A MAJOR PROJECT REPORT

IN

Finance management

SUBMITTED IN PARTIAL FULFILLMENT OF REQUIREMENT

BACHELOR OF BUSINESS ADMINISTRATION (B.B.A.)

BBAIII (E)

BATCH -2010-2013

Submitted to: Submitted by:

Mr.j.k.batra Mukesh kumar

(Asst. Professor) 03724501710

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JIMS KALKAJI,I.P.UNVERSITY Company Certificate

(LETTER HEAD of the Company )

TO WHOM IT MAY CONCERN

This is to certify that Mukesh kumar , a student of jims ,kalkaji , undertook a project on “_Finance managment” at Universal Crescent power Pvt.Ltd. ( UCPPL)From 11-06-2012 to 020-07-2012.

Ms./Mr Mukesh kumar has successfully completed the project under the guidance of Mr./Ms. Mukesh kumar. She/He is a sincere and hard-working student with pleasant manners.

We wish all success in her/him future endeavours.

Signature with date(Name)(Designation)(Company Name)

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CERTIFICATE OF ORIGIN

This is to certify that Ms./Mr. MUKESH KUMAR, a student of Graduate Degree in _, jims kalkaji has worked in the UCPPL, under the able guidance and supervision of Mr./Ms._Arvind Pasi, designation Manager-Corporate strategy, Company UCPPL. The period for which he/ she was on training was for 8 weeks, starting from 11-06-2011 to 20-07-2012. This Summer Internship report has the requisite standard for the partial fulfillment the Graduate Degree in International Business. To the best of our knowledge no part of this report has been reproduced from any other report and the contents are based on original research.

Signature Signature(Faculty Guide) (Student)

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ACKNOWLEDGEMENT

I express my sincere gratitude to my industry guide Mr./Ms.Arvind Pasi,Manager-corporate strategy, UCPPL , for his/her able guidance, continuous support and cooperation throughout my project, without which the present work would not have been possible.I would also like to thank the entire team of UCPPL, for the constant support and help in the successful completion of my project.

Also, I am thankful to my faculty guide Prof./Mr./Ms J.K .BATRA. of my institute, for his/her continued guidance and invaluable encouragement.

Signature(Student)

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TABLE OF CONTENTS

Chapter No. Subject Page No.

1.0 Executive Summary 6

2.0 Review of literature 7

3.0 Industry Profile 10

4.0 Company Profile 35

5.0 Objectives

A) To understand the power sector

Evaluation of current scenario 41

Regulations and power industry structure 43

Electricity generation, transmission & distribution 47

Demand and Supply scenario 51

B) To understand the types of Finances and relevant factors

Debt- Equity structure 53

Costing parameters 54

Tariff evaluation 56

Due diligence during funding of the project 64

6.0 Issues and challenges facing thermal power sector 68

7.0 Comparative Ratio Analysis of 5 major players 70

8.0 Recommendations 84

9.0 Bibliography 85

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Executive SummaryThe power sector of India is growing at a rapid rate. India’s current installed capacity is

1,74,911.40 MW, out of which 1,13, 456 MW is the total thermal power capacity installed all

over India. This document highlights the current scenario of thermal power projects in India. It

also compares the power sector to other sectors as to why it is a more attractive option for

investment. With the introduction of certain regulations, the Indian power sector has witnessed

significant structural and regulatory changes to make it attractive for private investment. These

include 100% foreign direct investment all segments of the power sector including trading, Zero

customs and excise duty waiver on capital equipment for MPP Income tax holiday for 10 years

etc. Since the primary focus is on the thermal power sector (coal based power stations) , we

highlight which are the major thermal power generation companies, the issues and challenges

being faced by the Indian thermal power sector and we also look into the financial aspect of

setting up a thermal power plant. A short peek at the past performances of the major players has

also been looked at and what are their future plans, have also been highlighted. This document

also looks at the key financing and investment trends that have given a boost to the thermal

power sector in the past and will do so in the future also. The role of the power finance

corporation(PFC) which is the primary lender has also been discussed in detail.

We have undertaken certain objectives which look into the costing parameters with regard to land cost, fuel cost, availability of water etc, tariff evaluation i.e interest on working capital, interest on loan capital, depreciation cost etc. and the due- diligence done by the power company for the funding of the project .

Furthermore, we look at the current demand and supply scenario of electricity currently being generated, transmitted and distributed all over India. the road that lies ahead of us is dotted with innumerable challenges that result from the gaps that exist between what’s planned versus what the power sector has been able to deliver. This document highlights and quantifies some of these gaps and attempts to analyze the problem. There are certain regulations which have been set by the government of India with regard to the debt- equity structure, regulatory requirement for financing etc. which all the power companies have to follow. These regulations are discussed at length in this document.

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The report also gives a detailed ratio analysis on 5 major players in the power sector which has also been carried out based on their past 5yr performance i.e. from FY 2005 to FY 2010. This helps us understand that out of the power stocks which ones are the best suited for investment.

Review of literature

DPR of UCPPL: Gives a detailed analysis of the current growth in the indian economy. It also gives us an insight into the companies proposed projects in Gujarat and west Benga land what are the various parameters involved in setting up a thermal power plant. It also shows the demand and supply gap that exists all over india and what are the issues and challenges being faced by the indian thermal power sector. CERC Tariff regulations 2009-14: These regulations may be called the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2009. These regulations came into force on 1.4.2009, and unless reviewed earlier or extended by the Commission, shall remain in force for a period of 5 years from the date of commencement, Provided that where a project, or a part thereof, has been declared under commercial operation before the date of commencement of these regulations and whose tariff has not been finally determined by the Commission till that date, tariff in respect of such project or such part thereof for the period ending 31.3.2009 shall be determined in accordance with the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2004.

Sreekumar (2009) reviews the market-oriented power sector reforms initiated in India in the early 1990s. It brings out a public interest oriented critique of the three phases of the reforms —firstly, privatization of generation, secondly, state sector restructuring and finally, the ongoing reforms since the passage of the Electricity Act 2003. Reforms were taken up as a response to the crisis in the sector. The article questions the success of the process in solving the crisis. While acknowledging positive elements like increase in transparency and participation, it criticizes the process for neglect of development issues like rural electrification and energy efficiency. The article concludes with some thoughts on developing an alternate reform approach

Schwartz (2008), Studies the business of NAILD distributor through this article. TheNAILD is an organisation supporting lighting distributors in the US with publications, training, and conferences. According to him, recent changes and trends in the lighting market provide new opportunities. The keys to taking advantage of the opportunities is to understand the market, know where to get more information, provide updates to your customers, and turn information into active marketing and promotional efforts. The Energy Independence and Security Act of 2007 add to the programs and efforts introduced in EPACT 2005. A key component of the ENERGY STAR qualified light fixtures program is the Advanced Lighting Package (ALP). As market trends and legislation move purchasers away from inefficient technologies and towards energy-efficient products, NAILD distributors that become ENERGY STAR Partners have an opportunity to increase sales and profits.

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Augustine (2007), tries to put forth a model pertaining to transportation because India is facing a huge increase in power consumption. The model is done with an aid of GAMS (General Algebraic Modelling System). The power sector is represented in the model by production capacities, cost of production and transmission, demand for power and the distances between power plants and consumption centres. The author has considered major power generating areas of the country like Ranchi, Bhopal, bhubwaneshwar, dhanbad, Vishakhapatnam etc. The model described is very realistic, scalable and easy to implement, but has only considered coal, hydroelectric and natural gas technologies. It can be expanded to include other technologies and also can be made dynamic to provide solutions for different time periods representing the maturing of the power generation plants during the duration of the model.

Singh (2006) address the Power sector reforms in India. Reforms were initiated at a juncture when the sector was plagued with commercial losses and burgeoning subsidy burden. Investment in the sector was not able to keep pace with growing demand for electricity. This paper takes stock of pre-reform situation in Indian power sector and identifies key concerns that led to initiation of the process of reform. The paper discusses major policy and regulatory changes undertaken since the early 1990s. The paper also illustrates changes in the market structure as we move along the reform process. It also discuss some of the major provisions of the recently enacted Electricity Act 2003 that aims to replace the prevailing acts which govern the functioning of the power sector in the country. In this context, it discuss two issues arising out of it, namely open access and multi-year tariff that we think would have a significant bearing on the performance of the sector in the near future. The paper also evaluates the reform process in the light of some of the regulatory changes undertaken. Finally, the paper briefly discusses the issues involved in introduction of competition in the power sector primarily through development of a market for bulk power.

Swain, Singh and Kumar (2004) ,describes there were many inhibitors to growth in power sector but the main problem in the growth was Government Policy, which made it difficult for a private player to enter. This further created the problem that Indian entrepreneurs didn’t have enough knowledge and experience in developing power projects. A whole new system was evolved where private players were invited to be an active participant. The system demanded financial, political and other major requirement in roads and communication. Some of the bold steps taken in the Act were moving generation and distribution out of ‘License Raj’, opening access to national grid and demolishing the ‘Single Buyer’ model. The failure of the large structure and the changing global scenario has forced Government to think of ways to revive this fundamental infrastructure sector. Two ways that government can count on for future growth of this sector are “Small Power Plants” and “Clean Development Mechanism”.

Soronow, Pierce & Wang(2003), introduces FEA's Power Sector Model as the next step in derivatives pricing. Here the authors identified weather and marginal fuel prices as independent variables driving load levels and power prices. This is grounded in the understanding that, to a large extent, weather dictates load conditions, which, together with the marginal fuel price, determines the power price. The second step is to conduct a detailed empirical study of the nature and relationships among the various components under analysis. The goal of the study is twofold: to understand the relationship between the variables, as well as to determine the seasonal aspects inherent in each component. The approach is capable of capturing the essential power price characteristics such as seasonality in price and volatility, mean-reversion, price spikes, volatility clustering, and regional correlations. The model is self-contained, and when fully calibrated, Monte Carlo simulation provides the basis for valuing power contracts and generation assets directly.

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Newbery (2005) says that Modern infrastructure, particularly electricity, telecom and roads, is critical to economic development. Electricity provides light, the ability to use modern equipment, computers and access to ICT. Telecom facilitate information exchange and access to the rest of the world, while transport infrastructure is critical for trade, and by lowering transport costs extends the market and increases competition. If there is a surplus of infrastructure, more investment adds little to total output, but if there is a deficit, then shortages constrain total output, magnifying the impact, so that the return to reducing that deficit can be very high indeed.

Tongia (2003), describes that India’s power sector is undergoing significant reforms, beginning in 1991, which are changing and diminishing the role of the government, which functioned earlier as the near monopoly integrated utility. Because of significant financial difficulties faced by the SEBs 1991 saw the enactment of legislation, the 1991 Electricity (Supply) Act, which opened up the sector to private participation, primarily in generation. The current thrust of reforms is on the distribution sector, reducing losses and increasing efficiency. This might just be a precursor to privatization, but there is a goal to full electrification by 2012. In the last few years, the T&D losses have stabilized somewhat, but there is only limited interest of private players into the sector, especially new players. Those who state that overall financial losses have increased after the reforms do not factor in the increase in costs due to generator price increases regardless of reforms, even from government generators and PSUs. Electricity Bill 2001 opens up the sector to private participation with limited approval obligations

Banerjee (2004) says that the earliest electric power systems were distributed generation (DG) systems intended to cater to the requirements of local areas. Subsequent technology developments driven by economies of scale resulted in the development of large centralized grids connecting up entire regions and countries. The design and operating philosophies of power systems have emerged with a focus on centralized generation. During the last decade, there has been renewed interest in DG. This paper reviews the different technological options available for DG, their current status and evaluates them based on the cost of generation and future potential. The relevance of these options for a developing country context is examined using data for India.

This report also gives us an in depth analysis of the most prominent prominent players in the Indian thermal power sector as well as shows the demand and supply gap that exists in India. It also shows as to how tariff is calculated and what parameters go into the evaluation of tariffs. It also an in depth review on the key financing and investment trends.

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Industry profile

Power sector in India

Power is an essential requirement for all facets of our life and has been recognized as a basic human need. It is the critical infrastructure on which the socio-economic development of the country depends. The growth of the economy and its global competitiveness hinges on the availability of reliable and quality power at competitive rates. The demand of power in India is enormous and is growing steadily. The vast Indian power market, today offers one of the highest growth opportunities for private developers.

India is endowed with a wealth of rich natural resources and sources of energy. Resources for power generation are unevenly dispersed across the country. This can be appropriately and optimally utilized to make available reliable supply of electricity to each and every household. Electricity is considered key driver for targeted 8 to 10% economic growth of India. Electricity supply at globally competitive rates would also make economic activity in the country competitive in the globalized environment.

The Power & Energy Infrastructure sector in India is poised for a major take-off. The APDRP (Accelerated Power Development & Reforms Programme 2002 - 2012) has seen an addition of around 22,000 MW during last five years. And during the next five years, a capacity addition of over 78,000 MW has to be setup by 2012. (A commitment of 15,600 MW capacity addition per annum). The Market Potential to sustain the GDP Growth rate of India @ 8% plus per annum needs the power sector to grow at 1.8 - 2 times the GDP rate of growth as espoused by economists, planners and industry experts. This would mean a YOY capacity addition of 18,000 - 20,000 MW to achieve this ambitious plan of moving India to a Developed Economy status, as an Economic Global Powerhouse. The Target Mission : ‘POWER for All by 2012’ would mean achieving the target of 1000 KwHr (Units) of per capita consumption of electricity by this period. To achieve this goal, following milestones are critical :-

• Attract US $ 250 Billion Investment into the sector. (FDI & Domestic Investment Combined)• Adequate Capacity Growth to Sustain GDP Growth at 8% plus.

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• Reliable & Quality Power On 24 x 7 basis, at least in Urban & Industrialized areas.• 100% Rural Electrification with Adequate & Qualitative Power   for irrigation purpose.• Increasing the Role of Hydel & Renewable Energy in the Energy Mix. • Urgent need to develop the alternatives, both    in the Fuel & Technology terms.• Focus on implementation (Outcomes are more important than Outlays)   - as espoused by the Indian Prime Minister, Dr. Manmohan Singh

For the current growth in the Indian economy to be sustained, country’s infrastructure needs to be improved. And electricity is the key to support this projected growth in the economy. However, over the years the demand in the power sector has outpaced the capacity addition. India’s energy requirement during 2008- 2009 was 774,324 million units (MU), while availability was 689,021 MU resulting in an energy shortage of 11 %.

To overcome this huge demand supply deficit the power sector is getting a continuous impetus from the government. Regulatory and structural changes have made it attractive for strategic and financial investors, and this is substantiated by the recent upswing in the Indian power market.

Regulatory changes

Thus, development in the power sector is indispensable to bridge the demand supply deficit and further country’s economic growth. To sustain the GDP growth of 8.0 %recorded in FY 2010, adequate power availability is essential. Government has set up steep targets for capacity addition during the 11th and 12th 5 yr plan and has facilitated this through essential investor friendly regulations in the power sector.

The Indian power sector has witnessed significant structural and regulatory changes to make it attractive for private investment. These include:-

1. 100% foreign direct investment allowed in all segments of the power sector including trading.2. Zero customs and excise duty waiver on capital equipment for MPP3. Income tax holiday for 10 years4. Unbundling and corporatization of the transmission & distribution business of SEBs

Sector performance in comparison to other sectors

These changes have made the power sector attractive for financial and strategic investors and have also been well received by the capital markets. The available in public domain gas formed the basis for capital market analysis presented herein. From a total of 17 IPO’s issued in 2009, around 67% were in the energy and power sector. Power sector IPO’s have been very well received by retail and institutional investors.

