Project Appraisal & Financial Modeling   

 

 

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6. Ministry of environment and Forest 7. Fuel Supply Arrangement/Agreement through various coal linkages 8. Fuel Transportation Arrangement 9. PPA for selling Electricity 10. Transmission agreement with Transmission agency 11. Pollution Control Board Table 9: Approval and Agreement Status Major Clearances/ Agreements S No

Requirement

Agency

Status

1

Consent to establish / NoC

Tuticorin Airport

Certified

2

Environment Clearance

MoEF

3

Forest clearance

MoEF

4

Water Drawl

SG

5

Stack height Clearance

6

Pollution control board NOC for power plant

7

Land Availability

State Government

8

Primary Fuel

Coal India Limited

9

Transportation of Fuel

Aspinwall Co Ltd

10

Transmission Line

PGCIL

11

EPC / package contract

Consolidated Construction Consortium Ltd.

The Company has applied for the clearance. The Company has applied for the clearance Agreement made

Airport Authority of India (AAI) Tamil Nadu Pollution control board (TNPCB)

Approved All the required standards of Pollution control board are met 600 acres has been acquired Long term agreement made on 15 April 2010 Fuel Transport Agreement made Open Access and Transmission Agreement made Agreement made on 18 June 2010

6.3 PROJECT COST 6.3.1 COMPONENTS OF PROJECT COST The Project is estimated to be set up at an aggregate cost of Rs. 4251 Crore comprising of expenditure towards Land, EPC 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:

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Table 10: Project Cost Details Sl No.

Particulars

Total Cost

1

Land & Site Development

50

2

Total Plant & Equipment

2038.48

3

Civil Works

545

4

Electric Works

135

5

Miscellaneous

146.5

Total Hard Cost

2914.98

6

Overhead & Pre-Op. Expenses

114.59

7

Interest During Construction

656.20

8

Working Capital Margin

565.43

Total Soft Cost

1336.22

(in crore) Total Project Cost

4251

6.3.2 FINANCING PLAN The tentative financial plan for the proposed project is as follows: Particulars

Cost (Rs Crore)

Percentage

Debt Equity Ratio

3.00

Equity

25%

1062.80

Debt

75%

3188.40

Upfront Equity

51.5%

547.342

Total

100%

4251

6.3.3 DEMAND AND SUPPLY Inspite of 18,382 MW of installed capacity the state of Tamil Nadu is struggling to fulfil its electricity demand. The electricity demand in the State had increased but the capacity of the generating facilities had dropped due to inefficiencies resulting in shortfall. Most of the districts in Tamil Nadu face power cuts lasting over six hours. Between April 2012 and February 2013, the energy and peak shortage of power in Tamil Nadu were 17.4 % and 12.3 % respectively of the demand.

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Electricity deficit in the state has increased from 1% in 2005-06 to 11% in 201112. Between 2005-06 and 2011-12, electricity requirement grew at CAGR of 9%, while availability only grew at around 7% leading to increasing electricity deficits. Figure 6: Actual power supply position in Tamil Nadu  Requirement

Availability

% deficit

90000

12% 11% 

80000

10% 70000 8%

8% 

20000

85685  76705 

69668  64208 

61499  60445 

47872  47570 

30000

54194  53853 

40000

76293  71568 

6% 

80314  75101 

7% 

50000 65780  63954 

MU 

60000

4%

3%  2%

2%  10000

1% 

6%

1%  0%

0 FY 2005

FY 2006

FY 2007

FY 2008

FY 2009

FY 2010

FY 2011

FY 2012

Source: CEA website

Table 11: Power requirement and availability for year 2012-2013 for Tamil Nadu Peak Peak Energy Energy Energy Peak Availabilit Deficit/Surp Requiremen Availabilit Deficit/S Period Demand y lus t y urplus (MW) (MW) (MW) (MU) (MU) (MW Apr 12

12499

9841

-2658

7583

5817

-1766

May 12

11967

10182

-1785

6796

5840

-956

June 12

12296

11053

-1243

7868

6834

-1034

July 12

12269

10877

-1392

8043

7333

-710

Aug 12

12004

10566

-1438

7840

6763

-1077

Sep 12

12606

10348

-2258

7990

6606

-1384

Oct 12

12538

10269

-2269

8233

6574

-1659

Nov 12

11755

8306

-3449

7110

5254

-1856

Dec 12

12323

9409

-2914

7450

5831

-1619

Jan 13

12038

9698

-2340

7859

6668

-1191

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Feb 13

11803

10021

-1782

7288

5998

-1290

Mar 13

12736

10556

-2180

8242

6643

-1599

76161

-16141

TOTAL 134565 121126 -13439 92302 Source: CEA, Load Generation Balance Report (2012-2013) 6.3.4 COST BENEFIT ANALYSIS Table 12: Project details sheet No. of units Capacity per unit Total project capacity

1 660 660

MW MW

Without IDC IDC With IDC

3595 656 4251

Rs Crore Rs Crore Rs Crore

1062.80 3188.40 547.34 13.25% 13.25% 13%

Rs Crore Rs Crore Rs Crore p.a. p.a. p.a.

12 6 01-Jul-14 01-Jan-26 01-Jan-14 01-Jan-26

Years Months Date Date Date Date

70% As per CERC based tariff 25

Rs/unit

30% 3.5 25 5%

Rs/unit years

Equity (25%) Debt (75%) Upfront Equity (51.5%) Interest Rate pre COD Interest rate post COD Working Capital Repayment Period Moratorium Period Principle Repayment Start Date Principle Repayment End Date Interest Repayment Start Date Interest Repayment End Date MOU with PTC (including all units) % of total capacity PPA Tariff No. of years Selling through Merchant Basis (including all units) % of total capacity PPA Tariff No. of years Escalation per year Corporate Tax MAT   Project Appraisal & Financial Modeling   

years

33.99% 20.96%  

 

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GSHR Auxiliary Consumption Plant Load Factor O&M Escalation O&M Expense

2392 7% 85% 5.72% 0.155

kCal/kwh % % % crore/MW

Fuel Price Price Escalation Gross Calorific Value

900 5% 3400

Rs/tonne p.a. kCal/kg

Secondary Fuel Price Gross Calorific Value Secondary Fuel Consumption Specific Gravity value of Secondary Fuel Price Escalation Transportation & Handling Charges Escalation

50 10280 1 0.95 4%

Rs/kg kCal/kg ml/kwh

2 2 1 1 2

Months Months Month Year Months

Coal Stock Secondary Fuel O&M Expenses Maintenance Spares (20% of O&M Expense) Receivables from Energy Sales Rate For Tariff Calculation Land Civil Works & Building Plant & Machinery Max Depreciable Value

5.28% 0% 3.34% 5.28% 90%

Machinery Building

15% 10%

Discount Rate Return on Equity Return on Equity pre tax (first 12 years) Return on Equity pre tax (last 13 years) Project Life Total units generated

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p.a.

