Power Sector Analysis And Project Economics

2007 IIM Indore Abhishek Anand

[ASTRO MEASAT SUMMER INTERNSHIP PROJECT] Power Sector Analysis and Project Economics

Contents POWER SECTOR- INTRODUCTION .......................................................................................................................... 4 POWER SECTOR SNAPSHOT ..............................................................................................................................................4 STRUCTURE OF POWER SUPPLY INDUSTRY ............................................................................................................................7 PROBLEMS CONFRONTING THE SECTOR ................................................................................................................ 9 GENERATION ....................................................................................................................................................... 10 RESOURCES .................................................................................................................................................................10 Coal .....................................................................................................................................................................10 Natural Gas .........................................................................................................................................................11 Hydroelectric Power Station ...............................................................................................................................12 Nuclear power .....................................................................................................................................................12 TARGET 2012 .............................................................................................................................................................12 TRANSMISSION AND DISTRIBUTION .................................................................................................................... 13 KEY CONCERNS ............................................................................................................................................................13 PROJECT - COST ................................................................................................................................................... 15 INTRODUCTION .......................................................................................................................................................15 FACTORS INFLUENCING THE COST OF GENERATION .............................................................................................................15 Fuel......................................................................................................................................................................15 Cost of Fuel..........................................................................................................................................................16 Capital Cost .........................................................................................................................................................17 Source of energy .................................................................................................................................................17 Infrastructure ......................................................................................................................................................17 Size of Plant .........................................................................................................................................................18 Equipments .........................................................................................................................................................18 Interest During Construction(IDC) .......................................................................................................................18 Engineering, Procurement and Construction (EPC) contracts .............................................................................18 COMPUTATION OF TARIFF.......................................................................................................................................18 Method................................................................................................................................................................18 Formula Used ......................................................................................................................................................20 Assumptions for the calculations ........................................................................................................................20 SAMPLE CASE: .............................................................................................................................................................23 PROFITABILITY .............................................................................................................................................................24 Station heat rate .................................................................................................................................................25 O&M charges ......................................................................................................................................................25 Auxiliary consumption.........................................................................................................................................25 SENSITIVITY ANALYSIS ...................................................................................................................................................25 ULTRA MEGA POWER PROJECTS .......................................................................................................................... 27 MANAGEMENT STRUCTURE:...........................................................................................................................................27 ROLE OF SHELL COMPANIES ...........................................................................................................................................27 RFP...........................................................................................................................................................................28 APPROACHES FOR TARIFF DETERMINATION .......................................................................................................................29 Cost based approach ...........................................................................................................................................29 Benchmarking Approach .....................................................................................................................................29 Avoided Cost Approach .......................................................................................................................................30 PAYMENT SECURITY ......................................................................................................................................................31 SECTOR PLAYERS.................................................................................................................................................. 32 NTPC ........................................................................................................................................................................32 Summary: ............................................................................................................................................................32 Business Strategy: ...............................................................................................................................................32 Key Performance Indicators: ...............................................................................................................................32 Distribution of capacity: ......................................................................................................................................33 Financial Highlights: ............................................................................................................................................33

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Profile of Chairman NTPC ....................................................................................................................................33 Station wise Power generation ...........................................................................................................................34 PLF comparison of NTPC vs. other power producers ...........................................................................................35 NTPC Subsidiaries and JVs ...................................................................................................................................35 Growth plans – Power projects Planned .............................................................................................................36 Shareholding Pattern ..........................................................................................................................................38 TATA POWER ..............................................................................................................................................................39 Summary: ............................................................................................................................................................39 Business strategy: ...............................................................................................................................................39 Key performance indicators: ...............................................................................................................................39 Financial Highlights: ............................................................................................................................................39 Growth plans:......................................................................................................................................................40 Transmission and Distribution Capacity ..............................................................................................................40 Subsidiaries .........................................................................................................................................................40 Shareholding pattern ..........................................................................................................................................42 RELIANCE ENERGY ........................................................................................................................................................43 Summary .............................................................................................................................................................43 Key performance Indicators ................................................................................................................................43 Key Financials ......................................................................................................................................................44 Growth Plans .......................................................................................................................................................43 Key Management Personnel ...............................................................................................................................44 Details of Share Holding Pattern .........................................................................................................................46 Recent Projects bagged by REL ...........................................................................................................................47 Other Projects under Commissioning /Execution ................................................................................................47 Key Projects of EPC Division ................................................................................................................................47 CESC.........................................................................................................................................................................49 Company Overview—..........................................................................................................................................49 Products & Services— .........................................................................................................................................49 Recent Developments— ......................................................................................................................................49 Financials ............................................................................................................................................................50 Shareholding Pattern ..........................................................................................................................................51 COMPANY COMPARISON ..................................................................................................................................... 52 ICRA LONG-TERM RATING SCALE: ..................................................................................................................................55 CRISIL RATING ............................................................................................................................................................56 FORMULA USED ...........................................................................................................................................................56

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Power Sector- Introduction The power sector has registered significant progress since the process of planned development of the economy began in 1950. Hydro -power and coal based thermal power have been the main sources of generating electricity. Nuclear power development is at slower pace, which was introduced, in late sixties. The concept of operating power systems on a regional basis crossing the political boundaries of states was introduced in the early sixties. In spite of the overall development that has taken place, the power supply industry has been under constant pressure to bridge the gap between supply and demand. The Power Sector has been receiving adequate priority ever since the process of planned development began in 1950. The Power Sector has been getting 18-20% of the total Public Sector outlay in initial plan periods. Remarkable growth and progress have led to extensive use of electricity in all the sectors of economy in the successive five years plans.