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Sector IPO proceeds

($Mn)

% of IPO proceeds

IPO volume % of IPO volume

Energy and Power 2352 67.5 3 17.60

Industrial 765 22.00 5 29.40Hospitality 197 5.70 2 11.80Telecom, media and technology

112 3.20 3 17.60

Consumer goods and retail

42 1.20 2 11.80

Outsourcing 11 0.30 1 5.90Education 5 0.20 1 5.90Total 3484 100.00 17 100.00

Attractive return on power sector stock- India vs Global

In terms of comparative return vis-à-vis global peers listed on stock exchanges overseas, power sector stocks in Indian capital market has yielded relatively higher returns as presented in the table below. This indicates the high growth expectation for power sector in India and encourages private

India (local currency)

NTPC 196 35,218 17.9 16.5 14.6

Tata power 1,238 6,303 15.7 12.7 11.5

Reliance power 152 7802 NM NM NM

JSW energy 127 4,480 14.2 8.8 10.7

Adani power 136 6,339 40.1 8.6 6.9

CESC 379 1,016 9.8 9.6 9.4

Mean 19.5 11.1 10.6

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CMP August 272010

Market cap( U.S.mn)

P/E(x)

CY10E/FY11E CY11E/FY12E CY12E/FY13E

Asia

Huaneng power 4 9,889 11.8 10.6 9.7

Glow energy 45 2,110 13.9 12.2 8.4

Datang intl. 3 10,555 17.1 13.1 10.1

Mean 14.2 11.9 9.06

U.S

Southern co. 36 30,222 15.0 14.3 13.4

Duke enegy 17 22,523 12.9 12.7 12.3

NRG 20 5,130 8.2 15.7 11.0

Exelon corp. 40 26,493 10.2 9.8 13.3

Mean 15.4 17.5 16.6

Europe

DRAX Group 4 914 6.6 8.1 8.9

Fortum 18 12,533 11.6 12.0 11.3

RWE 52 23,149 7.6 8.1 7.7

National grid 5 12,196 9.4 11.7 11.1

Mean 8.8 10.0 9.7

Source: www.indiastat.com

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CMP August 272010

Market cap( U.S.mn)

P/E(x)

CY10E/FY11E CY11E/FY12E CY12E/FY13E

Attractive exit option- appetite for power sector stocks

Power sector stocks in India have provided relatively better returns than the index stocks. This makes power sector stocks an attractive proposition for retail as well as institutional investors. Power sector stocks offering IPO in the last 2 years have been oversubscribed at the upper end of valuation range.

This highlights greater opportunity for a financial investor to get attractive returns from the Indian capital. Markets.

Trade Date Company Sector Size ($mn)

Price bottom range

Offering price vs

Price range

Price top range

20 Aug, 09 Adani power Energy & power 670 2.0 2.22 2.22

01 Sept, 09 NHPC Energy & power 1342 0.67 0.8 0.8

30 Oct, 09 Indiabulls power Energy & power 340 0.88 1.0 1.0

Availability of fuel is critical for reliable and cost-effective production of power. Coal and natural gas are two fuel sources that can help to meet the base demand. Coal being an abundant and a cheaper source offers a cost effective option of fuel for power generation.

Availability of coal in India

The coal reserves of india, up to depth of 1200mmeters, are estimated to be 267.21 billion tonnes by the geological survry of india. These reserves are primarily located in states of jharkand, Orissa, west Bengal,Madhya Pradesh etc.

Million tonnes Proved Indicated Inferred Total

Gondwana coal 105343 123380 37414 266137Tertiary coal 477 90 506 1073

Total 123470 37920 267210

Source: DRHP, coal India ltd

Coal mining in india is primarily entrusted to government companies which have produced more than 90% of the coal produced in india in FY 2009. The chart on the next page depicts the annual coal production in india in the last 10 years.

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Source: DRHP, coal India ltd

Coal production by cil has increased by approximately 8% per annum in the last 3 years primarily due to the operational efficiencies achieved in its existing mines.

To meet the fuel requirement for additional capacity generation, incremental production from new fields would be needed. However, the new mines are expected to have considerable gestation period before they are fully operational and due to this we can forsee a considerable shortfall.

Recognizing the growing requirement of coal for capacity addition plan of CEA and potential lag in supply from domestic sources, CIL has projected the following coal deficit ( as per coal linkage already awarded).

Source: DRHP, coal India ltd

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The above projected deficit may increase if more projects are awarded the coal linkage in the future. This supply deficit is being transferred to the power utilities and following are two potent examples of the same:

a) Coastal power projects to mandatorily arrange 30% of their requirement from imported coal.

b) For new long term coal linkages being awarded, CIL is committed to supply only 50% coal from domestic sources and balance 50% can be supplied from imported coal sources.

Coal imports in India

As per the current policy, coal can be imported freely under the open general license. In FY 2010, India imported about 67.74 million tonnes of coal which is 11.69 % of its total coal consumption. Coal imports are expected to grow since many domestic power utilities NTPC, PTC and coal mining public sector undertaking are vying for coal assets abroad to meet their fuel requirements for power projects. Recent reports indicate Indonesia and Australia being pitched as favourite destination.

Coal reserves and production in Indonesia

Coal mining is an important industry segment for the Indonesian economy.indonesia has substantial coal reserves totaling 21 billion tonnes and there has been considerabe growth in coal production due to the increase in export demand. Coal deposits are mainly concentrated in two regions- Kalimantan and Sumatra holding 43% and 56 % of the total reserves. The Indonesian coal industry has shown significant growth in production over the last 15 years primarily to meet the export demand from other south east Asian countries.

Source: statistical yearbook of Indonesia

In order to meet the coal deficit, india has been importing coal from Indonesia and the import at 21.2 million tonnes has shown an increase by 25.3 % in H1 201

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5 Major players in the thermal power sector and the projects under their operation

India’s largest power company, NTPC was set up in 1975 to accelerate power development in India. NTPC is emerging as a diversified power major with presence in the entire value chain of the power generation business. Apart from power generation, which is the mainstay of the company, NTPC has already ventured into consultancy, power trading, ash utilisation and coal mining. NTPC ranked 341st in the ‘2010, Forbes Global 2000’ ranking of the World’s biggest companies. NTPC became a Maharatna company in May, 2010, one of the only four companies to be awarded this status.

The total installed capacity of the company is 34,194 MW (including JVs) with 15 coal based and 7 gas based stations, located across the country. In addition under JVs, 5 stations are coal based & another station uses naptha/LNG as fuel.  The company has set a target to have an installed power generating capacity of 1,28,000 MW by the year 2032. The capacity will have a diversified fuel mix comprising 56% coal, 16% Gas, 11% Nuclear and 17% Renewable Energy Sources(RES) including hydro. By 2032, non fossil fuel based generation capacity shall make up nearly 28% of NTPC’s portfolio.

NTPC has been operating its plants at high efficiency levels. Although the company has 17.75% of the total national capacity, it contributes 27.40% of total power generation due to its focus on high efficiency.

Source: NTPC

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Installed Capacity

Be it the generating capacity or plant performance or operational efficiency, NTPC’s Installed Capacity and performance depicts the company’s outstanding performance across a number of parametres.

NTPC owned

No of plants Capacity (MW)

Coal based 15 26,875

Gas & liquid 7 3,995

Total 22 30,830

Owned by JV’S

Coal & gas 6 3,364

Total 28 34,194

Source: NTPC

Regional Spread of coal based thermal plants

Region Coal Northern 8,015Western 6,860Southern 4,100Eastern 7,900JV’s 1,428Total 28.299

Coal Based Power Stations

With 15 coal based power stations, NTPC is the largest thermal power generating company in the country. The company has a coal based installed capacity of 26,875 MW.

COAL BASED(Owned by NTPC)

STATECOMMISSIONEDCAPACITY(MW)

1. Singrauli Uttar Pradesh 2,0002. Korba Chhattisgarh 2,600

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3. Ramagundam Andhra Pradesh 2,6004. Farakka West Bengal 2,1005. Vindhyachal Madhya Pradesh 3,2606. Rihand Uttar Pradesh 2,0007. Kahalgaon Bihar 2,3408. NCTPP, Dadri Uttar Pradesh 1,8209. Talcher Kaniha Orissa 3,00010. Feroze Gandhi, Unchahar Uttar Pradesh 1,05011. Talcher Thermal Orissa 46012. Simhadri Andhra Pradesh 1,50013. Tanda Uttar Pradesh 44014. Badarpur Delhi 70515. Sipat-II Chhattisgarh 1,000Total 26,875

Source: NTPC

Operations

In terms of operations, NTPC has always been considerably above the national average. The availability factor for coal based power stations has increased from 89.32% in 1998-99 to 91.62% in 2010-11, which compares favourably with international standards. The PLF has increased from 76.6% in 1998-99 to 88.29% during the year 2010-11.

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Source: NTPC

The table below shows the detailed operational performance of coal based stations over the years

OPERATIONAL PERFORMANCE OF COAL BASED NTPC STATIONSGeneration(BU) PLF(%) Availability Factor(%)

2010-11 220.54 88.29 91.622009-10 218.84 90.81 91.762008-09 206.94 91.14 92.472007-08 200.86 92.24 92.122006-07 188.67 89.43 90.092005-06 170.88 87.52 89.912004-05 159.11 87.51 91.202003-04 149.16 84.40 88.792002-03 140.86 83.57 88.702001-02 133.20 81.11 89.092000-01 130.10 81.80 88.541999-00 118.70 80.39 90.061998-99 109.50 76.60 89.36

Source: NTPC

Turnaround Capability

NTPC has played an extremely important role in turning around sub-optimally performing stations. The phenomenal improvement in the performance of Talcher and Tanda by NTPC make them their big success stories.

Talcher (460 MW)

An even more challenging turnaround story was being scripted at the OSEB's old power plant at Talcher. Taken over in June 1995, the table indicates the dramatic gains in the performance of the power plant as a result of NTPC’s expertise.

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Source: NTPC

Tanda (440 MW)

Tanda Thermal Power Station was taken over by NTPC on the 15 January 2000.The PLF of the power station improved from 21.59% at the time of the takeover to 91.66% for the year 2007-08.

Source: NTPC

While NTPC bettered PPA commitments, from the viewpoint of capital requirements, turning around such old units is a low cost, high and quick return option. This unprecedented success helped the concerned SEBs and the entire nation in terms of economy and power availability.

Future Capacity Additions of coal based thermal power plants:NTPC has formulated a long term Corporate Plan upto 2032. In line with the Corporate Plan, the capacity addition under implementation stage is presented below:

Project State MWIndira Gandhi STPP- JV with IPGCL & HPGCL ( 3 x 500)

Haryana 1000

Sipat I (3 x 660) Chhattisgarh 1980Simhadri II Unit - IV( 500) Andhra Pradesh 500Vallur I -JV with TNEB ( 2 x 500) Tamilnadu 1000Vallur Stage-I Phase-II  -JV with TNEB ( 1 x 500)

Tamilnadu 500

Bongaigaon(3 x 250) Assam 750Mauda ( 2 x 500) Maharashta 1000

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Rihand III(2X500) Uttar Pradesh 1000Vindhyachal-IV (2X500) Madhya

Pradesh1000

Muzaffarpur Expansion (2x195) – JV with BSEB

Bihar 390

Nabinagar TPP-JV with Railways (4 x 250)

Bihar 1000

Barh II (2 X 660) Bihar 1320Barh I (3 X 660) Bihar 1980

Source: NTPC

SWOT analysis of NTPC

STRENGTH OF NTPC:

• The company has kept with itself sufficient liquid funds to meet any kind of cash requirement. • Efficient working capacity of plants

•A minimum risk factor.

•Best-integrated project management systems.

•Company with an excellent record and high profits.

•An early starter-more than 30 years experience in power sector.

•Highly motivated and dedicated workers and officers- no industrialrelations problem.

•Excellent growth prospects with significant additions, modifications andreplacements.

•Employee-friendly personnel policies.•Low project cost of NTPC’s plants.

WEAKNESSES OF NTPC:

•Depleting raw materials.

•Some of the Plant have become old and need investment in Renovation &Modernization.

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OPPURTUNITIES:

•Demand and supply gap.

•Upcoming hydro and nuclear sector.

•Huge opportunity in consultancy services.

Threats

•Rising prices of raw materials

•Huge competition from SEB’s, Reliance Energy, Tata power and otherPrivate Development.

•Coming up of other sources of power.

•Huge Capital requirement for expansion, diversification, horizontal &vertical integration and R & M.

Adani, a conglomerate with a formidable presence in multiple businesses across the globe, has entered the power sector to harbinger a ‘power full’ India, by generating 20,000 MW of power by 2020. Their comprehension of the criticality in meeting the power requirement and its crucial role in ensuring the energy security of India, spurs us to build India’s largest and one of the world’s top 5 single location thermal power plant in Mundra.

Along with thermal power generation, Adani power has made a paradigm shift by venturing into Solar power generation in Gujarat. It is Adani’s endeavour to empower one and all with clean, green power that is accessible and affordable for a faster and higher socio-economic development. We are achieving it with our out-of-the-box thinking, pioneering operational procedures, motivated team and a yen for trendsetting. Our enthusiasm and energy has earned us accomplishments that make us the FIRST, FASTEST AND LARGEST power company in many aspects.

Adani power has the Adani Power Limited has commissioned the first supercritical 660 MW unit in the country. Mundra is also the WORLD’S FIRST supercritical technology project to have received ‘CLEAN DEVELOPMENT MECHANISM (CDM) Project’ certification from United Nations Framework Convention on Climate Change (UNFCCC).

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FASTEST turnaround time of projects in the industry.

Poised to be the LARGEST private power generating company in India.

To ascertain a potent presence across the value chain within the industry, Adani has also forayed into power transmission. The first power transmission project of 400KV Double Circuit Transmission System from the Mundra plant to Dehgam (430 kms) has been realised with two more in the implementation stage. We are currently implementing nearly 1000 km long high voltage DC double circuit line connecting Mundra power station to Northern India. This will be commissioned by March 2011. This is the first private sector HVDC transmission project in the country ensuring free flow of power between Western India and the Northern Hinterland.

Coal based Thermal power projects under Adani group operations:-

Mundra Thermal Power Project

Location : Mundra, District Kutchh, Gujarat, IndiaCapacity :   4620 MW

Phase I - 2 x 330 MWPhase II - 2 x 330 MWPhase III - 2 x 660 MWPhase IV - 3 x 660 MW

Source: Adani power

The Mundra Thermal Power Project was conceived for the captive consumption of the Mundra Port & SEZ, thereafter the vision and the capabilities of the promoters shall make the Mundra Power project on completion, the largest single location Coal based Thermal Power Station in India and one of the top five in the World. With the synchronization of Unit 1, Adani Power Limited proved its project execution skills by developing Greenfield coastal power project in a short span of 33 months from the date of NTP.

At present all the four units of Phase I and Phase II based on subcritical technology have been commissioned and are Commercially Operational.

Adani Power created history by synchronizing the first-ever super-critical technology based 660 MW Unit (Unit 5 of Phase III) in India at Mundra. This is not only the first super-critical turbine in the country but what makes it special is that this has been synchronized within 36 months from the inception, which is the fastest implementation ever by any power developer in the country.