13.10% 15.50% 19.38% 22.95% 25 4914.36

 

% % % % years MU

 

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6.3.5 FINANCIAL MODELLING AND PROJECTIONS After doing through study of the information Memorandum and all the contracts and the agreements signed by ABC Ltd. the Financial Analysis is performed. Various parameters that need to be calculated as a part of the financials of the project are: INTEREST DURING CONSTRUCTION In the Interest during construction phase is the period were the power plant is in the process of making and during this time it generates no revenues. The complete infusion of term loan and the equity by the financers and promoters respectively is done in this phase. This period starts from the date when the sub – debt and then the upfront equity starts flowing into the project (upto 51.5 % of the total equity) by the promoters, when the Upfront Equity part finishes Upfront Debt starts flowing till the time Debt Equity ratio becomes 75:25. Once, the ratio is achieved the Matching Debt and Matching Equity flows simultaneously in the ratio of 75:25. During the construction period the project has to pay the interest on the debt fused till that month. The interest rates depends on the Pre COD Rates and sub debt rates are specified by the leading Financial Institution (FI), which is also the syndicator of the project. (IDC Sheet Attached in Annexure III) DEBT PAYMENT When the project is commissioned then the borrower company has to pay the interest on the Term Loan. The interest rate used is the weighted average of Post COD Rates and sub debt rates are specified by the leading Financial Institution (FI), which is also the syndicator of the project. The First Six months after the project commissioning is the Moratorium Period that is during this period no principle repayment will be done but the interest will be charged according to the Post COD Rates. After the Moratorium period the project has to pay both the principle repayment and interest on the term loan. (Sheet is attached in the Annexure V) FUEL REQUIREMENT The main objective of this part is to calculate the requirement of fuel for the project and thus calculate overall cost of fuel required per annum for each of the next 25 years of operation of the plant from the date of start of operations, which is assumed as the life of the Thermal Power plant. Here we first calculate the primary fuel cost and secondary fuel cost on yearly basis for 25 years depending upon the energy exported and GCV of the fuel that will be charged to the project. While calculating the fuel cost we consider the Fuel Charges Escalation (as mentioned in Power Purchase Agreement).For this we calculate the amount of units that the project will be producing every year for 25 years. This is done on the basis of installed capacity (MW) from the point the very first unit becomes operational to the point 25 years ahead of the last commissioning of last unit. Plant Load factor (PLF) is also taken into consideration. This collectively gives the amount of fuel required to generate the stipulated amount of power. After knowing the amount of fuel required and the cost for 25 years we calculate the fuel cost on yearly basis. (Fuel requirement sheet is attached in Annexure VI)   Project Appraisal & Financial Modeling   

 

 

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TARIFF This is among the most important parameters of the project. In this the main objective is to calculate the Variable Cost and Fixed Cost of generation of one unit of electricity. This cost is the cost to the company. This cost is compared with the Quoted Tariff, as specified in the PPA so as to figure it that whether the company is selling the electricity on profit and loss. VARIABLE TARIFF: Variable tariff only takes into account the primary fuel cost. This is obtained by using formula: Variable Cost Electricity Units sold FIXED TARIFF: As per CERC norms, the fixed cost takes the following parameters into consideration:  Secondary Fuel Cost  Interest on Loan Capital  Return on Equity  Depreciation  O&M Expenses  Interest on Working Capital

Fixed tariff is calculated as:

Fixed Cost Electricity Units sold

The sum of variable cost and the fixed cost gives the total Tariff that should be charged to get the desire return on Equity. (Tariff sheets attached in Annexure VIII) DEPRECIATION Depreciation is calculated on the Machinery and Building strictly according to the CERC Guidelines. Depreciation shall be calculated on straight line method and at rates specified in the CERC guidelines for the assets of the generating station but the company files the tax according to IT ACT section 80. (Tariff sheets attached in Annexure IV) WORKING CAPITAL REQUIREMENT The working capital requirements as specified in the CERC guidelines are as follows: Working Capital Limits Primary Fuel Stock

2

Months

Secondary Fuel Stock

2

Months

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O&M Expense Maintenance Spares Receivables from energy sales

1

Month

20%

O&M

2

Months

(Detailed Working Capital requirement sheets is attached in Annexure VII) CASH FLOW The Objective of this part is to calculate the total cash flow Inflow and Outflows, and then to calculate the excess/shortfall. (Detailed Cash flow sheets is attached in Annexure X) PROFIT AND LOSS ACCOUNT The main aim of this part is to calculate the Profit & Loss of the project for the 25 years after the commissioning of first unit. In case of PTC (long term) the levelised cost of electricity is Rs 2.475/kWh and that for short term is Rs 3.5/kWh. The sale of electricity to PTC is done at the rate of Rs 2.475/kWh for aggregate cap of 70% and rest at variable cost of Rs 0.63/kWh. (Detailed P&L is attached in Annexure IX) BALANCE SHEET This part accounts for the assets and liabilities per year for the project for 25 years from COD. (Detailed Balance sheet is attached in Annexure XI) RATIOS This part is used to calculate the relevant ratios in order to determine the financial viability of the project. The Minimum, average and maximum Debt Service Coverage Ratio is calculated along with Internal Rate of Return and Net present Value are calculated. (Detailed Ratios sheet is attached in Annexure XII) 6.3.6 SNAPSHOT OF FINANCIAL PROJECTIONS The financial projections, based on the capital/project cost as specified by the borrower, would be as below:

Table 13: Snapshot of project financial projections Particular Value Value Parameters DSCR Minimum

1.403

Average

2.106

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Maximum

4.212

Project IRR, 25 years

18.54%

Equity IRR, 25 years

21.41%

Levelised cost of generation

2.475 Rs/kwh

6.3.7 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:

Scenario

Table 14: Sensitivity analysis sheet Project IRR Min DSCR Avg DSCR (%)

Equity IRR (%)

Base Case

1.403

2.106

18.54

21.41

Case 1: PLF at 65%

1.238

1.784

16.44

18.12

Case 2: Increase Fuel cost by 20%

1.371

2.043

18.20

20.81

Case 3: Increase project cost by 10%

1.332

1.974

17.70

20.35

Case 4: Decrease in calorific value of coal by 1000 kcal/kg

1.336

1.975

17.83

20.13

Case 5: Increase interest rate by 100 bps

1.373

2.068

18.73

21.25

It may be observed from above mentioned results that project financials are quite robust in various scenarios and the DSCR levels are above satisfactory.

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CHAPTER 7: RISK ANALYSIS AND SWOT ANALYSIS 7.1 RISK ANALYSIS i)

PRE CONSTRUCTION

Sno

1

2

3

ii)

Risk

Mitigation / Allocation

Grant of approvals / Clearances

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.

Finalization 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.

Procurement of land

Land has been already acquired which is sufficient for the main power block, Ash Dyke and Raw Water Reservoir.

CONSTRUCTION

Sno

Risk

Mitigation/Allocation

Cost estimate

Since the technology is based on super critical parameters, it is difficult to fairly compare costs and to estimate the cost precisely.

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.

1

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4

iii)

Equity infusion

The equity in company will be infused by promoter’s Group as also by raising funds from financial/strategic investors.

POST CONSTRUCTION

Sno 1

Risk Fuel supply risk

Mitigation/Allocation The Company has made a long term fuel agreement with CIL. Hence, fuel supply risk is perceived to be moderate. The fuel supply agreement is yet to be signed.

2

3

4

5

6

7

8

Fuel price risk

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.

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.

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.

Off take risk

The Company would sell 70% of net power to State Discom through a long term PPA at a levelized tariff and rest at Rs 3.5 per unit on merchant basis with escalation of 3% p.a.

Price risk

The cost of generation, is lower than the assumed average purchase price of power. The risk may be perceived to be low.

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.

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The fuel supply agreement shall be subject to review by Lenders / Lenders’ agencies.

 

 

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Also, LDs have been specified in the PPA for payment security. 9

Environmental Hazards

Obtained MOEF Clearance and Pollution Control Board NOC.

10

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.

7.2 SWOT ANALYSIS STRENGTH 

The Project has long term fuel supply agreement with Coal India Limited of Coal for use in the Project.



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 600 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.

WEAKNESS 

Company shall be selling 30% of power on Merchant Basis and may get lower return than the levelised cost of generation.



Environment and Forest Clearances still to be obtained.

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OPPORTUNITY 

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. 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 

A part of power generated will be sold on Merchant basis and may get lower return than the levelised cost of generation.



Fuel supply agreement with Coal India Limited may result in delay

7.3 LIMITATIONS This analysis is limited to an examination of annualized expenses and revenue and represents a prototypical year of operations. This analysis should examine alternative pay as- you-go and debt financed scenarios, be conducted in year-of-expenditure, 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: 

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.



Cash flows not really known until the project is in service – no history of cash flows.

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

Value of debt and equity driven by cash flow.



Measure the value of different securities supported by project cash flow.



Risk analysis depends on contracts used to allocate risk to different parties.