Power Sector Snapshot

Installed Capacity 1.91% 0.06% 12.66%

27.68%

Northern Region Western Region

28.72%

Southern Region Eastern Region 28.97%

North Eastern Region Islands

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Source of Generation Southern Region 12%

2% 30%

HYDRO Thermal

56%

RES NUCLEAR

Sources of Generation Western Region 3% 5% 19%

Source of Generation Eastern Region 1% 0%

HYDRO

15%

Thermal

Thermal

RES

73%

NUCLEAR

HYDRO

84%

RES NUCLEAR

Source of Generation North Eastern Region 2%0% HYDRO Thermal RES NUCLEAR

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7% 0% 6% HYDRO

47% 51%

Source of Generation Islands

Thermal 87%

RES NUCLEAR

Total Installed Capacity: Sect

MW

%age

State Sector

71,250

55.4

Central Sector

43,231

33.7

Private Sector

13,951

10.9

Fuel

MW

%age

Total Thermal

84,400

65.6

Coal

69,616

54.1

Gas

13,582

10.6

Oil

1,202

0.9

Hydro

33,942

26.5

Nuclear

3,900

3

Renewable

6,191

4.8

Total

1,28,432

or

Total

Central and State sector are the dominant players in the generation with private sector contributing only 10.9% of total installed capacity

1,28,432

Coal is the primary source of fuel for generation and accounts for over 50% of generation.

2.High Voltage Transmission Capacity: Capacity

MVA

Circuit KM

765/800 KV

--

2,037

400 KV

91,052

73,753

220 KV

1,52,967

112,901

HVDC

3,000

5,872

[Trans.Dn] 3.Per Capita Consumption of Electricity: (Year 2004-05)

606 KWH / Year [Pl. Dn.]

4.Rural Electrification: No. of Villages (Census 1991)

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593,732

Per capita consumption of electricity is much lower than those of developed countries like USA(13242 Kwh/year), Russia(5480 kwh/year), (Brazil (1884.5 kwh/ year), China (1378 kwh/ year).

Power for all (2012) aims at Sufficient power to achieve GDP growth rate of 8% Reliable of power Quality power Optimum power cost Commercial viability of power industry Power for all

Villages Electrified 30th May 471,360 2006) Electrification %age Rural 2001)

Households

79.40% (Census 138,271,559

Having access

60,180,685

Electrification %age

44%

5.Power Situation: (April 2006-January 2007) Demand

Met

Surplus/ Deficit

Energy

572,812 MU

519,656 -9.30% MU

Peak Demand

100,403 MW

86,425 MW

-13.90%

Structure of power supply industry In December 1950 about 63% of the installed capacity in the Utilities was in the private sector and about 37% was in the public sector. The Industrial Policy Resolution of 1956 envisaged the generation, transmission and distribution of power almost exclusively in the public sector. The Electricity (Supply) Act, 1948, envisaged creation of State Electricity Boards (SEBs) for planning and implementing the power development programs in their respective States. The Act also provided for creation of central generation companies for setting up and operating generating facilities in the Central Sector. The Central Electricity Authority constituted under the Act is responsible for power planning at the national level. GOI promulgated Electricity Regulatory Commission Act, 1998 for setting up of Independent Regulatory bodies both at the Central level and at the State level viz. The Central Electricity Regulatory Commission (CERC) and the State Electricity Regulatory Commission (SERCs) at the Central and the State levels respectively.

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National Load Dispatch Centres

Further amendments in electricity Act were introduced in 2003. The provisions provided in the Electricity Act 2003 are as follows: Open access allowed in transmission: The transmission sector was opened up to private investment through the grant of a license by an appropriate authority. A captive generation unit can move power to the end-use destination (captive use) without the payment of any surcharge. The planning, co-ordination and development of transmission systems at inter-state levels is the responsibility of the Central transmission utility (CTU), whereas intra-state transmission of electricity will be controlled by state transmission utilities (STU). The formation of a National Load Dispatch Centre (NLDC) at the national level for optimum scheduling and dispatch of electricity between Regional Load Dispatch Centres (RLDCs). Establishment of RLDCs (they have already been set up, as specified in the Act). RLDCs have to monitor grid operations, monitor the quantity of electricity transmitted through the regional grid and exercise supervision and control of the inter-state transmission system. The respective state governments have to establish state load dispatch centres (SLDCs), which will be responsible for optimum scheduling, dispatch of electricity and real time operations to ensure stability in respect of the intra-state transmission of electricity. The transmission licensees have to provide non-discriminatory access to their transmission systems, on payment of transmission charges along with a cross-subsidy surcharge as specified by the CERC/SERC. NLDC, RLDC, SLDC, CTU, STU and other transmission licensees not to engage in trading of electricity. Apart from these, some of the provisions for transmission included in the National Electricity Policy are as follows:

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The augmentation of transmission capacity, in view of the aggressive capacity expansion plans in generation. The requirement of additional transmission capacity to supplement the increase in generation capacity needs to be considered to avoid a mismatch between generation and transmission facilities. Development of the national grid for providing adequate infrastructure for inter-state transmission of power and ensuring the optimum utilisation of generation capacity from the surplus to the deficit regions. The responsibility of network planning and development rests with CTU and STU (based on the National Electricity Plan) in coordination with all the concerned agencies specified in the Act. Network expansion has to be planned and implemented factoring in the capacity needs for open access, which is to be gradually implemented by states as per their stage-wise schedule. For a secure and reliable operation of the grid, adequate margins and redundancy levels in the transmission system should be created as per global standards and practices. A national transmission tariff framework needs to be implemented by CERC for transmission pricing. The tariff would be determined on the basis of distance, direction and quantum of flow. At present, the CERC has recommended the usage of the regional postage stamp method. A proper infrastructure network and appropriate planning are required if some other method has to be adopted.