The entire project is scheduled to be fully operational within the XIth Five Year Plan (2007-2012).

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Further the project being at a coastal location shall use sea water with the implementation of a desalinization unit,

making efficient use of the water resources of India.

The Phase III of the Mundra Project, which is also based on supercritical technology, has received ‘Clean Development Mechanism (CDM) Project’ certification from United Nations Framework Convention on Climate Change (UNFCCC). This is the world’s first project based on super-critical technology to get registered as CDM Project under UNFCCC. This state-of-the-art supercritical technology is 25% more efficient than conventional sub-critical power plants and enables 20% reduction in CO2 emission.

Tiroda Thermal Power Project

Source: Adani power

The Tiroda Thermal Power Project of 3300 MW is being set up by Adani Power Maharashtra Ltd (APML), a subsidiary of Adani Power Limited. In line with their commitment to the environment all the units are based on supercritical technology. The construction activities are in full swing and the first three units of the project are planned to be commissioned within the XIth Five Year Plan (2007-2012) and the balance two units in the first year of the XIIth Five Year Plan (2012-2017).

With the completion of the Phase I and Phase II project Adani shall be making the largest capacity addition in the Indian power sector in the XIth five year plan (2007-2012) with a cumulative capacity of 6600 MW.

Kawai Thermal Power Project

Source: Adani power

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Location : Tiroda, District Gondia, Maharashtra, IndiaCapacity : 3300 MW

Phase I - 2 x 660 MWPhase II - 1 x 660 MWPhase III - 2 x 660 MW

Location Kawai, District Baran, Rajasthan, India Capacity 1320 MW

The Kawai Thermal Power Project of 1320 MW is being set up by Adani Power Rajasthan Limited, a subsidiary of Adani Power Limited. In line with our commitment to the environment all the units are based on supercritical technology. The state of Rajasthan shall be the beneficiary for the entire power generated from the project. We are prepared to commence construction activities at the project site and the project is planned to be commissioned in the first year of the XIIth Five Year Plan.

Upcoming thermal power plants

Pench Thermal Power Project

Source: Adani power

The Pench Thermal Power Project of 1320 MW is being set up by Adani Pench Power Limited, a subsidiary of Adani Power Limited. In line with our commitment to the environment all the units are based on supercritical technology. The project is in advanced stage of development and the project is planned to be commissioned in the second year of the XIIth Five Year Plan.

Dahej Thermal Power Project

Adani Power Dahej Limited a subsidiary of Adani Power Limited is implementing at a coastal location, near the port of Dahej, in the industrial district of Bharuch in Gujarat, a thermal power project with an aggregate capacity 2640 MW. The project is advanced stage of development.

Bhadreshwar Thermal Power Project

Kutchh Power Generation Limited a subsidiary of Adani Power Limited is implementing at a coastal location, near the port of Mundra, in district Kutchh in Gujarat, a thermal power project with an aggregate capacity 3300 MW. The project is advanced stage of development.

Adani power growth chart

Source: Adani power

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Location Chhindwara, District Chhindwara, Madhya Pradesh, India Capacity 1320 MW

SWOT Analysis of Adani power

Strengths

• Strong execution track record on the back of the huge success of Mundra Port• The diversified nature of the Adani Group (especially its presence in ports and coal trading) augurs well for Adani Power• Stellar operational efficiency (FY10 average PLF was 85%+ compared with India’s national average of 78%)• Minimal exposure to merchant power (23% compared with JSW’s 56%)

Weakness

• All of Adani’s power plants use Chinese equipment• Conflict of interest given that other promoter owned companies are also in power generation• Limited bargaining power vis a vis delays in coal supplies from Adani Enterprises as it is Adani Power’s holding company

Opportunities

• private sector (this is equivalent to 10x Adani’s installed capacity) and Adani Power will be a relatively strong contender for these UMPPs• Given group’s presence in coal mining and India’s rising coal imports, domestic coal mining offers a huge opportunity for Adani Enterprises This in turn will reduce• Adani Power’s coal cost as currently Adani Enterprises is the biggest supplier of coal to Adani Power

Threats

• The 5x increase in private sector generation capacity by FY13 could result in merchant power rates getting compressed.• The rising Maoist insurgency (with its greatest influence in states having the largest coal resources) could result in delays and higher costs.• The improving trend in T&D losses due to rising investment in T&D could result in the fading of India’s power deficit at a quicker pace than expected.

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Lanco Infratech Ltd is one of India’s top business conglomerates and among the fastest growing.

Lanco Infratech has subsidiaries and divisions across a synergistic span of verticals. These include Construction, Power, EPC, Infrastructure, Property Development, and Renewables.

Lanco Infratech’s projects, operational and underway, are spread across India.

A member of the UN Global Compact, Lanco Infratech is recognized for its Good Corporate Governance and Corporate Social Responsibility initiatives led by the Lanco Foundation.

A preferred employer, Lanco Infratech builds on a tradition and culture where trust comes first… and the credo is inspiring growth.

Power

LANCO has proven expertise in power generation from conventional and non-conventional sources of energy including gas, coal, biomass, hydro and wind. Lanco has operational and under execution projects amounting to over 11000MW.

Operational coal based thermal power Projects

Plants Capacity Fuel Location Cost(mn)

Lanco Power I & II 600 (2x300) Coal Chhattisgarh 1100

Lanco Anpara I* 600 Coal Uttar pradesh 1300

Udupi Power I & II 1200 Coal Karnataka 900

Total 2400

Coal based power Projects Under ConstructionPlants Capacity Fuel Location Lanco Power III & IV 1,320 Coal Chhattisgarh Lanco Anpara II 600 Coal Uttar pradesh Lanco Vidarbha Thermal 1,320 Coal Karnataka Total 3,240

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Source: Lanco group

FINANCIAL PROFILE

In FY10, LITL’s top-line grew by 34.6% year-on-year to Rs 82.6 bn, mainly on accountof growth in power and infrastructure sector, which led to increase in revenue fromboth business divisions. Operating margin improved by 400 basis points to 18.6% inFY10, against 14.6% in FY09, due to decrease in operating expenses as a percentageof sales.PAT increased to Rs 5.3 bn in FY10, from Rs 3.6 bn in FY09, mainly due to improvedoperating profit and credit entitlement from minimum alternate tax of Rs 603.72 mnduring the year.

SWOT analysis of Lanco PowerStrengths

Cost advantage High R&D Market share leadership Strong management team Strong brand equity Strong financial position

Weaknesses Diseconomies to scale Over leveraged fiancial position

Opportunities Financial markets (raise money through debt, etc) Emerging markets and expansion abroad Innovation

Threats Competition Economic slowdown External changes (government, politics, taxes, etc)

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Considering India's diverse energy needs and anticipating the high demand of the future, GVK has established a significant presence in the energy sector. The diverse portfolio in the energy sector covers conventional and non-conventional energy resources. The current portfolio has gas, hydro and thermal energy projects. Recognizing Oil and Gas as potential growth segment, GVK is also creating presence in this area.

GVK's energy portfolio currently features six power projects which are being developed across several states in the country. Currently power projects are present in the states of Andhra Pradesh, Jammu Kashmir, Punjab and Uttarakhand. Together, these power projects are set to exceed over 5,000 MW capacity.

GVK is proud of establishing India's first independent power plant at Jegurupadu, Andhra Pradesh. This extraordinary project has won many accolades for its environmental initiatives. It uses state of the art technology that minimizes impact on the environment. Leveraging the company's skills and extensive experience, GVK addresses the consistently growing energy requirements of the country.

Gvk’s thermal power projects

GVK Power Goindwal Sahib LtdPROJECT OVERVIEW

Capacity 540 MW Coal Fired Thermal Plant

Commissioning Date FY 2013 (Expected)

Project Cost ` 29,638.1 Mn (Approved by PSERC)

PPA Agreement 25 Years with PSEB

Financial Closure Achieved on 1st Feb 2010

Tariff Structure As per CERC norms

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Source: GVK

Highlights

1,075 acres of land acquired at a cost of ` 1,677.5 Mn Compound wall construction, site grading work and approach roads work completed Work in progress at Boiler area, ESP area, Power House Building, TG Foundation and

Coal Handling Area BTG contract awarded to BHEL and BOP contract awarded to Punj Lloyd Coal to be sourced from captive mines (Tokisud & Seregarha) in Jharkhand Coal Transportation Agreement signed with Indian Railways

GVK Coal (Tokisud) & Seregarha Mines

PROJECT OVERVIEW

Geological Reserves

66.7 Mn Tonnes

Project Cost `

2914 Mn

Location

Latehar , Jharkhand

Coal Supply

1 million tonnes per annum toGoindwal Sahib thermal power plant

Coal Pricing Structure To be finalized

Source: GVK

HighlightsKISUD HIGHLIGHTS• Financial Closure achieved on 27th April 2010• Environmental Clearance granted by MoEF• Forest Clearance granted by MoEF• Mining Lease executed with Govt. of Jharkhand on 5th Aug 2010• Entire 926 acres acquired for compensatory afforestation

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PROJECT OVERVIEW

Mineable Reserves

52 Mn Tonnes

Project Cost `

2948 Mn

Location

Hazaribagh, Jharkhand

Coal Supply

2 million tonnes per annum toGoindwal Sahib thermal power plant

Coal Pricing Structure Coal India Ltd rates minus gradediscount

Source: GVK

SEREGARHA HIGHLIGHTS

• Jointly allocated with Arcelor-Mittal; GVKPIL’s share is 45%• Prospecting License has been applied for• ` 5 Mn paid to Central Coalfields Ltd towards compensationfor transfer of Mineral Rights

SWOT analysis of GVK Power

Strengths

• Stellar operational efficiency (FY10 average PLF was 85%+ compared with India’s national average of 78%)• Minimal exposure to merchant power (23% compared with Lanco’s 56%)

Weaknesses

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• Conflict of interest given that other promoter owned companies are also in power generation• Limited bargaining power vis a vis delays in coal supplies from GVK Enterprises

Oppurtunities

• Given group’s presence in coal mining and India’s rising coal imports, domestic coal mining offers a huge opportunity for GVK power

Threats

• The 5x increase in private sector generation capacity by FY13 could result in merchant power rates getting compressed.• The rising Maoist insurgency (with its greatest influence in states having the largest coal resources) could result in delays and higher costs.

Jindal Power Limited

Jindal Power Limited (JPL), a company promoted by Jindal Steel & Power Ltd. (JSPL), has been contributing significantly to the growing needs of power in the country.

JPL has set up India’s first mega power project in the private sector at Tamnar, Raigarh, Chhattisgarh. The company has invested approx. Rs. 4310 crore for setting up a 1000 MW thermal power plant which commenced commercial operation of the 1st unit in December 2007 and all four units (250 MW each) within a short span of nine months.

The fuel supply of the plant is met through its captive coal mines. About 6.9 km conveyer pipeline has been set up for transportation of coal between the mines and the plant. The company has constructed a 258 km, 400 KV Double Circuit transmission line from the plant to the PGCIL sub-station at Raipur through which power can be sold anywhere in India. 25 kms away from the project-site, an 18 m high dam over the river Kurket has been built, to meet the plant's water requirements.

Jindal Power Limited plans to add a 2400 MW Thermal Power plant to the existing capacity of the 1000 MW thermal power plant at Tamnar at an estimated cost of Rs 13,410 crore. The company has already placed an order with Bharat Heavy Electricals Limited (BHEL) for supply, erection and commissioning of 4X600 MW Boiler Turbine Generation (BTG) package. The existing 1000 MW power plant was set up with four Turbine Generators of 250 MW each, also supplied by BHEL.

JPL has also signed a MoU with the State Government of Jharkhand to set up a 2640 MW thermal power plant.

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Transmission line

Jindal Power Limited has established a 258 km, 400 KV Double Circuit transmission line from Raigarh to the PGCIL sub-station at Raipur.

Highlights  

Total length: 258.251 km Total towers: 701 nos. Forest: 5.920 hectares at village Rabo (Raigarh) 400 KV crossing: 5 nos. (PGCIL) 220 KV crossing: 6 nos. (4 CSEB+1 PGCIL) 132 KV crossing: 3 nos. (CSEB) Railway crossing: 2 nos. (SECR) River crossing:  3 nos. (Mand, Asdeo, Sheonath)

Financial Performance of JPL at a GlanceParticulars

Forthe Qtrs.

NetSales

Profit AfterTax

(PAT)

UnitGeneration

(MU)

PLF

Year 2010-11

3337.73 2001.60 8598 98%

4th Qtr. 2010-11

827.99 495.54 2178 101%

3rd Qtr. 2010-11

796.56 487.08 2238 101%

2nd Qtr. 2010-11

785.58 459.00 1972 89%

1st Qtr. 2010- 11

927.60 559.98 2210 101%

Year 2009-10

3921.90 2318.76 8148 93%

4th Qtr. 2009-10

851.96 521.37 2086 97%

3rd Qtr. 2009-10

965.33 582.39 2120 96%

2nd Qtr. 2009-10

891.08 514.71 1851 84%

1st Qtr. 1213.53 700.29 2091 96%

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2009-10 Year 2008-09

3257.48 1581.93 6368 79%

Source: Jindal power

SWOT analysis of Jindal power

Strengths

The company has kept with itself sufficient liquid funds to meet any kind of cash requirement.

Efficient working capacity of plants

A minimum risk factor.

Weaknesses

Depleting raw materials.

•Some of the Plant have become old and need investment in Renovation &Modernization.

OPPURTUNITIES:

•Demand and supply gap.

•Upcoming hydro and nuclear sector.

•Huge opportunity in consultancy services.

Threats

•Rising prices of raw materials

•Huge competition from SEB’s, Reliance Energy, Tata power and otherPrivate Development.

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Chapter 4

Company Profile

Universal Crescent Power Private Limited (UCPPL) is a subsidiary of diversified multinational business group, Universal Success Enterprise Limited (USEL), founded by eminent NRI business man, Mr. Prasoon Mukherjee. Spearheaded by a highly experienced management team and a rapidly growing workforce of talented power sector professionals, the company aims to develop 10,000MW of power plant capacity in next 10 years to help meet India’s rapidly growing power requirement.

Currently the company is developing two imported-coal based thermal power plants named ‘Saurashtra Super Thermal Power Plant’ (3960 MW) in Gujarat and ‘Sagar Super Thermal Power Plant’ (1980 MW) in West Bengal. The power plants will be constructed with state of the art, highly efficient supercritical technology and will employ stringent environmental standards to greatly limit effluents and emissions. Both the projects shall have their own dedicated Captive Coal Jetties to receive, unload and transfer the imported coal to power plant sites.

Development of the power projects is proceeding at a rapid pace and the company expects Stage-I of Sagar STPP and Saurashtra STPP to start commercial operation in the year 2015.

For Sagar STPP, which is coming up on Nayachar Island, Purba Medinipur district near Haldia in West Bengal, land has been alloted, EPC specifications have been prepared, Terms of References (ToR) for Environment Clearance has already been approved by Ministry of Environment and Forests (MoEF), fuel supply and power off take agreements have been signed and financial closure is at an advance stage.

For Saurashtra STPP, which is coming up at Bhatvadia Village, Jamnagar district in Gujarat, land acquisition is under final stages, a Detailed Project Report (DPR) has been prepared, Terms of References (ToR) for Environment Clearance has already been approved by MoEF and signing of fuel supply and power off take agreements are underway.