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CHAPTER 8: CONCLUSION, RECOMMENDATIONS AND LEARNING 8.1 CONCLUSION Company has proposed to set-up 660 MW 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 Competitive Bidding Process. The Project requires about 3771700 TPA coal based on average GCV of 3400 kcal/kg and PLF of 85%. The company made an FSA with CIL for the Proposed Project. Appropriate arrangements are proposed to be done. The Project will require about 150 cubic meter per hour make-up water during operation. A raw water reservoir of 25200m3 capacity to hold 7 days requirement for plant requirement of water will be constructed at the plant site. Of the total 462 MW of power is proposed to be sold as PPA as per CERC tariff. Balance 198 MW will be sold on Merchant basis at Rs 3.5 per unit with an escalation of 3% p.a. Considering the cost of generation of Rs. 2.475 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 scenario assumed. 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. Thus, loan amount should be granted by PFC equal to the request of the borrower.

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8.2 RECOMMENDATIONS 

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.



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.

8.3 LEARNING 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.



Learnt corporate culture.

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BIBILIOGRAPHY 1. Chandra Prasanna, Project Management, 4th Edition, 2005 2. I.M.Pandey, Financial Management, 9th Edition, 2010 3. PFC website: www.pfcindia.com 4. www.cerc.gov.in 5. www.powermin.nic.in 6. Operational policy statement of PFC 7. Project Appraisal Manual 8. Load Generation Balance Report for 2013-14, CEA 9. Integrated Project Rating Model Manual 10. Detailed Project Report of the Company 11. www.powergrid.com 12. Power Finance Corporation, “Project Term Loan and Short Term Loans”

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ANNEXURE

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ANNEXURE I: ASSUMPTION SHEET Project Capacity

No. of units Capacity per unit Total project capacity

1 660 660

MW MW

Project Cost

Without IDC IDC With IDC

3595 656 4251

Rs Crore Rs Crore Rs Crore

Financing Plan

Equity (25%) Debt (75%) Upfront Equity (51.5%) Interest Rate pre COD Interest rate post COD Working Capital

1062.80 3188.40 547.34 13.25% 13.25% 13%

Rs Crore Rs Crore Rs Crore p.a. p.a. p.a.

Repayment Details

Repayment Period Moratorium Period Principle Repayment Start Date Principle Repayment End Date Interest Repayment Start Date Interest Repayment End Date

12 6 01-Jul-14 01-Jan-26 01-Jan-14 01-Jan-26

Years Months Date Date Date Date

PPA Details

PPA with PTC (including all units) % of total capacity

70% As per CERC based tariff 25

Rs/unit

30% 3.5 25 5%

Rs/unit years

PPA Tariff No. of years Selling through Merchant Basis (including all units) % of total capacity PPA Tariff No. of years Escalation per year

years

Tax Rates

Corporate Tax MAT

33.99% 20.96%

Technical Parameters

GSHR Auxiliary Consumption Plant Load Factor O&M Escalation O&M Expense

2392 7% 85% 5.72% 0.155

kCal/kwh % % % crore/MW

Fuel : Primary Fuel

Fuel Price Price Escalation Gross Calorific Value

900 5% 3400

Rs/tonne p.a. kCal/kg

Secondary

Fuel Price Gross Calorific Value Secondary Fuel Consumption Specific Gravity value of Secondary Fuel Price Escalation Transportation & Handling Charges Escalation

Working Capital Limits

Coal Stock Secondary Fuel O&M Expenses Maintenance Spares (20% of O&M Expense) Receivables from Energy Sales

Depreciation

Rate For Tariff Calculation Land Civil Works & Building Plant & Machinery Max Depreciable Value

Depreciation Rate for IT

Machinery Building

Miscellaneous

Discount Rate Return on Equity Return on Equity pre tax (first 12 years) Return on Equity pre tax (last 13 years) Project Life Total units generated

50 10280 1 0.95 4%

Rs/kg kCal/kg ml/kwh

2 2 1 1 2

Months Months Month Year Months

p.a.

5.28% 0% 3.34% 5.28% 90% 15% 10% 13.10% 15.50% 19.61% 23.48% 25 4914.36

% % % % years MU

ANNEXURE II: PROJECT COST Sl No. 1 2 3 4 5

6 7 8

Particulars Land & Site Development Total Plant & Equipment Civil Works Electric Works Miscellaneous Total Hard Cost

Base Amount 50 2038.48 545

Escalation 0% 0% 0%

Overhead & Pre-Op. Expenses Interest During Construction Working Capital Margin Total Soft Cost

114.59 656.20 565.43 1336.22

Total Project Cost

4251

MEANS OF FINANCE Particulars Debt Equirt Ratio Equity Debt Upfront Equity Total

Total Cost 50 2038.48 545 135 146.5 2914.98

Percentage 3.00 25% 75% 51.5% 100%

Cost (Rs Crore) 1062.80 3188.40 547.34 4251

PROJECT COST BREAKUP i)

ii)

iii)

Land & Site Development Particulars Land Site Development TOTAL

Civil Construction Particulars Civil & Construction Works TOTAL

Plant & Equipment Particulars Steam generators (boilers) & Steam turbine generators with all auxiliaries Coal handling system Ash handling plant CW System

Amount (In Crore) 30 20 50

Amount (In Crore) 545 545

Amount (In Crore) 1431.5 50 50 10.5

DM plant including all accessories

5.05

Air conditioning plants Fire protection system Miscellaneous pumps CW treatment plant IDCT Electro-Mechanical Effluent treatment system

2.15 4.25 2.5 3.3 6 2.38

Chemical laboratory equipment

1.5

Cranes and hoists

2.23

Air compressors and accessories

2.05

Instrumentation and Control system Computers and software Emergency D.G. Sets Fuel unloading, storage and forwarding system Workshop Equipment Cost of Mechanical Spares Freight and Insurance Excise and Central Sales tax Erection testing and commissioning Transmission Line Service tax TOTAL

5 1.05 3.05 6.2 2.75 4 15.95 199.53 159.15 52 16.39 2038.48

iv)

v)

Overheads & Preoperative Expenses Particulars Start-up fuel Design, engineering, construction supervision, inspection and expediting and project management Pre-operative Expenses Insurance during construction TOTAL

Amount (In Crore) 14.57 56.3 29.15 14.57 114.59

Electric Works Expenses

Particulars Power transformers GCB Other electric equipments Cost of Electrical Spares Miscellaneous TOTAL

vi)

Amount (In Crore) 21 8 76.98 2.65 26.37 135

Miscellaneous

Particulars Coal conveyor from Port Railway siding Water intake

Amount (In Crore) 12 55 29.5

Desalination plant and auxiliaries

50

TOTAL

Date of Commencement No. of quarters of construction Period of Construction End of Construction Commercial operation period

146.5

01-Apr-10 15 45 months 31-Dec-13 01-Jan-14

ANNEXURE III: INTEREST DURING CONSTRUCTION Particulars Project Cost without IDC IDC Project Cost with IDC Interest Rate pre COD Interest Rate post COD

Amount 3595 656 4251 13.25% 13.25%

Equity Debt Upfront

25% 75% 51.50%

Jun-10 2010 3

Jul-10 2010 4

Total 1062.801 3188.402

Upfront 547.34 1642.03

Balance 515.46 1546.38

Aug-10 2010 5

Sep-10 2010 6

Oct-10 2010 7

PROJECT PHASING Month Financial Year

Apr-10 2010 1 Total 100% 4251

Percentage Amount

May-10 2010 2

Nov-10 2010 8

Dec-10 2010 9

Jan-11 2011 10

Feb-11 2011 11

Mar-11 2011 12

Apr-11 2011 13

May-11 2011 14

Jun-11 2011 15

Jul-11 2011 16

1.50% 1.50% 1.50% 2.00% 2.00% 2.00% 2.00% 2.00% 1.00% 1.00% 2.00% 2.00% 2.00% 2.00% 2.00% 2.00% 63.76804 63.76804 63.76804 85.02406 85.02406 85.02406 85.02406 85.02406 42.51203 42.51203 85.02406 85.02406 85.02406 85.02406 85.02406 85.02406