Problems confronting the sector The major reasons for inadequate, erratic and unreliable power supply are: inadequate power generation capacity; lack of optimum utilization of the existing generation capacity; inadequate inter-regional transmission links; inadequate and ageing sub-transmission & distribution network leading to power cuts and local failures/faults; large scale theft and skewed tariff structure; slow pace of rural electrification; inefficient use of electricity by the end consumer. Strengths and opportunities in the sector Abundant coal reserves (enough to last at least 200 years). Vast hydroelectric potential (150,000 MW). Large pool of highly skilled technical personnel. Impressive power development in absolute terms (comparable in size to those of Germany and UK). Expertise in integrated and coordinated planning (CEA and Planning Commission). Emergence of strong and globally comparable central utilities (NTPC, POWERGRID,). Wide outreach of state utilities. Enabling framework for private investors.

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Well laid out mechanisms for dispute resolution. Political consensus on reforms. Potentially, one of the largest power markets in the world. Objectives To provide 'Power on Demand by 2012'. To make the sector commercially sound and self-sustaining. To provide reliable and quality power at an economic price. To achieve environmentally sustainable power development. To promote general awareness to achieve consensus on the need for reforms.

Generation Based on the projections of demand made in the 16th Electric Power Survey, additional generation capacity of over 1,00,000 MW needs to be added to ensure 'Power on Demand by 2012'. This amounts to nearly doubling the existing capacity of about 1,00,000 MW.

Resources In India, power generation is largely dependent on coal, gas, nuclear and hydroelectric sources. Nonconventional sources of energy such as wind and solar energy, account for a small proportion of the total installed capacity. Fuel oil and diesel are largely used in captive power plants Coal According to the Geological Survey of India, in January 2005, the total coal reserves of India were estimated at around 248 billion tonnes (including the non-recoverable reserves under riverbeds or urban areas). A significant proportion of the Indian coal reserves are concentrated in the eastern and southeastern regions. Jharkhand, Orissa, Madhya Pradesh, Chhattisgarh, West Bengal and Andhra Pradesh account for about 85 per cent of the country‘s total coal reserves. At the current rate of production (around 374.9 million tonnes in 2004-05, however, this does not include lignite production), the proven reserves will last for approximately 245 years. Power generation sector is the largest enduser of coal in India. In 2004-05, it accounted for almost 75 percent of total coal consumption

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Although India has abundant coal reserves, they are of poor quality. Indian coal has an average calorific value of around 3,500 kcal per kg and an ash content of around 40 per cent, as compared to imported coal which has a calorific value of around 6,500 kcal per kg and an ash content of around 10 per cent. The lower ash content of imported coal results in marginally better operational efficiency and lower ash disposal costs partially compensate for its higher cost. In view of the high shipping costs, coal is imported mainly from Australia, South Africa and the Southeast Asian countries (such as Indonesia and Malaysia). However, coal imports are economical only for plants based in the coastal region, due to high inland transportation costs. At present, imported coal accounts for less than 5 per cent of the total coal consumption for power generation. Natural Gas The natural gas-based power generation capacity (including naphtha-based capacity) accounted for around 10 per cent of the total installed capacity as on March 31, 2005. Out of the total natural gas produced in India, 38 per cent is consumed in the generation of electricity and 25 per cent in the production of fertiliser. The consumption of natural gas for power generation and other end-uses (such as fertiliser) is expected to increase significantly in the next 5-10 years as natural gas is an environment friendly and economic fuel.

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Hydroelectric Power Station The total hydroelectric potential in India is estimated to be around 84,000 MW (at 60 per cent load factor), of which 18 per cent has been developed and another 6-7 per cent is under development. The hydroelectric potential of different regions varies. The North-eastern region (which has the lowest demand for power) has the highest hydroelectric potential, at 38 per cent (around 32,000 MW), followed by the northern and southern regions, at 36 per cent and 13 per cent, respectively. The extent of the development of hydroelectric potential also varies significantly across regions. It is highest in the southern region, around 37 per cent, followed by the northern, western and eastern regions, at 33 per cent, 18 per cent and 9 per cent, respectively. The hydroelectric potential in the North-eastern region is the least developed, at around 5 per cent. With the objective of expediting hydropower development in a systematic manner, the Central Electricity Authority completed a ranking study of the remaining hydro potential sites for all the basins in the country in 2001-02. The ranking of hydro sites has been carried out based on the weight age criteria for various aspects involved in the development of hydro schemes. Considering these aspects, the schemes have been graded in A, B and C categories in order of their priority for development. Nuclear power Nuclear power plants supply around 17 per cent of the electricity consumed worldwide. In India, nuclear power accounts for less than 3.2 per cent of the total electricity generated, compared to over 50 per cent in France and Japan. As on March 31, 2005, the installed capacity of nuclear power plants in India was around 2,770 MW. The government plans to increase the installed capacity of nuclear power plants to 20,000 MW by 2020. Although India has achieved a high degree of self-reliance in the design and construction of nuclear power plants, the capital cost of nuclear power projects is significantly higher than that of coal-based and hydroelectric plants. This could be attributed to the stringent and continuously evolving safety norms for nuclear power plants, and the long gestation period (gestation periods for nuclear power projects in India have been long (5-7 years), largely due to technological complexity and the difficulty in obtaining adequate funds)

Target 2012 The following sector wise capacity addition targets have been firmed up for aggregate capacity addition of 1,07,000 MW by 2012. All Figures in MW

X Plan

XI Plan

Total

Ministry of Power

23000

23500 46500

Ministry of Coal

210

1500

1710

Department of Atomic Energy

1220

5160

6380

Ministry of Non Conventional Energy Sources

4055

6625

10680

Total Central Sector

28485

36785 65270

Central Sector

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Total State Sector

8300

10600 18900

Total Private Sector

9400

13500 22900

Overall Capacity Addition (approx.)