Guided by deeply rooted principles of dedication to technical and commercial excellence, strong corporate governance and environmental sustainability, the company aims to help materialize the ambition of reliable power for all.

Proposed projects

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Saurashtra Super Thermal Power Project, Gujarat

he company has signed an MoU for 10,000MW with the Government of Gujarat during the “Vibrant Gujarat investor Summit” held in January 2009. In line with the MoU, Universal Crescent Power is developing 3960 MW coal fired Saurashtra Super Thermal Power Project in the state.

The project is coming up at Bhatvadia village in Jamnagar district and will be developed in three stages with each stage having two units of 660MW.

The power station will employ high efficiency, supercritical units and will adhere to strict environmental protection standards. Coal of low ash will be imported from the leading coal suppliers on large cape size ships and shall be unloaded on a captive jetty which will be constructed in Gojiness village, located on the coast, 8km from the power plant site. A cross country conveyor belt will bring the coal to the power plant site from the captive jetty.

Power from the station will be evacuated through a 400kV transmission line which will connect to a substation at Rajkot. Power from the project will be sold directly to the merchant market and through a combination of long term MoUs with state governments and sale agreements with reputed power traders.

Sagar Super Thermal Power Project, West Bengal

The company has signed an MOU with the Government of West Bengal for setting up 10,000MW thermal power plants at various locations in the state of West Bengal. In line with the MoU, Universal Crescent Power is developing a 1980 MW coal fired Sagar Super Thermal Power Project in the state. The project is coming up on Nayachar Island near Haldia district and is being developed in two stages – Stage-I: 2×660 MW and Stage-II: 1×660 MW.

The power station will employ high efficiency, supercritical units and will adhere to strict environmental protection standards. Low ash coal will be imported from leading coal suppliers and unloaded at captive coal jetty which shall be constructed at Nayachar Island near power plant site and transferred to the power plant through belt conveyers.

Power from the station will be evacuated to Kharagpur 400 KV substation located 100 Km from the project site. This substation is connected to West Bengal State Electricity Transmission Corporation Limited (WBSETCL). The last mile connectivity for power evacuation will be developed by WBSETCL as West Bengal State Electricity Development Corporation Limited (WBSEDCL) will buy the power at plant bus. A Power Purchase Agreement (PPA) with WBSEDCL for supply of 85% of Stage-I (2×660 MW) power has already been signed. The rest of the 15% will be sold to the merchant market. Roadmap for UCPPL viz a viz project Implementation plan

Location Capacity Project Phases

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West Bengal - 3 × 660 MW Sagar super thermal Stage 1: 2 × 660 MW Nayanchar island Power project Stage 2: 1 × 660 MWHaldia

Gujarat – 6 × 660 MW Saurashtra Stage 1: 2 × 660 MWBhatwadia village Super thermal Stage 2: 2 × 660 MW

Jamnagar Power project Stage 3: 2 × 660 MW Construction and commissioning strategy

UCPPL envisages implementing the first 2640 MW, 1320 MW project in west Bengal( sagar state 1) and Gujarat ( saurashtra stage-1) each, on lump su turn key basis by engaging an EPC contractor. The envisaged mode of implementation would entail following benefits:

EPC contractor would be responsible for integrated development, commissioning and performance test of the plant thus ensuring single point responsibility for commissioning and performance thereafter.

Award of EPC work on LSTK will protect UCPPL against any increase in the project capital cost.

EPC contractor will be engaged on international competitive bidding (ICB) basis which would ensure a competitive price for UCPPL project

Would provide time to UCPPL to build its in- house capability for implementation of future projects on a package basis.

The implementation of these projects would be monitored by in- house technical team of UCPPL.

For the subsequent 3300 MW units, UCPPL project team would handle the integrated development of plant by constructing and installing various packages for the plant procured from the vendors. UCPPL has elaborate manpower recruitment and capability development plan to achieve the same.

Snapshot of implementation strategy

Phases Implementation philosophySagar stage-I LSTK EPC basis- on a fixed cost basis

Integration managed by LSTK contractor LSTK contractor selected through ICB bidding

route Monitoring by in- house team of UCPPL

Saurashtra stage- I

Sagar stage - ‖ Pant packages will be procured and the plant

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would be constructed by integrating these packages by the project team of UCPPL.

Saurashtra stage- ‖

Saurashtra stage- III

Source: UCPPL

Project operation and maintenance philosophy

UCPPL would develop an experienced in house team to carry out operations and maintenance of the plants after taking over the plant from the EPC contractor after commissioning. UCPPL plans to develop the team by recruiting experienced manpower for key positions and also train the team by utilizing EPC contractor’s facility for training of its manpower.

Manpower – planning and recruitment

UCPPL’s manpower recruitment and development plan is synchronized to the project development activities. Key technical and commercial positions will be filled up by experience

Area For two projects under execution

By mar 2011 By march 2012 By march 2013A. At head quarter and regional office:

Engineering + IT +QA and I 15 40 80

HR + Admin. 3 8 8

Contracts 3 5 5

Finance 4 8 10

Planning + project 13 25 35 management

Documentation 2 4 4

B. At site for construction supervision: Civil + QA + HR+ 8 30 30 Admin. + finance + planning

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Mechanical + electrical + C&I + QA 3 30 60

Total manpower for two 51 150 262 Phases

Source: UCPPL

As per the detailed project report prepared for Sagar Stage-I and saurashtra stage-I and further rationalization by the company based on their ongoing discussions with various EPC contractors, the capital cost of project is estimated to be $1.33 Mn/MW. Accordingly, the estimated capital cost for project and its units are:

Stages Project capacity- MW Capital cost- CroresSagar stage-I 1,320 1760Sagar stage-II 660 880Saurashtra stage-I 1,320 1760Saurashtra stage-II 1,320 1760Saurashtra stage- III 1,320 1760Total 5,940 7920

Source: UCPPL

Potential for UCPPL in Gujarat and west Bengal

Before discussing on why UCPPLL has chosen these states as a destination, I would like to discuss the power scenario in both states as well as look at the current demand & supply scenario and future energy requirements in these states

As mentioned earlier UCPPL has drawn up firm plans to develop a total of 5940 coal- based thermal power generation capacity in two locations with 1980 MW capacity to be set up in West Bengal and 3960 MW in Gujarat.

Location advantages

Gujarat offers wider optionfor sale of power to the power- deficit markets in western, northern and southern regions of the country at optimum transmission cost for interregional transmission.

West Bengal offers support through power purchase at normative tariff as the state has not added any new generation capacity in the recent past creating potential power deficit in the near future.

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Other advantages include:

1.Logistical advantage in transporting imported coal- captive jetty planned at both locations2. Availability of adequate land with minimal R&R issues/cost.3. Coastal location also offers abundant sea water desalination.4. Power evacuation through existing substation or last mile connectivity by power grid corporation of india ltd. With no additional cost to the project account.

Chapter 5

Objectives

A) To understand the Indian Power sector

I. Current scenario of thermal power projects

• This Covers the performance analysis of 413 coal / lignite based thermal units above 25 MW capacity of 104 thermal power stations aggregating 80439.5 MW.

• Considering increased role of private sector projects in the power generation, 11 units of 5 thermal power stations of Independent Power Producers (IPPs) aggregating to 1870 MW have been covered in this review.

• All India electricity generation in the country during 2009-10 has been 771.6 BUrepresenting a growth rate of 6.6%.

• Thermal Generation stood at 640.9 BU representing a growth rate of 8.6%.

• Achievement in thermal generation in the country during 2009-10 was 98.83% ofthe target of 648.5 BU.

• Major reasons for shortfall in thermal generation vis-à-vis targets have been inadequate availability of coal; delay in commissioning / commercial operation of new generating units & long duration of forced outage of some of the existing thermal units.

• Thermal power Stations have achieved PLF of 77.68% at the National level which Is higher than 77.22% achieved during previous year. Had there been no loss of generation due to coal shortages, the PLF would have been 80.09%.

• Thermal stations of Central, State and Private sector Utilities and Private Sector IPPs achieved the PLF of 85.64%, 71.13%, 82.41% and 85.68% respectively.

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• 490-500 MW unit capacity group achieved the highest PLF of 87.21% among different capacity groups.

• BHEL/BHEL make units (277 units aggregating to 62147.0 MW) have registered the highest PLF of 80.39% among units of different make.

• Dahanu Thermal Power Station (2X250 MW) of M/s Reliance Infrastructure Ltd. in Maharashtra achieved the highest ever PLF of 102.33 %.

• PLF of 21 thermal power Stations aggregating to 25247.5 MW is above 90%. Among these 11 were from Central Sector Utility (NTPC), 5 were from Pvt. Utilities (Two from Torr. Power and one each from Reliance Infra, CESC and JSPL) and 5 were from State Sector Utilities (PSEB- 3, APGENCO-2)

• PLF of 19 Thermal units aggregating to 6005 MW is 100% or more. Further, PLF of 70 thermal power units aggregating to 19255 MW is 90% or more.• An all time high overall Operating Availability of 85.10% has been achieved as against 85.05% achieved during 2008-09.

• 36 Thermal stations achieved the Operating Availability more than 90% during 2009-10.

• 15 thermal generating units have achieved plant operating availability more than 99% during 2009-10.

• Energy loss on account of planned maintenance was 6.05% as compared to 5.66% during 2008-09.

• The average duration of boiler overhaul and capital maintenance was achievedcas 28 days and 62 days respectively.

• Average duration of boiler overhaul in private sector was lowest (21 days).

• The loss of generation due to non-availability of thermal units due to forcedcoutages during 2009-10 reduced to 8.85% as compared to 9.29 % during 2008-09.

• Main cause of forced outage was due to various boiler problems.

• 63.78% of the total forced shut down were of duration up to 24 hours. 35.03% outages were of duration varying from 1 to 25 days and only 1.19% of shut downs were for more than 25 days.

• Generation loss of 14.5 BU was reported due to coal shortage by the power utilities during 2009-10.

• The gas based generation registered a remarkable improvement during the year 2009-10 mainly on account of availability of gas from KG Basin and recorded a growth rate 32.56%.

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• Energy loss due to Partial availability of the generating units during 2009-10 was 8.03% as compared with 8.48% during 2008-09.

• Energy losses due to partial unavailability was above national average in the Western & Eastern Regions mainly due to shortage of coal, coal handling problems & poor quality / wet coal & other miscellaneous problems and was minimum in the Southern Region.

• Energy loss due to Low system demand & grid constraints during 2009-10 increased from 0.50% during 2008-09 to 0.88%.

• Loss of generation due to planned maintenance of units was maximum (6105.93 MU) during August'09 while loss of generation due to forced outages of units was maximum (6036.88 MU) during October'09

• 7 Nos. coal/lignite based thermal generating units (5 of NTPC, and one each of Tata PCL & TNEB) continuously have been operating for more than 300 days while 17 coal/ lignite based thermal generating units (13 of NTPC and one each of GSECL, MAHAGENCO, Tata PCL & TNEB) have been operating continuously for morethan 250 days.

• Among 500 capacity group, Trombay TPS #5 of TATA PCL had continuously operated for more than 300 days.

• All India Specific coal consumption of thermal units at National level reduced from 0.74 kg/kWh to 0.72 kg/kWh.

• Auxiliary power consumption of thermal units at National level marginally increased from 8.33% to 8.34% mainly due to high auxiliary consumption by newly commissioned lignite based unit at Giral TPS, Jalippa Kapurdi & Surat Lignite.

ALL INDIA REGIONWISE GENERATING INSTALLED CAPACITY (MW) OFPOWER UTILITIES INCLUDING ALLOCATED SHARES IN JOINT AND CENTRALSECTOR UTILITIES

S no. Region Coal Gas DSL Total 1 Northern 24232.50 504134.76 12.99 28380.252 Western 31430.50 7903.81 17.48 39351.793 Southern 20482.5 4690.78 939.32 26112.604 Eastern 18747.88 190.00 17.20 18955.085 N. Eastern 60.00 787.00 142.74 989.74

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6 Islands 0.00 0.00 70.02 70.027 All India 94953.38 17706.35 1199.75 113859.48

Source: UCPPL

II. Regulations and power industry structure

Institutional Framework

The Ministry of Power is primarily responsible for the development of the Indian power sector.It is concerned with perspective planning and policy formulation in the sector.

The State Electricity Boards (SEBs) generate, transmit and distribute electricity in coordinationwith private/centrally owned generating companies or any other relevant agency.

The Central Electricity Authority (CEA) is a body constituted under the Electricity Supply Act,which is responsible for developing a sound, adequate, and uniform policy for the control andutilisation of national power resources. It is also responsible for the techno-economic appraisalof the project reports for the proposed power plants, including those in the private sector.Subsequent to enactment of the Legislation on establishment of a regulatory authority, aninstitution called the Central Electricity Regulatory Commission (CERC) has been set up forrationalisation of bulk and retail tariff for generation and transmission utilities involved in interstate operations. It also regulates at intra-state level. Each state has set up a State ElectricityRegulatory Commission.

The Electricity Act 2003

The Electricity Act 2003 has been enacted by the Parliament in June, 2003. The salient positivefeatures of this legislation are:• Removal of a number of restrictive barriers to the flow of power in a competitive market scenario by opening access to transmission (from the outset) and distribution.

• Freeing up of generation and captive power plants from licenses and technoeconomicapprovals.• The recognition to trading as a distinct activity that would help ushering in a market

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environment.• The formation of an expert Appellate Tribunal to hear appeals against State andCentral Electricity Regulatory Commission orders.• Transferring the full range of regulatory and licensing functions to the Central andState Regulatory Commissions.• Deregulating tariffs in certain situations e.g. in case of agreements between consumersand generating companies.• The distancing of Government from the functioning of the sector after giving broaddirections via the National Electricity Policy and the National Tariff Policy.• The conversion of the remaining State Electricity Boards into State TransmissionUtilities and deemed licensees with the freedom (but not compulsion) to restructureand progress down the road to corporatisation and privatization.• The Energy Conservation Act, 2001 has been enacted and consequently Bureau ofEnergy Efficiency (BEE) has already been set up.

Reforms So Far

• 26 states have signed Memorandum of Understanding (MoU) with the Governmentof India to undertake reforms.• 20 states have constituted State Electricity Regulatory Commissions and arefunctional. Tripura and Jharkhand have notified the constitution of SERC.• 18 State Electricity Regulatory Commissions have issued tariff orders.• 11 States have unbundled/corporatised.• State of Orissa and Delhi have privatised distribution of electricity.

Power structure

India's power market is the fifth largest in the world. The power sector is high on India's priority as it offers tremendous potential for investing companies based on the sheer size of the market and the returns available on investment capital.

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Source: CEA

Almost 55 per cent of this capacity is based on coal, about 10 per cent on gas, 26 per cent on hydro, approximately 5 per cent on renewable sources, about 3 per cent on nuclear and 1 per cent on diesel. In the past five years, there has been a much greater emphasis on transmission and distribution reforms. The government aims to provide "power to all" by 2012. To achieve that promise, it will have to add as much as 1,00,000 MW of generation capacity, cut AT&C losses substantially to below 20 per cent, rationalize tariffs and ensure that average revenue realization is greater than the cost of production. It will have to continue to push the process of reform and restructuring and ensure greater private participation, in every segment.

In the past few years, there has been considerable growth in power plants based on renewablesources of energy. The Plant Load Factor (PLF) of generating plants has improved consistently over the last 10 years. The share of thermal power as a proportion of total power generated has decreased from 71 per cent to 66.3 per cent in the last decade. The share of hydro has increased to 26 per cent from 25.7 per cent.