Upfront Equity Upfront Debt

547.34 63.76804 63.76804 63.76804 85.02406 85.02406 85.02406 85.02406 15.94 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 1642.03 0.000 0.000 0.000 0.000 0.000 0.000 0.000 69.08205 42.51203 42.51203 85.02406 85.02406 85.02406 85.02406 85.02406 85.02406

Matching Equity Matching Debt

515.46 1546.38

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

Total Equity Total Debt

1062.80 3188.40

63.768 0.000

63.768 0.000

63.768 0.000

85.024 0.000

85.024 0.000

85.024 0.000

85.024 0.000

Total Senior Debt Total Sub Debt

3188.402 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

69.082 0.000

42.512 0.000

42.512 0.000

85.024 0.000

85.024 0.000

85.024 0.000

85.024 0.000

85.024 0.000

85.024 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 69.082 69.082

69.082 42.512 111.594

111.594 42.512 154.106

154.106 85.024 239.130

239.130 85.024 324.154

324.154 85.024 409.178

409.178 85.024 494.202

494.202 85.024 579.226

579.226 85.024 664.250

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.381

0.997

1.467

2.171

3.110

4.049

4.987

5.926

6.865

Opening Balance Monthly Disbursement Closing Balance Interest During Construction

656.203

YEARLY PHASING Year Ending on 31 March Total Expenditure IDC Expenditure less IDC Total Equity Debt

2010 2011 2012 4251.2 658.9364 977.7766 1254.105 656.203 1.379 76.982 219.945 3595.000 657.558 900.794 1034.160 1062.801 547.342 0.000 175.362 3188.402 111.594 977.777 1078.743

2013 1360.385 357.897 1002.488 340.096 1020.289

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

15.942 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 69.08205 42.51203 42.51203 85.02406 85.02406 85.02406 85.02406 85.02406 85.02406

Aug-11 2011 17

Sep-11 2011 18

Oct-11 2011 19

Nov-11 2011 20

Dec-11 2011 21

Jan-12 2012 22

Feb-12 2012 23

Mar-12 2012 24

Apr-12 2012 25

May-12 2012 26

Jun-12 2012 27

Jul-12 2012 28

Aug-12 2012 29

Sep-12 2012 30

Oct-12 2012 31

Nov-12 2012 32

Dec-12 2012 33

Jan-13 2013 34

Feb-13 2013 35

Mar-13 2013 36

2.00% 2.00% 2.00% 2.00% 2.00% 2.50% 2.00% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 3.00% 2.50% 2.50% 85.02406 85.02406 85.02406 85.02406 85.02406 106.2801 85.02406 106.2801 106.2801 106.2801 106.2801 106.2801 106.2801 106.2801 106.2801 106.2801 106.2801 127.5361 106.2801 106.2801 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 85.02406 85.02406 85.02406 85.02406 85.02406 106.2801 85.02406 106.2801 106.2801 106.2801 42.5120 0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 85.02406 85.02406 85.02406 85.02406 85.02406 106.2801 85.02406 106.2801 106.2801 106.2801 85.024 0.000

85.024 0.000

85.024 0.000

664.250 85.024 749.274

749.274 85.024 834.299

834.299 85.024 919.323

7.804

8.743

9.681

85.024 0.000

85.024 0.000

106.280 0.000

85.024 0.000

106.280 0.000

106.280 0.000

106.280 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

15.942 47.826

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

31.884 95.652

26.570 79.710

26.570 79.710

15.942 90.338

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

26.570 79.710

31.884 95.652

26.570 79.710

26.570 79.710

90.338 0.000

79.710 0.000

79.710 0.000

79.710 0.000

79.710 0.000

79.710 0.000

79.710 0.000

95.652 0.000

79.710 0.000

79.710 0.000

919.323 1004.347 1089.371 1195.651 1280.675 1386.955 1493.235 1599.515 1689.853 1769.563 1849.273 1928.983 2008.693 2088.403 2168.113 2263.766 2343.476 85.024 85.024 106.280 85.024 106.280 106.280 106.280 90.338 79.710 79.710 79.710 79.710 79.710 79.710 95.652 79.710 79.710 1004.347 1089.371 1195.651 1280.675 1386.955 1493.235 1599.515 1689.853 1769.563 1849.273 1928.983 2008.693 2088.403 2168.113 2263.766 2343.476 2423.186 10.620

11.559

12.615

13.671

14.728

15.901

17.075

18.160

19.099

19.979

20.859

21.739

22.619

23.500

24.468

25.436

26.316

ANNEXURE IV: DEPRECIATION Depreciation as per IT act Civil Works Opening Balance Depreciation Closing Balance Plant & Machinery Opening Balance Depreciation Closing Balance Total Dep as per IT

Depreciation rate after taking the weighted avg.

Depreciation Cumulative Depreciation

0 545.00 13.625 531.38

1 531.38 53.1375 478.24

2 3 4 5 6 7 478.24 430.41 387.37 348.64 313.77 282.39 47.82375 43.04138 38.73724 34.86351 31.37716 28.23945 430.41 387.37 348.64 313.77 282.39 254.16

8 254.16 25.4155 228.74

9 10 228.74 205.87 22.87395 20.58656 205.87 185.28

11 185.28 18.5279 166.75

2038.48 1962.037 1667.731 1417.572 1204.936 1024.196 870.5662 739.9813 628.9841 534.6365 454.441 386.2749 76.443 294.3056 250.1597 212.6358 180.7404 153.6293 130.5849 110.9972 94.34762 80.19547 68.16615 57.94123 1962.037 1667.731 1417.572 1204.936 1024.196 870.5662 739.9813 628.9841 534.6365 454.441 386.2749 328.3336 90.068

347.4431 297.9835 255.6771 219.4776 188.4929 161.9621 139.2366 119.7631 103.0694 88.75271 76.46913

4.89% 0 1 2 3 4 5 6 7 8 9 10 11 31.53483 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 126.1393 31.53483 157.6742 283.8135 409.9529 536.0922 662.2315 788.3709 914.5102 1040.65 1166.789 1292.928 1419.068

12 166.75 16.67511 150.08

13 150.08 15.0076 135.07

14 15 16 17 18 19 20 21 22 23 24 25 135.07 121.56 109.41 98.46 88.62 79.76 71.78 64.60 58.14 52.33 47.10 42.39 13.50684 12.15616 10.94054 9.846486 8.861837 7.975654 7.178088 6.460279 5.814252 5.232826 4.709544 3.178942 121.56 109.41 98.46 88.62 79.76 71.78 64.60 58.14 52.33 47.10 42.39 39.21

328.3336 279.0836 237.2211 201.6379 171.3922 145.6834 123.8309 105.2562 89.4678 76.04763 64.64049 54.94442 46.70275 39.69734 49.25005 41.86254 35.58316 30.24568 25.70883 21.85251 18.57463 15.78844 13.42017 11.40715 9.696073 8.241662 7.005413 4.465951 279.0836 237.2211 201.6379 171.3922 145.6834 123.8309 105.2562 89.4678 76.04763 64.64049 54.94442 46.70275 39.69734 35.23139 65.92516 56.87014

49.09

42.40184 36.64937 31.69899 27.43647 23.76409 20.59826 17.86742 15.51032 13.47449 11.71496 7.644893

12 13 14 15 16 17 18 19 20 21 22 23 24 25 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 66.88929 1508.253 1597.439 1686.625 1775.81 1864.996 1954.182 2043.368 2132.553 2221.739 2310.925 2400.111 2489.296 2578.482 2645.371

ANNEXURE V: DEBT SERVICING Year Quarters Loan Opening Balance Quarterly Interest Principle Amount Loan Repayments Outstanding Balance

Year Quarters Loan Opening Balance Quarterly Interest Principle Amount Loan Repayments Outstanding Balance