46000

61000 107000

It is estimated that for building over 1,00,000 MW of additional power capacity and associated transmission & distribution infrastructure, nearly Rs. 8,00,000 crores of investments would be needed in the next decade. The problem of non-availability of escrow capacity with most State utilities has been holding up the financial closure of most private sector projects. In view of the current policy against giving counter guarantees and pending fructification of reforms measures, the Ministry has taken steps to set up alternate payment security mechanism for the investors as an interim resource mobilisation strategy. The mechanism has been evolved in consultation with leading financial institutions like IDBI, ICICI, SBI Caps etc. on the basis of a memorandum of agreement/ understanding to be signed with the reforming States wherein the States agree on milestone based package of reforms like restructuring of SEBs, setting up of SERCs, reduction in T&D losses, 100% metering, improvement in PLF, energy audit etc. The policy framework has also been liberalised to encourage domestic/Foreign Direct Investment in power sector. The measures taken in this regard include allowing Foreign Direct Investments in generation, transmission, distribution and power trading on the automatic route without any monetary ceiling.

Transmission and Distribution Key concerns The Indian T&D system is characterised by exceptionally high losses, over 30 per cent, as compared to developed countries, where losses are around 10-15 per cent. Losses in retail distribution account for a significant proportion of the total losses in the Indian T&D system. T&D losses Transmission and distribution losses can be classified into two main categories: Technical losses The technical component of T&D losses has an inverse relationship with the voltage configuration of the T&D system. bulk power of high voltage (400, 220, and 132 kv), over long distances, is estimated to result in a loss of 4-5 per cent of the total energy transmitted, while distribution at low voltage levels is estimated to lead to a loss of 15-18 per cent of the total energy transmitted. Commercial losses Commercial losses occur due to non-metering, non-billing or pilferage of power. These losses can be largely attributed to faulty meters, reading errors, unmetered supply and unauthorised connections. As a result of inadequate metering arrangement, it is difficult to estimate the extent of the loss and attribute it to a specific reason. Reasons for high T & D losses:

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A weak and inadequate T&D system A large-scale rural electrification programme (due to low voltage distribution lines). Numerous transformation stages: This results in a high component of transformation losses. Improper load management Pilferage and theft of energy Given the large distribution network, multiple transformation stages and large-scale rural electrification in India, the optimal level of T&D losses has been recommended at around 15 per cent. Lack of investment is one of the main reasons for the weak and inadequate T&D infrastructure in India. Ideally, investment in the T&D sector should match that in generation. However, in India, the emphasis has been on adding generation capacity and rural electrification and the average outlay for T&D in the Five Year Plans has been approximately 25-30 per cent of the total outlay for the power sector. The primary reasons for inadequate investments in the transmission sector are: Focusing on rural electrification is resulting in higher investments in low-voltage distribution lines; Emphasis on capacity additions in the generation sector; Proliferation of low-tension (LT) lines; and Increase in the share of LT lines in the T&D network in India (following the emphasis on rural electrification), which has resulted in a load density that is 4-5 times lower than that of developed countries like Japan. In addition, the ratio of the lengths of low-tension (LT) and high-tension (HT) lines has increased significantly over the past three decades. As losses are inversely related to voltage, the higher share of low-voltage lines results in higher T&D losses.

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Project - Cost INTRODUCTION The cost of a power project depends on the type of fuel used. The choice of fuel for a power plant depends on several factors listed below Relative cost of generation Availability of fuel Transportation constraints Environmental hurdles The capital cost of power plants also vary significantly based on the source of energy, infrastructure, plant size, technology, equipments and interest costs incurred during construction. A power generation project has three party tariff structure. 1. The fixed part of tariff comprising the interest on long term debt, interest on working capital, depreciation, operation and maintenance expenses and taxes. 2. The variable part of tariff comprising the cost of primary and secondary fuel. 3. Unscheduled interchange to account for the variation between the actual generation and the scheduled generation. Debt-equity ratio, ratio of incentive, plant load factor, exchange rate are the factors which affect the generation tariff significantly.

FACTORS INFLUENCING THE COST OF GENERATION Let us analyze the factors which affect the cost of power generation. Fuel There are three major options for generating electricity: Thermal, hydroelectric and nuclear. Thermal power plants can be based either on coal, on natural gas (including liquefied natural gas)or on naphtha. Power plants can also be based on other hydrocarbon fuels like fuel oil and diesel but such plants smaller in size and are primarily used for captive power generation. The demand for power varies with the time of the day and the season. A part of the demand is always present (known as base-load), while the balance fluctuates with the time of the day (known as peaking demand). The choice of fuel for a power plant depends on the type of demand that the plant is expected to meet. In general, in order to minimize the variable costs, power plants with the lowest variable costs (fuel costs) should be employed to meet the base demand, while those with a higher variable cost should be employed to meet the peaking demand. Coal-based power plants have lower variable costs than those based on naphtha or natural gas. However, coal-based power plants have high capital costs which result in high fixed costs. In addition, these plants cannot vary their output with variation in demand. Hence, coal-based plants are largely used to meet base demand. This results in lower fixed costs per unit, due to higher PLF. Gas and naphtha-based plants have higher variable costs and are more flexible in terms of varying their output. Hence, these plants are better suited for meeting peak demand.