Of the fossil fuel supplies, there is delivery constraint with respect to gas. A number of gas plantstoday are running at sub-optimal plant load factor (PLF) levels due to shortages. The governmenthas decided not to embark on new projects that rely on gas. It is feared that supply shortages candisturb the capacity addition plans, reduce PLFs, as the rising crude prices have led to firmer naphtha and natural gas prices.

Emerging environmental concerns have led to an increasing interest in renewables.Captive power plants (CPPs) also make a major contribution, which is more than one-fifth of thetotal installed capacity. In the last three years, captive capacity has grown at an average of 1,600 MW per year. The introduction of ABTs (Availability Based Tariffs) has changed the thinking of discoms.

They have to pay huge prices as they have to source power from the grid during low frequencyperiods. During this time the CPP power comes in handy at a much lower tariff. The reform process in the power sector continues. Thirteen states have unbundled SEBs into separate entities

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for transmission, distribution and generation. Two states have privatized distribution. Regulatory authorities have been set up in 24 states. These authorities are applying commercial principles to tariff setting, monitoring the performance of state utilities and paying attention to areas such as demand side management and grid discipline.

FUTURE PLANS OF CAPACITY ADDITION

Plan for Capacity Addition during XIth Five Year Plan (2007-2012)

The power generation capacity added during the last five years is a lowly 21,280 Mw, which is about half the original target of 41,110 MW set for the Tenth Plan. This is also 2000 Mw less than the 23,250 Mw capacity addition projected by the government in last few days of Xth five year plan. (March 2007).An ambitious target of 78,577 Mw has been set by the government for the eleventh plan period(2007 -2012). Of this, the hydropower’s share would be 16,553 MW, the thermal power wouldconstitute 58,644 MW and the nuclear power’s share would be 3,380 MW. Capacity addition plan from different sources during XIth five year plan (2007-2012).

Source: CEA

III. Electricity generation, transmission & distribution

Generation

India has the fifth largest generation capacity in the world with an installed capacity of 152 GW as on 30 September 20091, which is about 4 percent of global power generation. The top four countries, viz., US, Japan, China and Russia together consume about 49 percent of the totalpower generated globally. The average per capita consumption of electricity in India is estimated to be 704 kWh during 2008-09. However, this is fairly low when compared to that of some of the developed and emerging nations such US (~15,000 kWh) and China (~1,800 kWh). The world average stands at 2,300 kWh2. The Indian government has set ambitious goals in the 11th plan for power sector owing to which the power sector is poised for significant expansion. In order to provide availability of over 1000 units of per capita electricity by year 2012, it has been estimated that need-based capacity addition of more than 100,000 MW would be required. This

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has resulted in massive addition plans being proposed in the sub-sectors of Generation Transmission and Distribution.

Source: www.powermin.nic

The annual growth in power generation during 11th Plan period is as under:

11th Plan Growth in Achievement(%)2007-08 6.32008-09 2.72009-10 6.62010-11 5.56

www.powermin.nic

The growth in electricity generation during 2008-09 was constrained due to delay in commissioning of new units during 2008-09, long outages, shortage of coal/gas/nuclear fuel, poor hydrology, etc

Transmission

Transmission of electricity is defined as bulk transfer of power over a long distance at a high voltage, generally of 132 KV and above. In India bulk transmission has increased from 3708 ckm in 1950 to more than 265,000 ckm today. The entire country has been divided into five regions for transmission systems, namely Northern Region, North Eastern Region, Eastern Region, Southern Region and Western Region. The interconnected transmission system within each region is also called the regional grid.

The Government of India has an ambitious mission of ‘POWER FOR ALL BY 2012’. This mission would require that our installed generation capacity should be at least 2, 00,000 MW by 2012 from the present level of 1, 14,000 MW. To be able to reach this power to the entire

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country an expansion of the regional transmission network and inter regional capacity to transmit power would be essential. The latter is required because resources are unevenly distributed in the country and power needs to be carried great distances to areas where load centres exist.

The transmission system planning in the country, in the past, had traditionally been linked to generation projects as part of the evacuation system. Ability of the power system to safely withstand a contingency without generation rescheduling or load-shedding was the main criteria for planning the transmission system. However, due to various reasons such as spatial development of load in the network, non-commissioning of load centre generating units originally planned and deficit in reactive compensation, certain pockets in the power system could not safely operate even under normal conditions. This had necessitated backing down of generation and operating at a lower load generation balance in the past. Transmission planning has therefore moved away from the earlier generation evacuation system planning to integrated system planning.

While the predominant technology for electricity transmission and distribution has been Alternating Current (AC) technology, High Voltage Direct Current (HVDC) technology has also been used for interconnection of all regional grids across the country and for bulk transmission of power over long distances.

Certain provisions in the Electricity Act 2003 such as open access to the transmission and distribution network, recognition of power trading as a distinct activity, the liberal definition of a captive generating plant and provision for supply in rural areas are expected to introduce and encourage competition in the electricity sector. It is expected that all the above measures on the generation, transmission and distribution front would result in formation of a robust electricity grid in the country.

Distribution

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Due to lack of adequate investment on T&D works, the T&D losses have been consistently on higher side, and reached to the level of 32.86% in the year 2000-01.The reduction of these losses was essential to bring economic viability to the State Utilities.

As the T&D loss was not able to capture all the losses in the net work, concept of Aggregate Technical and Commercial (AT&C) loss was introduced. AT&C loss captures technical as well as commercial losses in the network and is a true indicator of total losses in the system.

High technical losses in the system are primarily due to inadequate investments over the years for system improvement works, which has resulted in unplanned extensions of the distribution lines, overloading of the system elements like transformers and conductors, and lack of adequate reactive power support.

The commercial losses are mainly due to low metering efficiency, theft & pilferages. This may be eliminated by improving metering efficiency, proper energy accounting & auditing and improved billing & collection efficiency. Fixing of accountability of the personnel / feeder managers may help considerably in reduction of AT&C loss.

With the initiative of the Government of India and of the States, the Accelerated Power Development & Reform Programme (APDRP) was launched in 2001, for the strengthening of Sub � Transmission and Distribution network and reduction in AT&C losses.

The main objective of the programme was to bring Aggregate Technical & Commercial (AT&C) losses below 15% in five years in urban and in high-density areas. The programme, along with other initiatives of the Government of India and of the States, has led to reduction in the overall AT&C loss from 38.86% in 2001-02 to 34.54% in 2005-06. The commercial loss of the State Power Utilities reduced significantly during this period from Rs. 29331 Crore to Rs. 19546 Crore. The loss as percentage of turnover was reduced from 33% in 2000-01 to 16.60% in 2005-06.

The APDRP programme has been restructured by the Government of India, in order that reliable and verifiable baseline data of revenue and enegry in APDRP Project areas is attained over an IT plateform and that AT& C loss reduction is achieved on a sustained basis. The Restructured APDRP (R-APDRP) was launched by MoP, Gol in July 2008 as a central sector scheme for XI

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plan. The scheme comprises of two parts-Part-A & Part-B, Part-A of the scheme being dedicated to establishment of IT enabled system for achieving reliable & verifiable baseline data system in all towns with population greater than 30,000 as per 2001 census (10,000 for Special Category Status). Installation of SCADA/DMS for towns with population greater than 4 lakhs & annual input energy greater than 350MU is also envisaged under Part-A. 100% loan is provided under R-APDRP for Part-A projects & shall be converted to grant on completion and verification of same by Third Party independent evaluating agencies (TPIEA) being appointed by MoP. MoP, Gol has earmarked Rs. 10,000 Crores for R-APDRP Part-A.

Part-B of the scheme deals with regular Sub Transmission & Distribution system strengthening & upgradation projects.The focus for Part-B is on AT&C loss reduction on sustainable basis.25% loan is provided under Part-B projects and upto 50% of scheme cost is convertible to grant depending on extent of maintaining AT&C loss level at 15% level for five years. For special category states, 90% loan is provided by GOI for Part-b projects and entire GOI loan shall be converted to grant in five tranches depending on extent of maintaining AT&C loss level at 15% level for five years. MoP , Gol has earmarked sanctioning of schemes upto Rs. 40,000 Crores under R-APDRP Part-B. Of this, upto Rs. 20,000 Crore would be converted to grant depending on extent to which utilities reduce AT&C losses in project areas.

R-APDRP also has provision for Capacity Building of Utility personnel and development of franchises through Part-C of the scheme. Few pilot projects adopting innovations are also envisaged under Part-C.

IV. Current Demand and Supply scenario of power in India

The energy deficit has been in the range of 9.6% to 11.1% during the first three years of the current five year plan with an increasing trend. However, the peak deficit has been in the range of 11.9% to 16.6% with a decreasing trend.

Structural reforms like de-licensing of generation, enhancing availability of skilled and trained manpower, introduction of ultra-mega power projects (UMPP) and liberalization of mega power policy have been undertaken to improve the power situation in the country.

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Despite these initiatives, a capacity addition of only 32,762 MW has taken place in the 11th Plan till date. As on January 31, 2011, the installed generation capacity, including capacity from renewable energy sources (RES), stands at 1,70,228 MW. The capacity addition in the next five-year plan is targeted as 106,470 MW . 

Further, the CAGR of electricity generation in the country during the first three years of the 11th Plan has been 5.21%, as compared to 6.35% during the same period of the previous plan. In addition, 96.7% of the target for generation of power has been achieved during the current fiscal year.

Steps, such as renovation and modernization, are being taken by the government to improve the PLF performance of existing thermal power stations. Additionally, the Ministry of power (MoP) has adopted a robust monitoring system for the capacity addition program so that the projects are executed in time. 

During the last few years, the supply of coal by Coal India Limited (CIL) to various power utilities has stagnated. Consequently, import of coal has risen tremendously from 4.5 MT in 2004-05 to around 23.2 MT in 2009-10.

In order to improve capacity addition further, development of national power grid and reorganization of APDRP is being undertaken. 

Additionally, under the  Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY) scheme, 573 projects have been sanctioned at an estimated cost of Rs. 26,353,51 crore. These projects cover electrification of 1.18 lakh un-electrified villages, intensive electrification of 3.55 lakh electrified villages and free electricity connections to 246 lakh BPL households. As on 15 February 2011, 92,689 un-electrified villages have been electrified, 1.76 lakh already electrified villages have been intensively electrified and free electricity connections have been released to 148.81 lakh BPL households.

The government plans to add ~ 97 GW in the indian power sector over the next 4 years of which ~53 GW is planned to be added by the private sector. This capacity addition will boost the overall supply to 1.1 trillion units from the current 0.74 trillion units at 75% plant load factor ( PLF ) even if around 70 % of the planned 97 GW is commissioned. Also, india has only commissioned ~52 GW of its power capacity plans in last two decades.

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Source: CEAEven with increase in capacity additions in recent years and planned capacity additions in future, the country is still expected to have power deficit of around 4.80%in FY 2014 ( down from 11% in FY 2009 and 10.10% in FY 2010 ). This country wide power supply deficit provides adequate market to power projects like that of UCPPL.

Source: CEA

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OBJECTIVE 2

B) To understand the types of finances and relevant factors

I Debt- equity structure

Four distinct ownership perspectives were identified for this analysis. Each reflects a different financial structure, financing costs, taxes, and desired rates of return. Briefly, the four ownership scenarios are:

Generating Company (GenCo):

The GenCo takes a market-based rate of return approach to building, owning, and operating a power plant. The company uses balance-sheet or corporate finance, where debt and equity investors hold claim to a diversified pool of corporate assets. For this reason, GenCo debt and equity are less risky than for an IPP (see below) and therefore GenCos pay lower returns. A typical GenCo capital structure consists of 35% debt at a 7.5% annual return (with no debt service reserve or letter of credit required) and 65% equity at 13% return. Although corporate finance might assume the debt to equity ratio remains constant over the project's life and principal is never repaid, it is often informative to explicitly show the effect of the project on a stand-alonefinancial basis. Therefore, to be conservative, the debt term is estimated as 28 years for a 30-year project, and all the debt is repaid assuming level mortgage-style payments. Flow-through accounting is used so that the corporate GenCo receives maximum benefit from accelerated depreciation and tax credits.

Independent Power Producer (IPP):

An IPP’s debt and equity investment is secured by only the one project, not by a pool of projects or other corporate assets as is the case for a GenCo. In this project finance approach, a typical capital structure is 70% debt at 8.0% annual return (based on 30-year Treasury Bill return plus a 1.5% spread) and 30% equity at a minimum 17% return. A 6-month Debt Service Reserve is maintained to limit repayment risks. Debt term for an IPP project is generally 15 years, with a level mortgage-style debt repayment schedule. (For solarand geothermal projects that are entitled to take Investment Tax Credits, a capital structure of 60% debt and 40% equity should be considered.) Flow-through accounting is used to allow equity investors to realize maximum benefit from accelerated depreciation and tax credits. IPP projects are required to meet two minimum debt coverage ratios. The first requirement is to have an operating income of no less than 1.5 times the annual debt service for the worst year. The second is to have an operating income of about 1.8 times or better for the averageyear. Because debt coverage is often the tightest constraint, actual IRR may be well over 17%, to perhaps 20% or more. Likewise, with good debt coverage, negative after-tax cash flows in later years of debt repayment (phantom income) are low.

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Regulated Investor-Owned Utility (IOU):

The regulated IOU perspective analyzes a project with a cost-based revenue requirements approach. As described by the EPRI Technical Assessment Guide (TAGTM), returns on investment are not set by the market, but by the regulatory system. In this calculation, operating expenses, property taxes, insurance, depreciation, and returns are summed to determine the revenue stream necessary to provide the approved return to debt and equity investors. Use of a Fixed Charge Rate is a way to approximate the levelized COE from this perspective. IOU capital structure is estimated as 47% debt at a 7.5% annual return; 6% preferred stock at 7.2%; and 47% common stock at 12.0%. Debt term and project life are both 30 years. Accelerated depreciation is normalized using a deferred tax account to spread the result over the project's lifetime. IOUs are not eligible to take an Investment Tax Credit for either solar or geothermal projects.

Municipal Utility (or other tax-exempt utility):

The municipal utility uses an analysis approach similar to that of the IOU. Capital structure is, however, assumed to be 100% debt at 5.5% annual return, and the public utility pays neither income tax nor property tax. As under the financial regulations set by central electricity authority (CEC) most of the generating companies follow a debt-equity structure of 70:30.Here is an example of UCPPL power projects proposed funding plan ( subject to change ) which would make the financial structure more clear:-

II Costing parameters

A) land

The designated area for power plants requires considerable land filling. To arrange soil for land filling dredged silt from river shall have to be depended upon.

For construction of jetty and power evacuation additional land is required at an estimated cost.

B) Main equipment The cost of the steam generator with supercritical steam parameters burning coal as main fuel of composition in a pulverized fuel furnace, its auxiliaries and critical high pressure piping take place on the price indication by a vendor using similar supercritical steam parameters and associated technology.

C) taxes, duties, insurance, etc.:-

For plant and equipment, taxes, duties, insurance etc. are considered at the following rates:- Ocean freight and marine insurance @6.5% on F.O.B prive considered on imported items

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Customs duty on imported items would levied @ 22% Port handling charges are anywhere between 1% to 2.5 % on C.I.F Value Excise duty is levied @8.24% for mechanical items of the project . Sales tax @2 % of

supply price with education cess @3% is considered. Freight and insurance for indigenous items @3.5% on F.O.R cost is considered

D) auxiliary plants and equipment

All auxiliary plants and equipment’s other than civil packages are considered to be procured through international competitive bidding route.