Year Quarters Loan Opening Balance Quarterly Interest Principle Amount Loan Repayments Outstanding Balance

2015 2016 2017 2014 1 2 3 0 Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec 3188.40 3188.40 3188.40 3119.09 3049.78 2980.46 2911.15 2841.84 2772.52 2703.21 2633.90 2564.58 105.62 105.62 105.62 103.32 101.02 98.73 96.43 94.14 91.84 89.54 87.25 84.95 0.00 0.00 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 105.62 105.62 174.93 172.63 170.34 168.04 165.74 163.45 161.15 158.86 156.56 154.26 3188.40 3188.40 3119.09 3049.78 2980.46 2911.15 2841.84 2772.52 2703.21 2633.90 2564.58 2495.27

2018 2019 2020 2017 4 5 6 3 Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec 2495.27 2425.96 2356.65 2287.33 2218.02 2148.71 2079.39 2010.08 1940.77 1871.45 1802.14 1732.83 82.66 80.36 78.06 75.77 73.47 71.18 68.88 66.58 64.29 61.99 59.70 57.40 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 151.97 149.67 147.38 145.08 142.78 140.49 138.19 135.90 133.60 131.30 129.01 126.71 2425.96 2356.65 2287.33 2218.02 2148.71 2079.39 2010.08 1940.77 1871.45 1802.14 1732.83 1663.51

2021 2022 2023 2020 7 8 9 6 Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec 1663.51 1594.20 1524.89 1455.57 1386.26 1316.95 1247.64 1178.32 1109.01 1039.70 970.38 901.07 55.10 52.81 50.51 48.22 45.92 43.62 41.33 39.03 36.74 34.44 32.14 29.85 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 124.42 122.12 119.83 117.53 115.23 112.94 110.64 108.35 106.05 103.75 101.46 99.16 1594.20 1524.89 1455.57 1386.26 1316.95 1247.64 1178.32 1109.01 1039.70 970.38 901.07 831.76

Year Quarters Loan Opening Balance Quarterly Interest Principle Amount Loan Repayments Outstanding Balance

2024 2025 2026 2023 10 11 12 9 Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec Jan-Mar Apr-Jun Jul-Sept Oct-Dec 831.76 762.44 693.13 623.82 554.50 485.19 415.88 346.57 277.25 207.94 138.63 69.31 27.55 25.26 22.96 20.66 18.37 16.07 13.78 11.48 9.18 6.89 4.59 2.30 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 69.31 96.87 94.57 92.27 89.98 87.68 85.39 83.09 80.79 78.50 76.20 73.91 71.61 762.44 693.13 623.82 554.50 485.19 415.88 346.57 277.25 207.94 138.63 69.31 0.0

ANNEXURE VI: ENERGY CHARGE PRIMARY FUEL (COAL) Gross station heat rate (kCal/kwh) Gross Calorific value of Secondary Fuel oil (kCal/L) Heat contribution from secondary fuel oil (kCal/kwh) Heat contribution from primary fuel oil (kCal/kwh) Gross calorific value for coal (kCal/kg) Coal required to produce 1 unit of electricity (kg/kwh) Cost of Coal (Rs/kg) Coal price to produce 1 unit of electricity (Rs/kwh)

2392 10280 10.28 2381.72 3400 0.7005 0.9 0.63

SECONDARY FUEL Secondary Fuel Oil Consumption (L/kwh) Specific gravity of Secondary Fuel Oil Secondary Fuel Oil Consumption (kg/kwh) Secondary Fuel Oil cost (Rs/kg) Secondary Fuel Oil cost per unit of electricity (Rs/kwh) Total Fuel Oil consumption per annum (Rs Crs)

0.001 0.95 0.00095 50 0.0475 23.34

ENERGY CHARGE Variable charges for single unit (Rs/kwh) Auxiliary Consumption Rate of Energy delivered to Ex Bus

Year Total Coal cost per annum (in crs) Total secondary fuel oil cost per annum (in crs)

0.63 7% 0.59

0

1

2

3

4

5

6

7

8

9

10

11

12

77.457

325.320

341.586

358.665

376.598

395.428

415.200

435.960

457.758

480.646

504.678

529.912

556.407

5.84

24.277

25.248

26.258

27.308

28.401

29.537

30.718

31.947

33.225

34.554

35.936

37.373

13 14 584.2277 613.4391 38.86816 40.42289

15 644.111 42.0398

16 17 18 676.3166 710.1324 745.639054 43.72139 45.47025 47.2890603

19 782.9210065 49.18062275

20 21 22 23 24 25 822.0671 863.1704 906.3289 951.6454 999.2276 786.8918 51.14785 53.19376 55.32151 57.53437 59.83575 46.67188

ANNEXURE VII: WORKING CAPITAL Year

2014 0

2015 1

2016 2

2017 3

2018 4

2019 5

2020 6

2021 7

2022 8

2023 9

2024 10

ITEMS Primary Fuel

2

Months

12.910

54.220

56.931

59.778

62.766

65.905

69.200

72.660

76.293

80.108

84.113

Secondary Fuel

2

Months

0.973

4.046

4.208

4.376

4.551

4.733

4.923

5.120

5.324

5.537

5.759

O&M Expense

1

Month

8.498

8.984

9.498

10.042

10.616

11.223

11.865

12.544

13.261

14.020

14.822

20%

O&M

20.396

21.563

22.796

24.100

25.479

26.936

28.477

30.105

31.828

33.648

35.573

2

Months

56.723

231.998

235.202

238.503

242.191

246.287

250.810

255.784

261.229

267.172

273.636

99.500 99.500 74.625 9.701

320.812 221.312 240.609 31.279

328.635 7.823 246.476 32.042

336.798 8.163 252.599 32.838

345.603 8.805 259.203 33.696

355.084 9.481 266.313 34.621

365.275 10.191 273.956 35.614

376.213 10.938 282.160 36.681

387.936 11.723 290.952 37.824

400.485 12.549 300.364 39.047

413.902 13.418 310.427 40.355

91.001 91.001

311.827 220.826

319.137 7.309

326.756 7.620

334.987 8.231

343.861 8.873

353.410 9.549

363.669 10.259

374.674 11.006

386.465 11.790

399.080 12.616

Maintenance Spares Receivables

WORKING CAPITAL Total Working Capital Increase in Working Capital Working Capital Debt Interest on Working Capital CURRENT ASSETS Total Current Assets Increase in Current Assets

2025 11

2026 12

2027 13

2028 14

2029 15

2030 16

2031 17

2032 18

2033 19

2034 20

2035 21

2036 22

2037 23

2038 24

2039 25

88.319

92.735

97.371

102.240

107.352

112.719

118.355

124.273

130.487

137.011

143.862

151.055

158.608

166.538

131.149

5.989

6.229

6.478

6.737

7.007

7.287

7.578

7.882

8.197

8.525

8.866

9.220

9.589

9.973

7.779

15.670

16.566

17.514

18.515

19.575

20.694

21.878

23.129

24.452

25.851

27.330

28.893

30.546

32.293

34.140

37.607

39.759

42.033

44.437

46.979

49.666

52.507

55.510

58.686

62.042

65.591

69.343

73.309

77.503

81.936

280.648

288.731

299.635

312.800

326.635

341.172

356.448

372.500

389.368

407.092

425.718

445.291

465.858

487.471

349.734

428.233 14.331 321.175 41.753

444.019 15.786 333.014 43.292

463.030 19.011 347.273 45.145

484.730 21.699 363.547 47.261

507.547 22.817 380.660 49.486

531.539 23.992 398.654 51.825

556.767 25.228 417.575 54.285

583.294 26.528 437.471 56.871

611.189 27.895 458.392 59.591

640.522 29.333 480.391 62.451

671.367 30.845 503.525 65.458

703.802 32.435 527.851 68.621

737.910 34.108 553.432 71.946

773.777 35.868 580.333 75.443

604.737 -169.041 453.553 58.962

412.564 13.483

427.453 14.889

445.517 18.064

466.214 20.698

487.972 21.758

510.844 22.872

534.889 24.044

560.165 25.276

586.737 26.572

614.671 27.934

644.037 29.366

674.909 30.872

707.364 32.455

741.485 34.120

570.597 -170.888

ANNEXURE VIII: TARIFF Year Variable Tariff Energy Available for Sale Variable Fuel Cost Variable Fuel Cost per Unit Fixed Tariff Interest Return on Equity Depreciation Cumulative Depreciation O&M Expense Interest on Working Capital Fixed Cost Fixed Cost per unit Total Cost per unit