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Hydroelectric plants have very low variable costs of generation and are the most flexible in terms of varying output. However, the total amount of energy that hydroelectric plants can produce is dependent on the rainfall. Hence, hydroelectric plants are used exclusively to meet peaking demand. Nuclear power plants have the highest capital costs and the lowest variable (fuel) costs. Hence, these plants are ideal for meeting base-load demand. Cost of Fuel The delivered price of any fuel can vary significantly depending on the source of supply (imported or indigenous), and the distance of the plant from the source of supply. In India, coal is generally transported from mines to power plants through the railways. However, the high cost of transportation results in a significant increase in per unit cost of coal. As a result, power plants located near coal mines (pit-head plants) are able to generate power at a fairly lower rate than plants that need to transport coal over long distances. Fuels: Comparison Coal

Gas

Naptha

Capital cost (Rs million per MW)

45

35

30

Gestation period (months)

48-52

24-30

18-30

Fuel cost (paise per kwh)

124

115

517

Application

Base load

Intermediate

Peak load

Emissions

High

Low

Low

Indigenous availability

High

Low

Medium

Indigenous quality

Poor

Good

Good

Imports

Coastal Plants could import coal from Australia and South Africa

Coastal plants could import LNG from West Asia. Pipeline infrastructure necessary for distribution to inland power plants.

Imports are feasible.

Import Quality

Good

Good

Good

Infrastructure required

Handling capacity at ports limited

Receiving terminals, re gasification plants, pipelines, etc.

Handling capacity at port limited

Deregulation will increase in faster price increase

Under priced in comparison to international prices. With increased proportion of

Domestic prices to move in line with the international prices.

Fuel price outlook

Domestic

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deregulated gas flowing in the market, prices are expected to rise in the future. International

Prices will continue to be volatile and will move in line with the crude oil prices.

Capital Cost Power projects are highly capital intensive projects with a gestation period of 4-6 years. The fixed component of power tariff is based on the capital cost of the project. The capital cost of most projects in private sector are assumed to be at Rs 40 – 50 million per MW for coal based plants and Rs 25 – 40 million per MW for gas based plants and Rs 45 – 60 million per MW for hydroelectric power plants. The various factors that affect the cost of capital are Source of energy The most important factor that influences the cost of a power project is the source of energy and the type of fuel used. The cost of setting up a nuclear power plant is the highest due to the complex technology involved, the incorporation of safety measures and the long gestation period (6-8 years). The cost of setting up a coal-based plant is lower than nuclear plants and higher than those based on natural gas, naphtha and fuel oil. The high cost of coal-based plants is attributed to the additional equipment required, such as coal-handling and ash-handling plants. It is difficult to estimate the cost break-up of hydroelectric power plants, due to their long gestation period and significant variations depending on the size, location and terrain. Infrastructure Infrastructure cost depends on the availability of water, transportation infrastructure and power evacuation and transmission system. Water is used for the purpose of generating steam and for cooling. Proximity to a source of water can reduce the investments in reservoir, pipelines and pumping equipment. A power plant located near coastal areas requires additional investments in demineralization of the water. Power plants are generally located near coal mines or gas pipelines in order to save transportation costs. Pit-head plants (power plants located near coal mines) use a conveyor belt to transport coal from the mine to the plant stockyard. However, in case of power plants located away from coal mines, investments are required in a railway siding. This can increase capital costs, depending on the distance of the site from the nearest station. Similarly, in case of gas-based projects, a pipeline would have to be laid from the main pipeline (for natural gas) or the receiving terminal (for LNG) up to the project site. Power plants based on imported fuel require an additional investment in jetties or receiving terminals and re-gasification plants (for LNG). For power plants based on imported coal, the cost of a jetty and a conveyor belt is around Rs 1.5 billion for a 1,000 MW plant (requiring approximately 3 million tonne per annum of coal). The minimum economic size of an LNG receiving terminal is 2.5 million tonne per

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annum (with a capital cost of Rs 15 billion), which is adequate to support a generation capacity of 2,000 MW. The distance of the power plant from the transmission substation determines the level of investments in a transmission line and/or a substation. A high-tension transmission line can cost up to Rs 5-7 million per km. Size of Plant Significant economies of scale exist in the capital costs of power plants. A larger plant costs less, in terms of cost per unit of capacity. In the case of a coal-based power plant, economies of scale exists in the capital cost of coal and ash-handling equipment and control and instrumentation (C&I) equipment. Larger units also have a better thermal efficiency and lower operation and maintenance cost. Equipments Equipment costs account for almost 75% of total cost of a thermal plant. Power plants based near urban areas or in ecologically sensitive regions would have higher capital costs, due to the stringent design conditions imposed on the equipment in terms of thermal efficiency and emission standards, resulting in the need for additional pollution control equipment. In addition, if a coal-based power plant includes a captive coal washery, it could increase capital costs. However, the use of washed coal results in a reduction in transportation costs (as washing reduces the ash content of the coal) and ash-disposal costs. Interest during Construction (IDC) The construction period of a power project varies between 2.0-3.0 years for a gas or naphtha-based project to 3.5-4.0 years for a coal-based project. The long gestation period and the capital-intensive nature of power projects, results in accumulation of interest on debt till the commissioning of the plant. Interest during construction can account for almost 15 to 20 percent of the total cost of the project. The main reason for high IDC cost is the delays in the implementation of a project. Engineering, Procurement and Construction (EPC) contracts In order to ensure timely execution of the project the services of an EPC contractor is generally employed. The EPC contractor undertakes the turnkey execution of the project on a fixed time and fixed price basis, while guaranteeing the performance of the power plant in accordance with the specifications stipulated by the developer. . In general, power plants executed on the basis of an EPC contract cost higher.