E) plant water system

For conveyance of consumptive water 1200 NB buried mild steel pipes are considered from the intake pump house to plant site covering a cross country length of 4km.

Cost of natural draft cooling water is estimated from the budgetary offer of typical vendors

For drawal of raw water fro the rivers an intake pump is constructed at a locatiom to be studied separately by the project authority.

F) fuel

Coal is considered to be generally available from mines in Indonesia and Australia. Cost of jetty is considered under the civil cost of the estimate It is assumed that coal would be supplied in size of (-) 50 mm in certain cases. An in plant coal storage of 30 days requirement is considered within the plant boundary Delivery cost of coal is generally taken at $66-$80 M.T

G) ash disposal

Bottom ash from units shall be extracted and disposed in wet mode and fly ash from the furnace would be extracdted, stored in dry form and disposed either in dry form for use as landfill or in wet slurry form to ash dyke using HCSD system.

H) electrical system The system helps to evacuate power from generating station to the proposed pooling station or substation. The cost of transmission lines for grid connectivity for evacuation of power generated and for supply of emergency will not be considered.

I) environmental Stack emission:- a high twin flue chimney with on-line gas monitoring system is

considered

Desulphurization: considering the sulphur content in thue fuel no FGD unit needs to be installed but a space provision is kept.

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Effluent: waste water from different processes of the station is collected in a guard pond where it is treated and recycled for use in less priority areas.

J) Time schedule:

Commercial operation of both the unitrs from” zero date” i.e the date for placement of order for main equipment is usually 51 months.

K) Manpower

Many key personnel are envisaged for O&M, administration and finance.

L) grid connectivity

The state electricity distribution company will draw power from the station bus of the power plant. The cost involved towards EHV line from the powerhouse to the nearby pooling station would be borne by the state distribution company.

III Tariff evaluation Components of Tariff.

(1) The tariff for supply of electricity from a thermal generatingstation shall comprise two parts, namely, capacity charge and energy charge (for recovery ofprimary fuel cost and limestone cost where applicable).

2) The tariff for supply of electricity from a hydro generating station shall comprise capacitycharge and energy charge to be derived in the manner specified in regulation 22, for recovery ofannual fixed cost through the twocharges.

(3) The tariff for transmission of electricity on inter-State transmission system shall comprisetransmission charge for recovery of annual fixed cost.

Annual Fixed Cost. The annual fixed cost (AFC) of a generating station or atransmission system shall consist of the following components –(a) Return on equity;(b) Interest on loan capital;(c) Depreciation;(d) Interest on working capital;(e) Operation and maintenance expenses;(f) Cost of secondary fuel oil (for coal-based and lignite fired generating stationsonly);(g) Special allowance in lieu of R&M or separate compensation allowance, whereverapplicable.

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Return on Equity. (1) Return on equity shall be computed in rupee terms, on then equity base determined in accordance with regulation 12 of CERC regulation(2) Return on equity shall be computed on pre-tax basis at the base rate of 15.5% to begrossed up as per clause (3) of the CERC regulation:Provided that in case of projects commissioned on or after 1st April, 2009, an additionalreturn of 0.5% shall be allowed if such projects are completed within the timeline specified in

Appendix-II:

Provided further that the additional return of 0.5% shall not be admissible if the project isnot completed within the timeline specified above for reasons whatsoever.

(3) The rate of return on equity shall be computed by grossing up the base rate with thenormal tax rate for the year 2008-09 applicable to the concerned generating company or thetransmission licensee, as the case may be:Provided that return on equity with respect to the actual tax rate applicable to thegenerating company or the transmission licensee, as the case may be, in line with the provisionsof the relevant Finance Acts of the respective year during the tariff period shall be trued upseparately for each year of the tariff period along with the tariff petition filed for the next tariffperiod.

(4) Rate of return on equity shall be rounded off to three decimal points and be computed asper the formula given below:Rate of pre-tax return on equity = Base rate / (1-t)Where t is the applicable tax rate in accordance with clause (3) of the regulation.-

This would be made more clear with the help of an illustration:-Illustration.-

(i) In case of the generating company or the transmission licensee paying MinimumAlternate Tax (MAT) @ 11.33% including surcharge and cess:

Rate of return on equity = 15.50/ (1-0.1133) = 17.481%

(ii) In case of generating company or the transmission licensee paying normal corporate tax@ 33.99% including surcharge and cess:

Rate of return on equity = 15.50/ (1-0.3399) = 23.481%

Interest on loan capital.

(1) The loans arrived at in the manner indicated in regulation 12shall be considered as gross normative loan for calculation of interest on loan.(2) The normative loan outstanding as on 1.4.2009 shall be worked out by deducting the

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cumulative repayment as admitted by the Commission up to 31.3.2009 from the gross normativeloan.(3) The repayment for the year of the tariff period 2009-14 shall be deemed to be equal to thedepreciation allowed for that year:(4) Notwithstanding any moratorium period availed by the generating company or thetransmission licensee, as the case may be the repayment of loan shall be considered from the firstyear of commercial operation of the project and shall be equal to the annual depreciationallowed,.(5) The rate of interest shall be the weighted average rate of interest calculated on the basisof the actual loan portfolio at the beginning of each year applicable to the project.:Provided that if there is no actual loan for a particular year but normative loan is stilloutstanding, the last available weighted average rate of interest shall be considered:

Provided further that if the generating station or the transmission system, as the case maybe, does not have actual loan, then the weighted average rate of interest of the generatingcompany or the transmission licensee as a whole shall be considered.(6) The interest on loan shall be calculated on the normative average loan of the year byapplying the weighted average rate of interest.(7) The generating company or the transmission licensee, as the case may be, shall makeevery effort to re-finance the loan as long as it results in net savings on interest and in that eventthe costs associated with such re-financing shall be borne by the beneficiaries and the net savingsshall be shared between the beneficiaries and the generating company or the transmissionlicensee, as the case may be, in the ratio of 2:1.(8) The changes to the terms and conditions of the loans shall be reflected from the date ofsuch re-financing.(9) In case of dispute, any of the parties may make an application in accordance with theCentral Electricity Regulatory Commission (Conduct of Business) Regulations, 1999, asamended from time to time, including statutory re-enactment thereof for settlement of thedispute:Provided that the beneficiary or the transmission customers shall not withhold anypayment on account of the interest claimed by the generating company or the transmissionlicensee during the pendency of any dispute arising out of re-financing of loan.

Depreciation.

(1) The value base for the purpose of depreciation shall be the capitalcost of the asset admitted by the Commission.(2) The salvage value of the asset shall be considered as 10% and depreciation shall beallowed up to maximum of 90% of the capital cost of the asset.(3) Depreciation shall be calculated annually based on Straight Line Method and at ratesspecified in the regulations for the assets of the generating station and transmission system:Provided that, the remaining depreciable value as on 31st March of the year closing after aperiod of 12 years from date of commercial operation shall be spread over the balance useful lifeof the assets.

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(4) In case of the existing projects, the balance depreciable value as on 1.4.2009 shall beworked out by deducting the cumulative depreciation as admitted by the Commission upto31.3.2009 from the gross depreciable value of the assets.(5) Depreciation shall be chargeable from the first year of commercial operation. In case ofcommercial operation of the asset for part of the year, depreciation shall be charged on pro ratabasis.

Interest on Working Capital.

(1) The working capital shall cover :(a) Coal-based/lignite-fired thermal generating stations(i) Cost of coal or lignite and limestone, if applicable, for 1½ months for pitheadgenerating stations and two months for non-pit-head generating stations, forgeneration corresponding to the normative annual plant availability factor;(ii) Cost of secondary fuel oil for two months for generation corresponding tothe normative annual plant availability factor, and in case of use of more than onesecondary fuel oil, cost of fuel oil stock for the main secondary fuel oil.(iii) Maintenance spares @ 20% of operation and maintenance expensesspecified in regulation 19.(iv) Receivables equivalent to two months of capacity charges and energycharges for sale of electricity calculated on the normative annual plant availabilityfactor, and(v) Operation and maintenance expenses for one month.(2) The cost of fuel in cases covered under sub-clauses (a) and (b) of clause (1) shall bebased on the landed cost incurred (taking into account normative transit and handling losses) bythe generating company and gross calorific value of the fuel as per actual for the three monthspreceding the first month for which tariff is to be determined and no fuel price escalation shall beprovided during the tariff period.(3) Rate of interest on working capital shall be on normative basis and shall be equal to theshort-term Prime Lending Rate of State Bank of India as on 1.4.2009 or on 1st April of the yearin which the generating station or a unit thereof or the transmission system, as the case may be, isdeclared under commercial operation, whichever is later.(4) Interest on working capital shall be payable on normative basis notwithstanding that thegenerating company or the transmission licensee has not taken loan for working capital from anyoutside agency.

Operation and Maintenance Expenses.

Normative operation and maintenance expenses shall be as follows, namely:Coal based and lignite fired (including those based on CFBC technology)generating stations, other than the generating stations Rs in lakh/MWYear 200/210/250

MW sets300/330/350MW sets

500MW sets

600MW sets & above

2009-10 18.20 16.00 13.00 11.70

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2010-11 19.24 16.92 13.74 12.372011-12 20.34 17.88 14.53 13.082012-13 21.51 18.91 15.36 13.822013-14 22.74 19.99 16.24 14.62

Provided that the above norms shall be multiplied by the following factors foradditional units in respective unit sizes for the units whose COD occurs on or after1.4.2009 in the same station:

200/210/250 MW Additional 5th & 6th units 0.9 Additional 7th & more units .85

300/330/350 MW Additional 4th & 5th units 0.9 Additional 6th & more units 0.85

500 MW and above Additional 3rd & 4th units 0.9 Additional 5th & above units 0.85

(b) Talcher Thermal Power Station(TPS), Tanda TPS, Badarpur TPS of NTPC andBokaro TPS, Chandrapura TPS and Durgapur TPS of DVC

Year Talcher TPS Tanda andChandrapura TPS

Badarpur, Bokaroand Durgapur TPS

2009-10 32.75 26.25 31.352010-11 34.62 27.75 32.252011-12 36.60 29.34 33.172012-13 38.70 31.02 34.122013-14 40.91 32.79 35.09 In a coal-based or lignite-fired thermal generating station a separate compensation allowance unit-wise shall be admissible to meet expenses on new assets of capital nature including in the nature of minor assets, in the following manner from the year following the year of completion of 10, 15, or 20 years of useful life:

Years of operation Compensation allowance Rs/lakh/MW/ yr

0-10 Nil 11-15 0.1516-20 0.3521-25 0.65

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Transmission system(i) Norms for operation and maintenance expenses shall be as

under

Expenses on secondary fuel oil consumption for coal-based and lignite-firedgenerating station.

(1) Expenses on secondary fuel oil in Rupees shall be computedcorresponding to normative secondary fuel oil consumption (SFC) specified in clause (iii) ofregulation 26, in accordance with the following formula:

= SFC x LPSFi x NAPAF x 24 x NDY x IC x 10

Where,SFC – Normative Specific Fuel Oil consumption in ml/kWhLPSFi – Weighted Average Landed Price of Secondary Fuel in Rs./ml consideredinitiallyNAPAF – Normative Annual Plant Availability Factor in percentageNDY – Number of days in a yearIC - Installed Capacity in MW.

(2) Initially, the landed cost incurred by the generating company on secondary fuel oil shallbe taken based on actuals of the weighted average price of the three preceding months and in theabsence of landed costs for the three preceding months, latest procurement price for thegenerating station, before the start of the year.

The secondary fuel oil expenses shall be subject to fuel price adjustment at the end of the eachyear of tariff period as per following formula:

SFC x NAPAF x 24 x NDY x IC x 10 x (LPSFy – LPSFi)

Where,LPSFy = The weighted average landed price of secondary fuel oil for the year in Rs. /ml

Computation and Payment of Capacity Charge and Energy Charge for ThermalGenerating Stations

(1) The fixed cost of a thermal generating station shall be computed on annual basis, basedon norms specified under these regulations, and recovered on monthly basis under capacitycharge. The total capacity charge payable for a generating station shall be shared by itsbeneficiaries as per their respective percentage share / allocation in the capacity of the generatingstation.

(2) The capacity charge (inclusive of incentive) payable to a thermal generating station for acalendar month shall be calculated in accordance with the following formulae :

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(a) Generating stations in commercial operation for less than ten (10) years on 1st April ofthe financial year :

AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF ) (in Rupees);Provided that in case the plant availability factor achieved during a financial year (PAFY)is less than 70%, the total capacity charge for the year shall be restricted toAFC x ( 0.5 + 35 / NAPAF ) x ( PAFY / 70 ) (in Rupees).

(b) For generating stations in commercial operation for ten (10) years or more on 1st April ofthe year:AFC x ( NDM / NDY ) x ( PAFM / NAPAF ) (in Rupees).Where,AFC = Annual fixed cost specified for the year, in Rupees.NAPAF = Normative annual plant availability factor in percentageNDM = Number of days in the monthNDY = Number of days in the yearPAFM = Plant availability factor achieved during the month, in percent:PAFY = Plant availability factor achieved during the year, in percent

(3) The PAFM and PAFY shall be computed in accordance with the following formula:NPAFM or PAFY = 10000 x Σ DCi / { N x IC x ( 100 - AUX ) } %i = 1

Where,AUX = Normative auxiliary energy consumption in percentage.DCi = Average declared capacity (in ex-bus MW), subject to clause

4) below, for the ith day of the period i.e. the month or the year as the casemay be, as certified by the concerned load dispatch centre after the day isover.IC = Installed Capacity (in MW) of the generating stationN = Number of days during the period i.e. the month or the yearas the case may be.Note : DCi and IC shall exclude the capacity of generating units notdeclared under commercial operation. In case of a change in IC during theconcerned period, its average value shall be taken.

(4) In case of fuel shortage in a thermal generating station, the generating company maypropose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours.The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule for thegenerating station to optimally utilize its MW and energy capability, in consultation with thebeneficiaries. DCi in such an event shall be taken to be equal to the maximum peak-hour expowerplant MW schedule specified by the concerned Load Despatch Centre for that day.

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(5) The energy charge shall cover the primary fuel cost and limestone consumption cost(where applicable), and shall be payable by every beneficiary for the total energy scheduled tobe supplied to such beneficiary during the calendar month on ex-power plant basis, at the energycharge rate of the month (with fuel and limestone price adjustment). Total Energy chargepayable to the generating company for a month shall be:(Energy charge rate in Rs./kWh) x {Scheduled energy (ex-bus) for the month in kWh.}

(6) Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis shall bedetermined to three decimal places in accordance with the following formulae : For coal based and lignite fired stations

ECR = { (GHR – SFC x CVSF) x LPPF / CVPF + LC x LPL } x 100 / (100 – AUX)

(7) The landed cost of fuel for the month shall include price of fuel corresponding to thegrade and quality of fuel inclusive of royalty, taxes and duties as applicable, transportation costby rail / road or any other means, and, for the purpose of computation of energy charge, and incase of coal/lignite shall be arrived at after considering normative transit and handling losses aspercentage of the quantity of coal or lignite dispatched by the coal or lignite supply companyduring the month as given below :Pithead generating stations : 0.2%Non-pithead generating stations : 0.8%(8) The landed price of limestone shall be taken based on procurement price of limestone forthe generating station, inclusive of royalty, taxes and duties as applicable and transportationcost for the month.