2014 0

2016 2

2017 3

2018 4

2019 5

2020 6

2021 7

2022 8

2023 9

2024 10

2025 11

2026 12

2027 13

2028 14

2029 15

2030 16

2031 17

2032 18

2033 19

2034 20

2035 21

2036 22

2037 23

2038 24

2039 25

Million 1228.59 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 4914.36 3685.77 Units Rs Crore 77.46 325.32 341.59 358.67 376.60 395.43 415.20 435.96 457.76 480.65 504.68 529.91 556.41 584.23 613.44 644.11 676.32 710.13 745.64 782.92 822.07 863.17 906.33 951.65 999.23 786.89 Rs/kwh

0.63

0.66

0.70

0.73

0.77

0.80

0.84

0.89

0.93

0.98

1.03

1.08

1.13

1.19

1.25

1.31

1.38

1.45

1.52

1.59

1.67

1.76

1.84

1.94

2.03

2.13

Rs Crore Rs Crore Rs Crore

105.62 52.10 31.53

415.58 208.42 126.14

381.14 208.42 126.14

344.40 208.42 126.14

307.66 208.42 126.14

270.93 208.42 126.14

234.19 208.42 126.14

197.46 208.42 126.14

160.72 208.42 126.14

123.98 208.42 126.14

87.25 208.42 126.14

50.51 208.42 126.14

13.78 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 249.56 89.19

0.00 187.17 66.89

Rs Crore

31.53

157.67

283.81

409.95

536.09

662.23

788.37

914.51 1040.65 1166.79 1292.93 1419.07 1508.25 1597.44 1686.62 1775.81 1865.00 1954.18 2043.37 2132.55 2221.74 2310.92 2400.11 2489.30 2578.48 2645.37

Rs Crore

25.50

107.81

113.98

120.50

127.39

134.68

142.38

150.53

159.14

168.24

177.86

188.04

198.79

210.16

222.19

234.89

248.33

262.53

277.55

293.43

310.21

327.96

346.72

366.55

387.51

Rs Crore

9.70

31.28

32.04

32.84

33.70

34.62

35.61

36.68

37.82

39.05

40.36

41.75

43.29

45.15

47.26

49.49

51.83

54.28

56.87

59.59

62.45

65.46

68.62

71.95

75.44

58.96

Rs Crore Rs/kwh Rs/kwh

224.45 1.83 2.46

889.23 1.81 2.47

861.72 1.75 2.45

832.30 1.69 2.42

803.31 1.63 2.40

774.79 1.58 2.38

746.75 1.52 2.36

719.22 1.46 2.35

692.24 1.41 2.34

665.83 1.35 2.33

640.02 1.30 2.33

614.86 1.25 2.33

594.61 1.21 2.34

594.05 1.21 2.40

608.19 1.24 2.49

623.13 1.27 2.58

638.90 1.30 2.68

655.56 1.33 2.78

673.17 1.37 2.89

691.76 1.41 3.00

711.41 1.45 3.12

732.16 1.49 3.25

754.08 1.53 3.38

777.24 1.58 3.52

801.70 1.63 3.66

338.63 0.92 3.05

1.00

0.8842

0.7818

0.69121

0.6112

0.5404

0.4778

0.4224

0.3735

0.3302

0.292

0.2582

0.2283

0.2018

0.1785

0.1578

0.1395

0.1233

0.1091

0.0964

0.0853

0.0754

0.0667

0.0589

0.0521 0.046072

0.6305 1.8269 2.4574

0.5853 1.5999 2.1852

0.5434 1.3708 1.914

0.50447 1.17064 1.67511

0.4683 0.999 1.4673

0.4348 0.8519 1.2867

0.4037 0.726 1.1296

0.3747 0.6182 0.993

0.3479 0.5261 0.874

0.323 0.4474 0.7704

0.2999 0.3803 0.6801

0.2784 0.323 0.6014

0.2584 0.2399 0.2762 0.244 0.5346 0.4839 2.475

0.2228 0.2208 0.4436

0.2068 0.2001 0.4069

0.192 0.1814 0.3734

0.1782 0.1645 0.3428

0.1655 0.1494 0.3149

0.1536 0.1357 0.2894

0.1426 0.1234 0.266

0.1324 0.1123 0.2447

0.1229 0.1023 0.2252

0.1141 0.0932 0.2073

0.1059 0.098361 0.085 0.042328 0.191 0.140689

PV Calculation PV Factor Discounted Tariff Variable Tariff Fixed Tariff Total tariff Levelised Tariff

2015 1

Rs/kwh Rs/kwh Rs/kwh Rs/kwh

25.60

ANNEXURE IX: PROFIT & LOSS Year Revenue from Energy Sale to PTC Revenue from energy sale on Merchant basis Total Revenue

0 2014

1 2015

2 2016

3 2017

4 2018

5 2019

6 2020

7 2021

8 2022

9 2023

10 2024

211.336

850.182

842.311

833.672

825.936

819.150

813.363

808.627

804.998

802.532

801.292

129.002

541.8082

568.8986

597.3435

627.2107

658.5712

691.4998

726.0748

762.3785

800.4975

840.5223

340.338

1391.990

1411.210

1431.016

1453.147

1477.721

1504.863

1534.702

1567.376

1603.030

1641.814

Expenses Fuel O&M Expenses Depreciation Interest payments Total Expenditure

77.457 325.320 25.495 107.813 31.53483 126.1393 115.32 446.85 249.804 1006.127

341.586 113.980 126.1393 413.18 994.883

358.665 120.500 126.1393 377.24 982.542

376.598 127.393 126.1393 341.36 971.490

395.428 134.679 126.1393 305.55 961.795

415.200 142.383 126.1393 269.81 953.528

435.960 150.527 126.1393 234.14 946.763

457.758 159.138 126.1393 198.54 941.578

480.646 168.240 126.1393 163.03 938.056

504.678 177.864 126.1393 127.60 936.284

Profit before tax, PBT

90.534

385.863

416.327

448.474

481.657

515.926

551.334

587.939

625.798

664.974

705.530

PBT+Dep on books

122.069

512.002

542.466

574.613

607.796

642.065

677.474

714.078

751.938

791.113

831.669

PBT for IT purposes

32.001

164.559

244.483

318.936

388.318

453.572

515.512

574.842

632.174

688.044

742.917

18.97593 10.87709 18.97593

80.87692 55.93375 80.87692

87.2621 83.09967 87.2621

94.00017 108.4064 108.4064

100.9552 131.9894 131.9894

108.138 154.1692 154.1692

115.5597 175.2224 175.2224

123.232 195.3887 195.3887

131.1673 214.8761 214.8761

139.3785 233.866 233.866

147.8791 252.5174 252.5174

71.558

304.986

329.065

340.068

349.667

361.757

376.112

392.550

410.922

431.108

453.013

MAT Corporate Tax Payable Tax Profit after tax, PAT

11 2025

12 2026

13 2027

14 2028

15 2029

16 2030

17 2031

18 2032

19 2033

20 2034

21 2035

22 2036

23 2037

24 2038

25 2039

801.340

805.709

824.798

855.142

887.065

920.652

955.988

993.165

1032.279

1073.433

1116.731

1162.287

1210.219

1260.651

787.862

882.5484

926.6759

973.0097

1021.66

1072.743

1126.38

1182.699

1241.834

1303.926

1369.122

1437.578

1509.457

1584.93

1664.177 1310.539

1683.889

1732.385

1797.807

1876.802

1959.809

2047.032

2138.687

2234.999

2336.205

2442.555

2554.309

2671.744

2795.149

2924.828 2098.401

529.912 188.037 126.1393 92.26 936.353

556.407 198.793 89.18573 57.07 901.454

584.228 210.164 89.18573 45.15 928.723

613.439 644.111 676.317 710.132 745.639 782.921 822.067 863.170 906.329 951.645 999.228 786.892 222.186 234.895 248.330 262.535 277.552 293.428 310.212 327.956 346.715 366.547 387.514 25.605 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 89.18573 66.88929 47.26 49.49 51.83 54.28 56.87 59.59 62.45 65.46 68.62 71.95 75.44 58.96 972.071 1017.677 1065.658 1116.138 1169.248 1225.126 1283.916 1345.771 1410.851 1479.325 1551.371 938.348