COMPUTATION OF TARIFF Method The most common method of pricing power is a two-part tariff formula, where the tariff consists of a fixed component (also known as the capacity charge) and a variable component. Further another component is taken during the computation of tariff known as unscheduled interchange charges. In India, under the two-part tariff policy, independent power producers (IPPs) are offered a guaranteed post-tax return of 14 per cent on equity, at a PLF of 80 per cent. In addition, there is a provision for additional return on equity as an incentive for generation above this normative level.

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The fixed component of the tariff is mainly dependent on the capital cost of the project. In addition, the terms of the Power Purchase Agreements (PPAs) regard O&M expenditure, rate of incentive (for an improvement in performance), financial structure of the project, and the security package for credit enhancement (which would have an impact on interest rates) as factors affecting the fixed component. The fixed component of the tariff ensures that the power producer is able to recover the fixed expenses and earn a return on investment, irrespective of the actual generation. Hence fixed charge comprises of 1. 2. 3. 4. 5. 6. 7.

Interest on long-term debt Depreciation O&M expenses (including insurance expenses) Return on equity Incentive return on equity Interest on working capital Taxes

Variable Component The variable component of the tariff covers the variable cost of operation of the power plant and also comprises the primary and secondary fuel cost and other costs (if any) that are directly dependent on the level of generation. The tariffs vary across projects when variable costs are compared due to the differences in the fuel cost, transportation cost, and due to differences in the thermal efficiency. Hence, variable charges comprise of 1. Cost of primary fuel 2. Cost of secondary fuel (if any)

Unscheduled Interchange Charges Variation between actual generation or actual drawal and scheduled generation or scheduled drawal is accounted through UI charge. The UI for a generating station is equal to its actual generation minus scheduled generation and is calculated for each 15-minute time block. The UI rates are shown in table below

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Average frequency of time block (Hz) Below Not below UI Rate ---50.5 0 50.5 50.48 0.06 50.48 50.46 0.12 50.46 50.44 0.18 50.44 50.42 0.24 50.42 50.4 0.3 50.4 50.38 0.36 50.38 50.36 0.42 50.36 50.34 0.48 50.34 50.32 0.54 50.32 50.3 0.6 50.3 50.28 0.66 50.28 50.26 0.72 50.26 50.24 0.78 50.24 50.22 0.84 50.22 50.2 0.9 50.2 50.18 0.96 50.18 50.16 1.02 50.16 50.14 1.08 50.14 50.12 1.14 50.12 50.1 1.2 50.1 50.08 1.26 50.08 50.06 1.32 50.06 50.04 1.38 50.04 50.02 1.44 50.02 50 1.5 50 49.98 1.56 49.98 49.96 1.62 49.96 49.94 1.68 49.94 49.92 1.74 49.92 49.9 1.8 49.9 49.88 1.86 49.88 49.86 1.92 49.86 49.84 1.98 49.84 49.82 2.04 49.82 49.8 2.1 49.8 49.78 2.19 49.78 49.76 2.28

Average frequency of time block (Hz) Below Not below UI Rate 49.76 49.74 2.37 49.74 49.72 2.46 49.72 49.7 2.55 49.7 49.68 2.64 49.68 49.66 2.73 49.66 49.64 2.82 49.64 49.62 2.91 49.62 49.6 3 49.6 49.58 3.09 49.58 49.56 3.18 49.56 49.54 3.27 49.54 49.52 3.36 49.52 49.5 3.45 49.5 49.48 3.61 49.48 49.46 3.77 49.46 49.44 3.93 49.44 49.42 4.09 49.42 49.4 4.25 49.4 49.38 4.41 49.38 49.36 4.57 49.36 49.34 4.73 49.34 49.32 4.89 49.32 49.3 5.05 49.3 49.28 5.21 49.28 49.26 5.37 49.26 49.24 5.53 49.24 49.22 5.69 49.22 49.2 5.85 49.2 49.18 6.01 49.18 49.16 6.17 49.16 49.14 6.33 49.14 49.12 6.49 49.12 49.1 6.65 49.1 49.08 6.81 49.08 49.06 6.97 49.06 49.04 7.13 49.04 49.02 7.29 49.02 49 7.45 49 48.98 0 48.98 48.96 0

Formula Used The payment due to the generation company by the buyer in any year is computed as follows:

Total payment due = Fixed charges + variable charges + UI Assumptions for the calculations

Interest on Long Term Debt A debt-equity ratio of 2.33:1.00 has been assumed. This is also the norm mandated by the UMPP projects guidelines. This is the most common norm followed by Indian financial institutions for funding private sector power projects. Further, a break-up of the loan component into domestic debt and foreign debt has been assumed. Representative interest rates have been assumed for rupee and foreign currency debts.

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The repayment period is assumed to be 12 years after the commencement of commercial operations by the power project. The interest and the principal is assumed to be payable on a quarterly basis.

Interest on working capital Working capital for a coal based/ lignite-fired generating station has been calculated on the following basis: Fuel inventory is assumed at one and half months for pit-head generating stations and 2 months for non-pit-head generating stations corresponding to target availability. O&M expenses are assumed for 1 month. Receivables are assumed at 2 months of fixed and variable charges for sale of electricity calculated on target availability. Maintenance spares at the rate of 1 per cent of the historical cost escalated at the rate of 6 per cent per annum from the date of commercial operation. Working capital has been assumed to be on a normative basis and the rate of interest applicable will be the short-term prime lending rate of the State Bank of India. A bank finance of 75 per cent of the gross working capital requirement has been assumed (a 25 per cent working capital margin has been assumed).