(9) The tariff structure as provided in this regulation may be adopted by the Department ofAtomic Energy, Government of India for the nuclear generating stations by specifying annualfixed cost (AFC), normative annual plant availability factor (NAPAF), installed capacity (IC),normative auxiliary power consumption (AUX) and energy charge rate (ECR) for such stations.

Computation and Payment of Transmission Charge for Inter-State TransmissionSystem

(1) The fixed cost of the transmission system shall be computed on annual basis, inaccordance with norms contained in these regulations, aggregated as appropriate, and recoveredon monthly basis as transmission charge from the users, who shall share these charges in themanner specified in Regulation 33.(2) The transmission charge (inclusive of incentive) payable for a calendar month for atransmission system or part thereof shall beAFC x ( NDM / NDY ) x ( TAFM / NATAF )Where,AFC = Annual fixed cost specified for the year, in RupeesNATAF = Normative annual transmission availability factor, in per centNDM = Number of days in the monthNDY = Number of days in the year

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TAFM = Transmission system availability factor for the month, inPercent, computed in accordance with Appendix IV.–.(3) The transmission charges shall be calculated separately for part of the transmissionsystem having differing NATAF, and aggregated thereafter, according to their sharing by thebeneficiaries.(4) The transmission licensee shall raise the bill for the transmission charge (inclusive ofincentive) for a month based on its estimate of TAFM. Adjustments, if any, shall be made on thebasis of the TAFM to be certified by the Member-Secretary of the Regional Power Committee ofthe concerned region within 30 days from the last day of the relevant month

Unscheduled Interchange(UI) Charges.

(1) All variations between actual net injectionand scheduled net injection for the generating stations, and all variations between actual netdrawal and scheduled net drawal for the beneficiaries shall be treated as their respective Unscheduled Interchanges (UI), charges for which shall be governed by the relevant regulationsspecified by the Commission from time to time.

(2) Actual net unscheduled interchange of every inter-State entity shall be metered on itsperiphery through special energy meters (SEMs) installed by the Central Transmission Utility(CTU), and computed in MWh for each 15-minute time block by the concerned Regional LoadDespatch Centre.

IV Due diligence during funding of a power project

Here are the various Due Diligence activities involved in funding of a thermal power project

FUEL AVAILABILITY

• Long term fuel availability• Daily, seasonal fluctuations• Fuel competition• Long term Fuel Purchase Agreement (FPA)

PLANT CAPACITY

• Optimum capacity• Electricity demand• Present and future situation• Fuel supply security

SITE SELECTION

• Location, topography, soil strength

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• Flood, earthquake risks• Fuel supply, electricity off‐take• Availability of roads• Availability of water• Availability of grid• Equipment transfer facilities

TECHNOLOGY• Proven technology• Acceptable efficiency• Acceptable availability• Environmental compliance• Project life• Investment cost

EQUIPMENT SELECTION• Efficiency, investment cost, operating cost• Equipment quality, automation• Design suitability• Combustion system• Equipment type• Safety margins• Fuel flexibility

WATER AVAILABILITY• During summer/drought season• Historical availability• Water quality• River/stream water vs. ground water

EPC CONTRACTOR/EQUIPMENT SUPPLIER• Track record• Capability and reliability• Plant performance• Guarantees• Payment terms and conditions• After sale service• Market presence• Financial stability

ONSTRUCTION CONTRACT• Payment terms/conditions• Payment schedules• Performance guarantees• Liquidated damages• Contract law

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• Arbitration

FINANCIAL MODELLING• Gross power, parasitic load, net power• Annual operating hours• Fuel and electricity pricing• Adequate escalations• Investment cost• Training and development cost• Insurance• Working capital• Tax rate• Discount rate• Interest, repayment period, grace period• IRR, NPV• Sensitivity analysis• Debt service coverage ratio

EQUITY FINANCING• Current status of the project• Credibility of the project developer• Credibility of other investors• Commitment from investors• Completion guarantee• Equity drawdown

DEBT FINANCING• Loan terms• Repayment period• Grace period• Interest rate• Interest during construction• Debt‐service coverage ratio• Working capital• Debt drawdown

PROJECT SCHEDULE• Practical schedule• Design• Manufacturing• Transportation• Erection• Testing and commissioning• Commercial operation and hand over

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PLANT OPERATION• Operating team• Qualification and experience• Commitment• Motivation

PLANT MAINTENANCE• Maintenance team• Qualification and experience• Commitment• Motivation• Local maintenance companies

PROJECT MANAGEMENT TEAM• Experience of project developer• Experience of consultant• Experience of other stakeholders

INSURANCE DURING CONSTRUCTION• Workmen’s compensation insurance• Automobile liability insurance• Construction plant and equipment insurance• Construction all risks insurance• Third party liability insurance• Marine and other transit insurance

INSURANCE DURING OPERATION• Fire risks insurance• Advanced loss of revenue insurance• Operator’s business interruption insurance• Third party liability insurance• Workmen’s compensation insurance

PERFORMANCE GUARANTEE• Availability guarantee• Net Power output guarantee• Completion guarantee• Heat rate guarantee• Environmental and noise level guarantee• Warranty

RISK MITIGATION MEASURES• Technology risk• Long term fuel supply• Off‐take of electricity

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• Construction/operation risk• Cost over‐run risk

Chapter 6 Issues and challenges facing thermal power sector

The thermal Power Sector is a highly capital-intensive industry with long gestation periods, before the commencement of revenue generation. Since most of projects have a long time frame (4-5 years of construction period and operating period of over 25 years), there are some inherent risks which this sector faces.

Availability of Coal: -

Coal is the mainstay of the power production in India and is expected to remain so in the future. India has limited coal reserves, plus, availability of domestic coal is a challenge on account of various bottlenecks such as capacity expansion of Coal India Limited (the largest coal producing company in the world, coal block allocation, tribal land acquisition, environmental and forest clearances, etc.Transportation of coal is a big concern in itself. Within the country, coal is transported by Indian Railways and in case of imports; coal is to be unloaded at ports. In both cases, India currently faces capacity shortage. Hence, a project developer has to account for and manage its logistics chain in a manner that ensures regular fuel supply which is a big challenge.

Dependence on Equipment Suppliers: -

The power sector is heavily dependent on Equipment suppliers. In fact, equipment shortages have been a significant reason for India missing its capacity addition targets for the 10th five year plan. While the shortage has been primarily in the core components of boilers, turbines and generators, there has been lack of adequate supply of Balance of Plant (BOP) equipment as well. These include coal handling, ash-handling plants, etc. Apart from these, there is shortage of construction equipment as well. Hence, inadequate supply of equipments is a cause of concern for the power companies.

Aggregate Commercial and Technical Losses: -The Aggregate Technical and Commercial Loss (AT&C) is defined as the power lost due to inefficient transmission and distribution infrastructure. India’s AT&C losses are as high as 30% compared with 5-10% in the developed markets which means out of every 100 units produced, 30 are lost during transmission and distribution. Technical losses are due to inadequate investments over the years for system improvement works. Commercial losses are mainly due to low metering efficiency, pilferage and theft of power. This is a huge problem for the power sector.

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Manpower Shortage

There is a general consensus that shortage of talent in the thermal power sector is a long term problem and is likely to continue to push up project costs and risks. The flow of talent into construction and power sector has been gradually drying up as candidates have sought an alternative – and often more lucrative – career options. The Government, which is the biggest buyer of the capital projects, has also not done enough to address this challenge. The educationsystem is often not delivering the required number of specialists across project management, engineering, estimating, surveying and contract management. Facing a desperate game of catch up, the industry needs a genuine collaboration between project owners, contractors andgovernments to attract more school leavers and graduates. Companies should also seek to stay in touch with changing employee aspirations. By encouraging diversity in its employment practices and by offering greater flexibility in working hours, the sector can reach out to a wider potential audience that perhaps would not previously have considered such a career. Investment in existing employees is also crucial in order to offer better-defined career structures, with a greater focus on training and higher salaries where possible.

©Other Roadblocks leading to Demand Supply Gap: -

The power sector has other concerns like shortage of skilled manpower for construction and commissioning of projects, contractual disputes between project authorities, contractors and their sub-vendors, delay in readiness of balance of plants by the executing agencies. Difficulties have been experienced by developers in land acquisition, rehabilitation, environmental and forest – related issues, inter-state issues, geological surprises (particularly for Hydro projects) and contractual issues. These issues continue to pose challenges to maintain the pace of development of power projects.

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Chapter 7

Financial Comparative analysis between Adani power, TATA POWER, jsw and GVK power

Ratio analysis of the last 5 companies based on their performance in the last 5 years

Current share price Company name

Share price

52 week high/low

Volume Eps p/e

Adani power 109.90 144.5/105.7 19883 45.75 2.40

GVK power 19.30 17.60/51.45 333486 44.63 0.43

JSW power 67.15 64.35/136.30 32502 12.44 5.40

Tata power 1286.75 1125/1465 3561 31.48 40.88

Lanco power 23.70 74.70/21.10 12,385,505 2.0 25.64

Adani power

Mar '06

Mar '07

Mar '08

Mar '09

Mar '10

Investment Valuation Ratios Face Value 10 10 10 10 10Dividend Per Share -- -- -- -- --Operating Profit Per Share (Rs)

-0.01 -0.09 -0.03 -0.02 1.12

Net Operating Profit Per Share (Rs)

-- -- -- -- 1.99

Free Reserves Per Share (Rs)

-0.14 -0.09 -0.07 2.38 16.6

Bonus in Equity Capital -- -- -- -- --Profitability Ratios

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Operating Profit Margin(%)

-- -- -- -- 56.24

Profit Before Interest And Tax Margin(%)

-- -- -- -- 45.41

Gross Profit Margin(%) -- -- -- -- 48.11Cash Profit Margin(%) -- -- -- -- 43.42Adjusted Cash Margin(%)

-- -- -- -- 43.42

Net Profit Margin(%) -- -- -- -- 37.07Adjusted Net Profit Margin(%)

-- -- -- -- 37.07

Return On Capital Employed(%)

-- -- -- -- 1.51

Return On Net Worth(%)

-- -- -- -- 2.94

Adjusted Return on Net Worth(%)

-0.1 -0.88 -0.11 -0.12 2.84

Return on Assets Excluding Revaluations

-0.01 9.91 22.57 12.38 26.6

Return on Assets Including Revaluations

-0.01 9.91 22.57 12.38 26.6

Return on Long Term Funds(%)

-0.1 -0.56 -0.06 -0.03 1.52

Liquidity And Solvency Ratios Current Ratio 0.47 0.22 0.9 1.78 1.61Quick Ratio 0.47 0.22 0.9 1.78 2.04Debt Equity Ratio -- 0.56 0.93 2.18 1.68Long Term Debt Equity Ratio

-- 0.56 0.93 2.18 1.65

Debt Coverage Ratios Interest Cover -- -- -- -- 6.24Total Debt to Owners Fund

-- 0.56 0.93 2.18 1.68

Financial Charges Coverage Ratio

-- -- -- -- 7.18

Financial Charges Coverage Ratio Post Tax

-- -- -- -- 6.47

Management Efficiency Ratios Inventory Turnover Ratio

-- -- -- -- --

Debtors Turnover Ratio -- -- -- -- 1.7

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Investments Turnover Ratio

-- -- -- -- 45.68

Fixed Assets Turnover Ratio

-- -- -- -- --

Total Assets Turnover Ratio

-- -- -- -- 0.03

Asset Turnover Ratio -- -- -- -- 0.16 Average Raw Material Holding

-- -- -- -- --

Average Finished Goods Held

-- -- -- -- --

Number of Days In Working Capital

-- -- -- -- 1,130.70

Profit & Loss Account Ratios Material Cost Composition

-- -- -- -- 38.42

Imported Composition of Raw Materials Consumed

-- -- -- -- --

Selling Distribution Cost Composition

-- -- -- -- 1.9

Expenses as Composition of Total Sales

-- -- -- -- --

Cash Flow Indicator Ratios Dividend Payout Ratio Net Profit

-- -- -- -- --

Dividend Payout Ratio Cash Profit

-- -- -- -- --

Earning Retention Ratio -- -- -- -- 100Cash Earning Retention Ratio

-- -- -- -- 100

AdjustedCash Flow Times

-- -- -- -- 48.73

Mar '06

Mar '07

Mar '08 Mar '09 Mar '10

Earnings Per Share -0.01 -0.09 -0.03 -0.02 0.78Book Value 9.86 9.91 22.57 12.44 26.6

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From the above ratios we can make out that the earning per share of adani power has increased rapidly from FY 2009 to FY 2010.

Tata power

Mar '06

Mar '07 Mar '08 Mar '09 Mar '10

Investment Valuation Ratios Face Value 10 10 10 10 10Dividend Per Share 8.5 9.5 10.5 11.5 12Operating Profit Per Share (Rs) 42.48 35.46 41.67 50.79 79.16Net Operating Profit Per Share (Rs) 230.1 248.54 267.77 327.74 299.12Free Reserves Per Share (Rs) 192.5 215.63 278.2 308.95 --Bonus in Equity Capital 0.57 0.57 0.51 0.51 0.47Profitability Ratios Operating Profit Margin(%) 18.46 14.26 15.56 15.49 26.17Profit Before Interest And Tax Margin(%)

11.9 7.79 10.38 10.63 18.78

Gross Profit Margin(%) 18.25 16.27 10.64 10.96 19.44Cash Profit Margin(%) 18.81 18.81 12.65 10.88 18.63Adjusted Cash Margin(%) 15.4 14.85 12.65 10.88 19.19Net Profit Margin(%) 12.92 13.26 14.35 12.32 12.84Adjusted Net Profit Margin(%) 9.3 9.11 14.35 12.32 12.88Return On Capital Employed(%) 8.69 7.61 6.96 7.32 9.9Return On Net Worth(%) 11.07 11.63 10.88 10.66 8.99Adjusted Return on Net Worth(%) 7.99 7.99 5.9 5.56 8.83Return on Assets Excluding Revaluations

6.31 302.42 362.04 390.36 447.68

Return on Assets Including Revaluations

6.31 302.42 362.04 390.36 447.68

Return on Long Term Funds(%) 8.72 7.62 7.18 7.67 10.19Liquidity And Solvency Ratios Current Ratio 2.18 2.22 1.78 1.64 2.51Quick Ratio 1.85 2 1.75 1.77 2.26Debt Equity Ratio 0.51 0.61 0.39 0.61 0.57Long Term Debt Equity Ratio 0.5 0.6 0.34 0.53 0.55Debt Coverage Ratios Interest Cover 4.86 4.03 4.63 3.33 4.02Total Debt to Owners Fund 0.51 0.61 0.39 0.61 0.55Financial Charges Coverage Ratio 6.63 5.55 6.23 4.15 5.11Financial Charges Coverage Ratio 6.89 6.34 7.78 4.86 4.37

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Post TaxManagement Efficiency Ratios Inventory Turnover Ratio 10.68 13.25 18.7 15.49 18.98Debtors Turnover Ratio 5.2 3.88 4.09 4.83 3.99Investments Turnover Ratio 498.8 6,072.41 18.7 15.49 12.04Fixed Assets Turnover Ratio 1.41 1.4 0.91 0.81 0.71Total Assets Turnover Ratio 0.55 0.51 0.53 0.52 0.43Asset Turnover Ratio 0.77 0.79 0.91 0.81 0.71 Average Raw Material Holding -- -- -- -- --Average Finished Goods Held -- -- -- -- --Number of Days In Working Capital 131.9 166.79 122.89 123.79 181.47Profit & Loss Account Ratios Material Cost Composition 70.43 70.1 72.76 73.86 60.74Imported Composition of Raw Materials Consumed

-- -- -- -- --

Selling Distribution Cost Composition

1.19 5.19 0.59 0.67 --

Expenses as Composition of Total Sales

1.82 2.12 0.31 4.47 0.78

Cash Flow Indicator Ratios Dividend Payout Ratio Net Profit 31.41 31.6 30.84 31.2 34.12Dividend Payout Ratio Cash Profit 21.34 22.05 23.02 22.9 22.68Earning Retention Ratio 56.37 54.01 43.09 40.16 65.56Cash Earning Retention Ratio 73.65 71.79 65.02 64.68 77.18AdjustedCash Flow Times 3.84 4.71 4.02 6.44 4.14

Mar '06

Mar '07 Mar '08 Mar '09 Mar '10

Earnings Per Share 30.85 35.21 39.42 41.65 39.93Book Value 278.6 302.73 362.11 390.36 447

As we can make out from the above table that eps of tata power has come down from FY 2009 to FY 2010. Therefore it does not make it an attractive stock to invest in.