747.536

830.931

869.084

904.730

942.132

981.374

1022.549

1065.751

1111.080

1158.639

1208.539

1260.894

1315.824

1373.457 1160.053

873.675

920.117

958.270

993.916

1031.317

1070.560

1111.735

1154.937

1200.266

1247.825

1297.725

1350.079

1405.010

1462.643 1226.943

797.206

854.192

901.400

944.826

988.915

1033.911

1080.036

1127.501

1176.501

1227.227

1279.857

1334.569

1391.536

1450.928 1219.298

156.6835 270.9702 270.9702

174.1632 290.3398 290.3398

182.1601 306.3858 306.3858

189.6315 321.1463 321.1463

197.4708 336.1324 336.1324

205.6961 351.4263 351.4263

214.3264 367.1043 367.1043

223.3815 383.2375 383.2375

232.8823 399.8929 399.8929

242.8508 417.1343 417.1343

253.3097 435.0234 435.0234

264.2833 453.62 453.62

275.7968 472.9829 472.9829

287.8766 243.1472 493.1704 414.4393 493.1704 414.4393

476.565

540.591

562.698

583.584

605.999

629.948

655.445

682.514

711.187

741.505

773.515

807.274

842.841

880.287

745.614

ANNEXURE X: CASH FLOW Year

0 2014

1 2015

2 2016

3 2017

4 2018

5 2019

6 2020

7 2021

8 2022

9 2023

10 2024

11 2025

12 2026

Inflow Equity Debt Term Loan WC Debt PBT Depreciation Total cash inflow

1062.80 3271.53 3188.40 83.12 90.534 31.535 4456.40

0 0 0 0 0 166.46 6.39 6.66 7.18 7.71 0 0 0 0 0 166.46 6.39 6.66 7.18 7.71 385.863 416.327 448.474 481.657 515.926 126.139 126.139 126.139 126.139 126.139 678.47 548.85 581.28 614.98 649.78

0 8.29 0 8.29 551.334 126.139 685.77

0 8.87 0 8.87 587.939 126.139 722.95

0 9.51 0 9.51 625.798 126.139 761.45

0 10.17 0 10.17 664.974 126.139 801.28

0 10.86 0 10.86 705.530 126.139 842.53

0 11.60 0 11.60 747.536 126.139 885.27

0 12.74 0 12.74 830.931 89.186 932.86

Outflow Project expenditure Increase in WC Tax Loan repayments Total cash outflow

4251.20 99.500 18.976 0.000 4369.68

0 0 0 0 0 221.312 7.823 8.163 8.805 9.481 80.877 87.262 108.406 131.989 154.169 207.939 277.252 277.252 277.252 277.252 510.13 372.34 393.82 418.05 440.90

0 10.191 175.222 277.252 462.67

0 10.938 195.389 277.252 483.58

0 11.723 214.876 277.252 503.85

0 12.549 233.866 277.252 523.67

0 13.418 252.517 277.252 543.19

0 14.331 270.970 277.252 562.55

0 15.786 290.340 207.939 514.06

Excess/Shortfall Opening Balance Closing Balance

86.718 168.338 176.516 187.454 196.933 208.873 223.101 239.373 257.598 277.617 299.345 322.720 418.791 0.000 86.718 255.056 431.572 619.026 815.959 1024.832 1247.934 1487.306 1744.905 2022.522 2321.867 2644.587 86.718 255.056 431.572 619.026 815.959 1024.832 1247.934 1487.306 1744.905 2022.522 2321.867 2644.587 3063.378

13 2027

14 2028

15 2029

16 2030

17 2031

0 15.20 0 15.20 869.084 89.186 973.47

0 17.28 0 17.28 904.730 89.186 1011.20

0 18.16 0 18.16 942.132 89.186 1049.48

0 0 0 0 0 0 0 0 0 19.11 20.11 21.15 22.24 23.40 24.61 25.89 27.24 28.64 0 0 0 0 0 0 0 0 0 19.11 20.11 21.15 22.24 23.40 24.61 25.89 27.24 28.64 981.374 1022.549 1065.751 1111.080 1158.639 1208.539 1260.894 1315.824 1373.457 89.186 89.186 89.186 89.186 89.186 89.186 89.186 89.186 89.186 1089.67 1131.85 1176.08 1222.51 1271.22 1322.34 1375.97 1432.25 1491.28

0 19.011 306.386 0.000 325.40

0 21.699 321.146 0.000 342.85

0 22.817 336.132 0.000 358.95

0 23.992 351.426 0.000 375.42

0 25.228 367.104 0.000 392.33

18 2032

0 26.528 383.237 0.000 409.77

19 2033

0 27.895 399.893 0.000 427.79

20 2034

0 29.333 417.134 0.000 446.47

21 2035

0 30.845 435.023 0.000 465.87

22 2036

0 32.435 453.620 0.000 486.06

23 2037

0 34.108 472.983 0.000 507.09

24 2038

25 2039

0 -124.93 0 -124.93 1160.053 66.889 1102.01

0 1 35.868 -169.041 493.170 414.439 0.000 0.000 529.04 246.40

648.071 668.355 690.531 714.256 739.514 766.318 794.719 824.757 856.470 889.911 925.160 962.246 855.614 3063.378 3711.450 4379.805 5070.335 5784.591 6524.105 7290.423 8085.142 8909.899 9766.37 10656.28 11581.44 12543.69 3711.450 4379.805 5070.335 5784.591 6524.105 7290.423 8085.142 8909.899 9766.37 10656.28 11581.44 12543.69 13399.30

ANNEXURE XI: BALANCE SHEET 0 2014

1 2015

2 2016

3 2017

4 2018

5 2019

6 2020

7 2021

8 2022

9 2023

10 2024

11 2025

Liabilities Equity Capital Reserve and Surplus Loan Funds Term Loan Working Capital loan Total Liabilities

1062.801 71.558 3263.027 3188.402 74.625 4397.39

1062.801 376.544 3221.072 2980.463 240.609 4660.42

1062.801 705.609 2949.687 2703.210 246.476 4718.10

1062.801 1045.677 2678.557 2425.958 252.599 4787.03

1062.801 1395.344 2407.908 2148.706 259.203 4866.05

1062.801 1757.100 2137.767 1871.453 266.313 4957.67

1062.801 2133.213 1868.157 1594.201 273.956 5064.17

1062.801 2525.763 1599.108 1316.949 282.160 5187.67

1062.801 2936.685 1330.648 1039.696 290.952 5330.13

1062.801 3367.793 1062.808 762.444 300.364 5493.40

1062.801 3820.805 795.618 485.192 310.427 5679.22

1062.801 4297.371 529.114 207.939 321.175 5889.29

Assets Project Asset Depreciation Current Asset Coal Stock Secondary Fuel Maintenance Spares Receivables Cash Total Assets