Depreciation Charges Depreciation is assumed to be allowed over the”fair life of the assets‘at the rate notified by CERC. The life of the project has been assumed as 25 years. 90% of the capital Rs in employed is considered for depreciation. Land cost should not be Year million/MW considered for depreciation.

O&M charges Normative operation and maintenance charges have been assumed as per CERC guidelines and appreciated at the rate of 4%. The O&M rates are shown in the table below.

Operation and Maintenance Charges

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034

1.190 1.238 1.287 1.339 1.392 1.448 1.506 1.566 1.629 1.694 1.761 1.832 1.905 1.981 2.061 2.143 2.229 2.318 2.411 2.507 2.607 2.712 2.820 2.933 3.050 3.172

Return on equity The return on equity has been calculated on the original equity of the project, at the rate of 14 per cent per annum on a PLF of 80 per cent.

Incentive for Thermal Generation The Target Availability (TA) has been specified by the Commission based on the performance that can be achieved by the utility which will determine the level of fixed charge recovery. The Commission’s present orders lay down 80% availability level for full fixed cost recovery. In case of performance below this availability level, pro-rata reduction in recovery of fixed charges is provided. As regards the incentive, the provision is that it will be @ 50% of fixed charges in paise/kwh on actual generation beyond 77% PLF upto 90% PLF subject to a ceiling of 21.5% paise/kwh. Beyond 90%, the incentive rate is reduced to half. This rate has been assumed as per CERC guidelines.

Tax Tax is treated as a component of fixed costs and the guaranteed return on equity is on a post-tax basis. A tax rate of 33 per cent is assumed for calculations.

Fuel A PLF of 80 per cent is assumed for calculating fuel requirements. The calorific value, SHR and fuel prices have been suitably assumed, depending on the type of the fuel. No increase in the price of fuel has been assumed for the entire life of the project. This is because a rise in cost of fuel will be a pass through cost.

Discounting rate In order to compare two projects, a levelised tariff over the life of the project is calculated, by discounting the tariffs over the life of the project. A discounting rate of 10.6 per cent has been assumed as mentioned by CERC for the period of October 2006 – March 2007.

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Sample Case: Assumed Capacity of Plant(MW)

4000

Interest on long term debt Domestic debt interest rate

10%

Foreign Debt interest rate

7%

% of foreign debt

80%

% of domestic debt

20%

Debt %

70.00%

Equity %

30.00%

PLF

80%

Total Distance from Coal Mine (km)

70

Tax Rate

33%

Repayment period of Debt payable quaterly

12 years

Discount rate

10.60%

Target Availability

100%

Project Cost(Rs million) Cost per MW

35

Unit

Coal Domestic (pithead) Kg

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Transportation Cost/ price Rs/Unit 1000 Km per unit

0.9

0.8

Calorific Value Kcal/unit

3500

Heat Rate kcal/kwh

2500

Tariff Computation of Various Components

Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033

Interest on Depreciati Long term Loan on 0.271 0.193 0.256 0.193 0.240 0.193 0.223 0.193 0.204 0.193 0.184 0.193 0.162 0.193 0.139 0.193 0.113 0.193 0.085 0.193 0.055 0.193 0.022 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193 0.193

ROE 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243 0.243

Interest on Total working O&M Fixed per unit capital Charges Tax Incentive Cost Fuel Cost cost 0.039 0.172 0.0801 0.1075 1.1055 0.73 1.8397 0.040 0.179 0.0801 0.1075 1.0983 0.73 1.8326 0.040 0.186 0.0801 0.1075 1.0903 0.73 1.8245 0.041 0.193 0.0801 0.1075 1.0813 0.73 1.8155 0.042 0.201 0.0801 0.1075 1.0712 0.73 1.8054 0.043 0.209 0.0801 0.1075 1.0598 0.73 1.7941 0.044 0.217 0.0801 0.1075 1.0472 0.73 1.7815 0.045 0.226 0.0801 0.1075 1.0331 0.73 1.7674 0.046 0.235 0.0801 0.1075 1.0175 0.73 1.7517 0.047 0.245 0.0801 0.1075 1.0000 0.73 1.7343 0.048 0.254 0.0801 0.1075 0.9807 0.73 1.7150 0.049 0.265 0.0801 0.1075 0.9593 0.73 1.6935 0.051 0.275 0.0801 0.1075 0.9493 0.73 1.6836 0.052 0.286 0.0801 0.1075 0.9617 0.73 1.6960 0.053 0.298 0.0801 0.1075 0.9746 0.73 1.7088 0.055 0.309 0.0801 0.1075 0.9880 0.73 1.7223 0.057 0.322 0.0801 0.1075 1.0020 0.73 1.7363 0.058 0.335 0.0801 0.1075 1.0166 0.73 1.7509 0.060 0.348 0.0801 0.1075 1.0318 0.73 1.7661 0.062 0.362 0.0801 0.1075 1.0476 0.73 1.7819 0.064 0.377 0.0801 0.1075 1.0642 0.73 1.7984 0.066 0.392 0.0801 0.1075 1.0814 0.73 1.8156 0.068 0.407 0.0801 0.1075 1.0993 0.73 1.8335 0.071 0.424 0.0801 0.1075 1.1180 0.73 1.8522 0.073 0.440 0.0801 0.1075 1.1375 0.73 1.8717

Formula Used Total payment due = Fixed charges + variable charges + UI Tariff for the first year: Rs. 1.7852 / Kwh Levelised Tariff: Rs. 1.746025/ Kwh

Profitability The profit for IPPs is determined by two factors-the assured return on equity (including the incentive on higher capacity generation) and the operating efficiency. The two-part tariff formula is calculated on the basis of pre-determined norms of operating efficiency, such as the heat rate, oil consumption and O&M expenses. If the power project attains higher levels of efficiency than those stipulated in the norms, it will make higher profits.