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Lanco Infratech

  Mar '06 Mar '07 Mar '08 Mar '09 Mar '10Investment Valuation Ratios Face Value 10 10 10 10 1Dividend Per Share -- -- -- -- --Operating Profit Per Share (Rs) 6.91 5.13 14.14 25.5 3.6Net Operating Profit Per Share (Rs) 49.23 24.36 70.81 183.6 24.45Free Reserves Per Share (Rs) 17.05 51.95 61.57 73.64 11.81Bonus in Equity Capital 75 71.45 71.94 71.92 66.28Profitability Ratios Operating Profit Margin(%) 14.03 21.06 19.96 13.89 14.71Profit Before Interest And Tax Margin(%)

12.67 19.95 18.89 12.85 13.44

Gross Profit Margin(%) 12.89 19.2 19.22 12.89 13.7Cash Profit Margin(%) 7.62 13.86 13.14 7.45 9.1Adjusted Cash Margin(%) 10.19 13.89 13.14 7.45 9.1Net Profit Margin(%) 6.39 13.2 12.49 6.46 8.1Adjusted Net Profit Margin(%) 8.95 13.22 12.49 6.46 8.1Return On Capital Employed(%) 14.72 7.93 15.39 16.9 15.57Return On Net Worth(%) 11.15 5.3 12.56 14.22 15.76Adjusted Return on Net Worth(%) 15.62 5.3 12.48 14.22 15.76Return on Assets Excluding Revaluations

2.95 62.03 71.64 83.72 12.82

Return on Assets Including Revaluations

2.95 62.03 71.64 83.72 12.82

Return on Long Term Funds(%) 15.28 8.13 19.06 16.9 15.77Liquidity And Solvency Ratios Current Ratio 0.96 1.06 0.9 1.31 1.61Quick Ratio 0.94 1.08 1.03 1.16 1.48Debt Equity Ratio 0.6 0.12 0.35 0.72 0.89Long Term Debt Equity Ratio 0.54 0.09 0.09 0.72 0.89Debt Coverage Ratios Interest Cover 7.26 6.24 11.76 3.91 4.64Total Debt to Owners Fund 0.6 0.12 0.35 0.72 0.89Financial Charges Coverage Ratio 6.21 5.94 9.92 4.2 4.94Financial Charges Coverage Ratio Post Tax

4.21 4.63 7.14 3.2 3.76

Management Efficiency Ratios Inventory Turnover Ratio 12.58 11.35 10.1 9.67 13.16

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Debtors Turnover Ratio 3.67 4.55 4.16 4.65 3.39Investments Turnover Ratio 12.47 11.11 10.1 9.67 13.16Fixed Assets Turnover Ratio 11.99 11.66 7.78 11.18 14.76Total Assets Turnover Ratio 1.08 0.35 0.73 1.27 1Asset Turnover Ratio 7.27 5.96 7.78 11.18 14.76 Average Raw Material Holding -- -- -- -- --Average Finished Goods Held -- -- -- -- --Number of Days In Working Capital 3.87 76.78 53.09 75.77 126.46Profit & Loss Account Ratios Material Cost Composition -- -- -- -- --Imported Composition of Raw Materials Consumed

-- -- -- -- --

Selling Distribution Cost Composition

0.03 0.92 0.28 -- --

Expenses as Composition of Total Sales

18.6 -- 0.04 -- --

Cash Flow Indicator Ratios Dividend Payout Ratio Net Profit -- -- -- -- --Dividend Payout Ratio Cash Profit -- -- -- -- --Earning Retention Ratio 100 100 100 100 100Cash Earning Retention Ratio 100 100 100 100 100AdjustedCash Flow Times 3.39 2.07 2.63 4.4 5.01 Mar '06 Mar '07 Mar '08 Mar '09 Mar '10Earnings Per Share 3.17 3.29 9 11.91 2.02Book Value 28.44 62.03 71.64 83.72 12.82

Jindal power

Mar '06 Mar '07 Mar '08Mar '09

Mar '10

Investment Valuation Ratios Face Value 5 5 1 1 1Dividend Per Share 15 18 4 5.5 1.25Operating Profit Per Share (Rs)

335.41 457.85 149.12 170.57 26.79

Net Operating Profit Per Share (Rs)

833.01 1,144.14 348.67 496.46 78.9

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Free Reserves Per Share (Rs)

564.79 773.29 230.73 327.99 -0.03

Bonus in Equity Capital

-- -- -- -- 83.3

Profitability Ratios Operating Profit Margin(%)

40.26 40.01 42.76 34.35 34.78

Profit Before Interest And Tax Margin(%)

31.4 30.15 33.99 27.98 27.05

Gross Profit Margin(%)

31.72 30.46 34.35 28.71 27.8

Cash Profit Margin(%)

30.71 28.96 33.99 26.71 26.49

Adjusted Cash Margin(%)

30.71 28.96 33.99 26.71 26.68

Net Profit Margin(%)

22.11 19.75 22.79 19.5 19.82

Adjusted Net Profit Margin(%)

22.11 19.75 22.79 19.5 19.59

Return On Capital Employed(%)

18.28 18.47 24.95 23.16 14.86

Return On Net Worth(%)

31.07 28.19 32.95 28.38 21.94

Adjusted Return on Net Worth(%)

31.26 27.83 37.11 30.87 21.94

Return on Assets Excluding Revaluations

598.84 809.78 243.78 349.96 72.41

Return on Assets Including Revaluations

598.84 809.78 243.78 349.96 72.41

Return on Long Term Funds(%)

20.55 21.54 26.6 25.01 13.88

Liquidity And Solvency Ratios Current Ratio 0.83 0.68 1.25 1.04 1.19Quick Ratio 0.78 0.73 1.1 0.95 0.92Debt Equity Ratio 1.49 1.4 1.03 0.92 1.24Long Term Debt Equity Ratio

1.21 1.06 0.9 0.77 0.84

Debt Coverage Ratios Interest Cover 8.87 6.97 8.45 10.33 7.91

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Total Debt to Owners Fund

1.49 1.4 1.03 0.92 1.24

Financial Charges Coverage Ratio

9.8 8.35 9.68 10.59 13.57

Financial Charges Coverage Ratio Post Tax

8.34 7 7.95 8.35 11.35

Management Efficiency Ratios

Inventory Turnover Ratio

7.55 6.99 7.01 9.08 8.05

Debtors Turnover Ratio

10.86 11.37 17.67 22.62 14.49

Investments Turnover Ratio

7.55 6.99 7.01 9.08 5.94

Fixed Assets Turnover Ratio

0.79 0.71 0.91 1.04 0.83

Total Assets Turnover Ratio

0.56 0.59 0.7 0.74 0.49

Asset Turnover Ratio

0.79 0.71 0.91 1.04 0.83

Average Raw Material Holding

67.56 95.86 85.56 40.04 --

Average Finished Goods Held

56.74 48.31 50.88 37.94 --

Number of Days In Working Capital

43.8 21.08 79.41 50.53 45.07

Profit & Loss Account Ratios Material Cost Composition

28.09 31.94 35.95 45.48 43.81

Imported Composition of Raw Materials Consumed

-- -- 46.77 31.97 46.23

Selling Distribution Cost Composition

8.66 7.84 4.93 4.26 --

Expenses as Composition of Total Sales

14.49 16.82 12.16 13.3 5.58

Cash Flow Indicator Ratios Dividend Payout Ratio Net Profit

9.19 9.14 5.86 5.55 8.16

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Dividend Payout Ratio Cash Profit

6.64 6.18 4.29 4.33 6.06

Earning Retention Ratio

90.87 90.74 94.79 94.9 91.84

Cash Earning Retention Ratio

93.39 93.77 96.07 95.95 93.94

AdjustedCash Flow Times

3.45 3.4 2.09 2.36 4.21

Mar '06 Mar '07 Mar '08 Mar '09

Mar '10

Earnings Per Share 186.07 228.3 80.34 99.35 15.89Book Value 599.08 810.83 243.98 350.16 72.44

As we can make out from the above table that eps of Jindal power has rapidly come down from FY 2009 to FY 2010. Therefore it does not make it an attractive stock to invest in.

GVK power

  Mar '06 Mar '07 Mar '08 Mar '09 Mar '10Investment Valuation Ratios

Face Value 10 10 1 1 1Dividend Per Share

-- 2.5 -- -- --

Operating Profit Per Share (Rs)

2.84 1.71 0.1 0.07 0.12

Net Operating Profit Per Share (Rs)

4.81 4.72 0.19 0.2 0.3

Free Reserves Per

164.32 138.45 11.22 11.37 14.61

80

Share (Rs)Bonus in Equity Capital

22.35 22.35 3.75 3.75 3.34

Profitability Ratios Operating Profit Margin(%)

59.06 36.17 51.15 -- 41.4

Profit Before Interest And Tax Margin(%)

28.42 9.4 11.59 -- 32.01

Gross Profit Margin(%)

43.88 39.22 51.11 -- 41.31

Cash Profit Margin(%)

34.31 34.65 76.06 -- 38.11

Adjusted Cash Margin(%)

33.78 34.83 76.06 45.19 38.11

Net Profit Margin(%)

34.3 34.64 76.05 51.33 36

Adjusted Net Profit Margin(%)

33.77 34.83 76.05 -- 36

Return On Capital Employed(%)

4.59 4.62 6.15 -- 1.27

Return On Net Worth(%)

1.96 3.52 5.26 -- 0.87

Adjusted Return on Net Worth(%)

1.93 4.25 5.26 1.06 0.92

Return on Assets Excluding Revaluations

1.91 148.45 12.22 12.37 15.61

Return on Assets Including Revaluations

1.91 148.45 12.22 12.37 15.61

Return on Long Term Funds(%)

4.59 10.17 6.15 1.32 1.27

Liquidity And Solvency

81

RatiosCurrent Ratio 9.2 0.26 266.99 223.04 268.52Quick Ratio 9.19 2.96 266.75 222.9 268.38Debt Equity Ratio

-- 1 -- -- 0.04

Long Term Debt Equity Ratio

-- -- -- -- 0.04

Debt Coverage Ratios Interest Cover

2.21 1.89 16.28 -- 38

Total Debt to Owners Fund

-- 1 -- -- 0.04

Financial Charges Coverage Ratio

2.21 1.89 16.28 102.79 22

Financial Charges Coverage Ratio Post Tax

1.94 1.78 14.93 94.47 15.54

Management Efficiency Ratios

Inventory Turnover Ratio

-- -- -- -- --

Debtors Turnover Ratio

15.96 9 7.73 4.7 9.23

Investments Turnover Ratio

-- -- -- -- --

Fixed Assets Turnover Ratio

931.25 1,018.54 -- -- --

Total Assets Turnover Ratio

0.03 0.01 0.02 -- --

Asset Turnover Ratio

257.63 238.31 73.65 68.42 91.28

Average Raw Material Holding

-- -- -- -- --

82

Average Finished Goods Held

-- -- -- -- --

Number of Days In Working Capital

3,277.94 2,144.04 7,313.58 10,157.91 8,108.59

Profit & Loss Account Ratios

Material Cost Composition

-- -- -- -- --

Imported Composition of Raw Materials Consumed

-- -- -- -- --

Selling Distribution Cost Composition

-- -- -- -- --

Expenses as Composition of Total Sales

-- -- -- -- --

Cash Flow Indicator Ratios

Dividend Payout Ratio Net Profit

-- 45.4 -- -- --

Dividend Payout Ratio Cash Profit

-- 45.39 -- -- --

Earning Retention Ratio

100 54.85 100 100 100

Cash Earning Retention Ratio

100 54.85 100 100 100

AdjustedCash Flow Times

-- 23.48 -- -- 4.37

Mar '06 Mar '07 Mar '08 Mar '09 Mar '10Earnings Per Share

3.42 6.28 0.64 0.15 0.14

Book Value 174.32 148.45 12.22 12.37 15.61

83

As we can make out from the above table that eps of GVK power has come down to an extent from FY 2009 to FY 2010. Therefore it does not make it an attractive stock to invest in. recommendation would be to keep the stock if one has it and whoever doesn’t should invest in it.

Recommendations

84

Attractive market and sector

The Indian economy is expected to continue on a high growth path with recent GDP growth being in the range of 7-9 % per annum. With electricity to gross domestic product (GDP) elasticity pegged at 0.8 and the current supply deficit, the power generation capacity addition is considered to be the key infrastructure requirement to support projected growth in the economy. Increase in the middle class population and changing lifestyle leading to higher per capita electricity consumption from current level of 704 kwh would require additional generation capacity of more than 100 GW as envisaged in X1 and X11 five year plan of the government of India. The liberalized power sector in India has achieved structural and regular stability making it attractive for private investment. These factors and the supportive Indian capital market establish UCPPL as an attractive target for equity investment.

What should be UCPPL’S business plan in setting up further power plants ?

UCPPL should plan to achieve economies of scale in operations, maintenance, power sale and funding.

They should choose a location where ffuel, water, infrastructure, market and land should be easily available.

They have to adopt latest and proven state-of-the-art supercritical technology for better operational efficiencies and environmental impact management.

They should secure cash flows through long term power sale for initial stages. This would immune financial returns from any increase in fuel and project cost.

They should go in for robust financing arrangements. This includes promoter’s equity, external private or financial partners, internal accruals from initial stages of the project and the IPO.

Bibliography

85

www.powermin.nic.in/JSP_SERVLETS/internal.jsp

www.cercind.gov.in/regulations.html

www.cea.nic.in/regulations.html

www.ntpc.co.in/index.php?option=com_content&view=article

http://www.lancogroup.com/power/power.html

http://www.gvk.com/ourbusiness/energy/energy.aspx

http://www.jindalpower.com/plant/overview.aspx

http://www.adanipower.com/Business/PowerGeneration.html

http://www.ucppl.com/index.php?option=com_content&view=article&id=48&Itemid=54

DRHP, COAL INDIA LIMITED

Statistical yearbook of Indonesia 2010

www.pfcindia.in?loan disbursements

http://www.moneycontrol.com/financials/ www.usea.org/ power

DPR of UCPPL on west Bengal and Gujarat

86