4219.67 31.535 91.001 12.910 0.973 20.396 56.723 86.718 4397.39

4093.53 126.139 311.827 54.220 4.046 21.563 231.998 255.056 4660.41

3967.39 126.139 319.137 56.931 4.208 22.796 235.202 431.572 4718.10

3841.25 126.139 326.756 59.778 4.376 24.100 238.503 619.026 4787.03

3715.11 126.139 334.987 62.766 4.551 25.479 242.191 815.959 4866.06

3588.97 126.139 343.861 65.905 4.733 26.936 246.287 1024.832 4957.66

3462.83 126.139 353.410 69.200 4.923 28.477 250.810 1247.934 5064.18

3336.69 126.139 363.669 72.660 5.120 30.105 255.784 1487.306 5187.67

3210.55 126.139 374.674 76.293 5.324 31.828 261.229 1744.905 5330.13

3084.41 126.139 386.465 80.108 5.537 33.648 267.172 2022.522 5493.40

2958.27 126.139 399.080 84.113 5.759 35.573 273.636 2321.867 5679.22

2832.14 126.139 412.564 88.319 5.989 37.607 280.648 2644.587 5889.29

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Year

Difference

12 2026

13 2027

14 2028

15 2029

16 2030

17 2031

18 2032

19 2033

20 2034

21 2035

22 2036

23 2037

24 2038

25 2039

1062.801 4837.962 333.014 0.000 333.014 6233.78

1062.801 5400.660 347.273 0.000 347.273 6810.73

1062.801 5984.244 363.547 0.000 363.547 7410.59

1062.801 6590.244 380.660 0.000 380.660 8033.70

1062.801 7220.192 398.654 0.000 398.654 8681.65

1062.801 7875.637 417.575 0.000 417.575 9356.01

1062.801 8558.151 437.471 0.000 437.471 10058.42

1062.801 9269.338 458.392 0.000 458.392 10790.53

1062.801 10010.843 480.391 0.000 480.391 11554.03

1062.801 10784.358 503.525 0.000 503.525 12350.68

1062.801 11591.632 527.851 0.000 527.851 13182.28

1062.801 12434.473 553.432 0.000 553.432 14050.71

1062.801 13314.760 580.333 0.000 580.333 14957.89

1062.801 14060.37 453.553 0.000 453.553 15576.73

2742.95 89.186 427.453 92.735 6.229 39.759 288.731 3063.378 6233.78

2653.76 89.186 445.517 97.371 6.478 42.033 299.635 3711.450 6810.73

2564.58 89.186 466.214 102.240 6.737 44.437 312.800 4379.805 7410.60

2475.39 89.186 487.972 107.352 7.007 46.979 326.635 5070.335 8033.70

2386.21 89.186 510.844 112.719 7.287 49.666 341.172 5784.591 8681.64

2297.02 89.186 534.889 118.355 7.578 52.507 356.448 6524.105 9356.01

2207.84 89.186 560.165 124.273 7.882 55.510 372.500 7290.423 10058.42

2118.65 89.186 586.737 130.487 8.197 58.686 389.368 8085.142 10790.53

2029.46 89.186 614.671 137.011 8.525 62.042 407.092 8909.899 11554.03

1940.28 89.186 644.037 143.862 8.866 65.591 425.718 9766.369 12350.68

1851.09 89.186 674.909 151.055 9.220 69.343 445.291 10656.280 13182.28

1761.91 89.186 707.364 158.608 9.589 73.309 465.858 11581.440 14050.71

1672.72 89.186 741.485 166.538 9.973 77.503 487.471 12543.685 14957.89

1606.83 66.889 570.597 131.149 7.779 81.936 349.734 13399.30 15576.73

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

ANNEXURE XII: RATIOS 2010

2011

2012

2013

Cash Outflow Cash Inflow PAT Add: Depreciation Add: Interest on loan Add: Interest on WC Add: Tax Total cash inflow Cash to the project Project IRR

-657.558

-900.794

-1034.16

-1002.49

0 0 0 0 0 0 -657.558 18.49%

0 0 0 0 0 0 -900.794

0 0 0 0 0 0 -1034.16

0 0 0 0 0 0 -1002.49

Cash Outflow Cash Inflow Cash to equity holder Equity IRR

-547.342 0 -547.342 21.37%

0 0 0

-175.362 0 -175.362

-340.10 0 -340.10

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

71.558 31.535 105.616 9.701 18.976 237.386 237.386

304.986 126.139 415.575 31.279 80.877 958.857 958.857

329.065 126.139 381.135 32.042 87.262 955.643 955.643

340.068 126.139 344.399 32.838 108.406 951.851 951.851

349.667 126.139 307.663 33.696 131.989 949.156 949.156

361.757 126.139 270.928 34.621 154.169 947.613 947.613

376.112 126.139 234.192 35.614 175.222 947.280 947.280

392.550 126.139 197.456 36.681 195.389 948.215 948.215

410.922 126.139 160.720 37.824 214.876 950.481 950.481

431.108 126.139 123.984 39.047 233.866 954.144 954.144

71.558 304.986 329.065 340.068 349.667 361.757 376.112 392.550 410.922 431.108 71.558086 304.98623 329.06473 340.06764 349.66729 361.75651 376.11202 392.5503 410.92209 431.10764

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

453.013 126.139 87.248 40.355 252.517 959.273 959.273

476.565 126.139 50.512 41.753 270.970 965.940 965.940

540.591 89.186 13.776 43.292 290.340 977.185 977.185

562.698 89.186 0.000 45.145 306.386 1003.415 1003.415

583.584 89.186 0.000 47.261 321.146 1041.177 1041.177

605.999 89.186 0.000 49.486 336.132 1080.803 1080.803

629.948 89.186 0.000 51.825 351.426 1122.385 1122.385

655.445 89.186 0.000 54.285 367.104 1166.020 1166.020

682.514 89.186 0.000 56.871 383.237 1211.808 1211.808

711.187 89.186 0.000 59.591 399.893 1259.857 1259.857

741.505 89.186 0.000 62.451 417.134 1310.276 1310.276

773.515 89.186 0.000 65.458 435.023 1363.183 1363.183

807.274 89.186 0.000 68.621 453.620 1418.700 1418.700

842.841 89.186 0.000 71.946 472.983 1476.956 1476.956

880.287 89.186 0.000 75.443 493.170 1538.086 1538.086

453.013 476.565 540.591 562.698 583.584 605.999 629.948 655.445 682.514 711.187 741.505 773.515 807.274 842.841 880.287 453.01274 476.56532 540.59141 562.69847 583.58389 605.9992 629.94819 655.44518 682.51395 711.18699 741.50481 773.51537 807.27366 842.841393 880.286707

ANNEXURE XIII: DSCR Year PAT Add: Depreciation Add: Interest on Term Loan Add: Tax Total

0 2014 71.558 31.535 105.616 18.976 227.685

1 2015 304.986 126.139 415.575 80.877 927.578

2 2016 329.065 126.139 381.135 87.262 923.602

3 2017 340.068 126.139 344.399 108.406 919.013

4 2018 349.667 126.139 307.663 131.989 915.460

5 2019 361.757 126.139 270.928 154.169 912.993

6 2020 376.112 126.139 234.192 175.222 911.665

7 2021 392.550 126.139 197.456 195.389 911.534

8 2022 410.922 126.139 160.720 214.876 912.657

9 2023 431.108 126.139 123.984 233.866 915.097

10 2024 453.013 126.139 87.248 252.517 918.917

11 2025 476.565 126.139 50.512 270.970 924.187

12 2026 540.591 89.186 13.776 290.340 933.893

Principal Repayment Interest Payment Total Debt Services

0.000 105.616 105.616

207.939 415.575 623.515

277.252 381.135 658.388

277.252 344.399 621.652

277.252 307.663 584.916

277.252 270.928 548.180

277.252 234.192 511.444

277.252 197.456 474.708

277.252 160.720 437.972

277.252 123.984 401.236

277.252 87.248 364.500

277.252 50.512 327.764

207.939 13.776 221.715

2.156 1.403 2.106 4.212

1.488

1.403

1.478

1.565

1.665

1.783

1.920

2.084

2.281

2.521

2.820

4.212

DSCR Minimum DSCR Average DSCR Maximum DSCR