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Station heat rate Since the computation of fuel cost is based on the contracted SHR and not the actual heat rate achieved, a producer can improve his profitability by improving the efficiency of the power plant. However, this additional profit will decrease gradually, as the efficiency of the plant declines due to deterioration of the equipment over the life of the project. O&M charges The maximum prescribed norm for O&M expenses is as stipulated above in the tariff computation. However, based on the experience of existing power plants in the country, the actual expenses could be significantly lower at 1-1.5 per cent of gross fixed assets. Auxiliary consumption IPPs can increase their profits by reducing their auxiliary consumption. The norm for auxiliary consumption is fixed as shown below: Coal Based Unit: Auxiliary Consumption Type

Percentage of generation With Cooling tower

Without Cooling Tower

200 MW

9

8.5

500 MW

9

8.5

However, modern power plants could have an auxiliary consumption as low as 7 per cent and 1 per cent for coal and gas-based plants, respectively. This could result in higher sales volumes of electricity, resulting in additional revenues.

Sensitivity Analysis

Key findings of the analysis are explained below:

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For a given capital cost, an increase in the debt-equity ratio results in a decline in the levelised tariffs. This is attributed to the higher cost of servicing debt, as compared with the cost of servicing equity. However, the sensitivity would change, depending on factors such as the proportion of foreign debt/equity and exchange rate fluctuations. The levelised tariffs decline with an increase in the PLF. Although the incentive charges (for attaining PLFs over 68.5 per cent) increase in line with the PLF, they are offset by the lowering of fixed costs per unit as a result of increased power generation. This results in a decline in overall tariffs.

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ULTRA MEGA POWER PROJECTS The Government of India has envisaged capacity addition of 100,000 MW by 2012 to meet its Mission of Power to All. Achievement of this target also requires the development of large capacity projects at the national level to meet the requirements of a number of States. Section-63 of the Electricity Act, 2003 provides that the Regulatory Commissions shall adopt the tariff if it is determined through transparent process of bidding in accordance with the guidelines issued by the Central Government. This aims at moving away from cost-plus support for tariff determination and it is expected to further encourage private sector investment. Guidelines for competitive bidding for determination of tariff for procurement of power by distribution licensees were issued on 19th January, 2005. The policy stipulates that all future requirement of power needs to be procured competitively by distribution licensees except in cases of expansion of existing projects and where regulators will need to resort to tariff determination based on norms. Recognizing the fact that economies of scale leading to cheaper power can be secured through development of large size power projects, Ministry of Power, CEA, and Power Finance Corporation are working together for development of five ultra mega power projects under tariff based competitive bidding route. These projects will be awarded to developers on Build, Own, Operate (BOO) basis. The Ultra Mega Power Projects each with a capacity of 4000 MW, would also have scope for further expansion. The size of these projects being large, they will meet the power needs of a number of states through transmission of power on regional and national basis.

Management Structure: PFC has designated a core team to coordinate all activities related to the Ultra Mega Projects. A senior executive has been appointed as Chief Executive for each SPV. The primary role of the core team will be to perform the initial ground work for various projects including formation of different Shell Companies (SPVs) by registering them simultaneously. The SPVs will carry out site visits in coordination with CEA and Ministry of Coal etc. to narrow ideal locations for power plant having proximity to water source and coal blocks for pit head locations as well as port facility for coastal locations. Various surveys and studies will be taken up by the core team through the consultants appointed for each assignment. Finally, the SPV will invite EOI for exploring the prospective bidders and invite bids based on tariff quoted. The SPVs will be transferred to the successful bidders along with all assets and liabilities.

Role of Shell Companies The role of the shell companies are to facilitate following activities: 1. 2. 3. 4. 5. 6. 7.

Appointment of Consultant to undertake studies and preparation of Project Report Initiate land acquisition proceedings Allocation of fuel blocks for pit-head projects Allocation of water through State Government/concerned statutory authority Appointment of Consultant for ICB, preparation of document and evaluation of bids Obtain various approvals and statutory clearances Commitment of Payment Security Mechanism (PSM) and Off-take of power by Distribution Utilities.

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8. Initiate action for development of the power evacuation system and grid tolerance considering the addition of capacity by these projects. 9. Green field rating of project

RFP Standard documentation to be provided by the procurer in the RFP shall include I.

Structure of tariff to be detailed by bidders;

II.

PPA proposed to be entered with the selected bidder.

The model PPA proposed in the RFQ stage may be amended based on the inputs received from the interested parties, and shall be provided to all parties responding to the RFP. No further amendments shall be carried out beyond the RFP stage; III.

Payment security to be made available by the procurer.

The payment security indicated in the RFQ stage could be modified based on feedback received in the RFQ stage. However no further amendment to payment security would be permissible beyond the RFP stage. IV.

Bid evaluation methodology to be adopted by the procurer including the discount rates for evaluating the bids.

The bids shall be evaluated for the composite levelised tariffs combining the capacity and energy components of the tariff quoted by the bidder. In case of assorted enquiry for procurement of base load, peak load and seasonal power, the bid evaluation for each type of requirement shall be carried out separately. The capacity component of tariffs may feature separate non-escalable (fixed) and escalable (indexed) components. The index to be adopted for escalation of the escalable component shall be specified in the RFP. For the purpose of bid evaluation, median escalation rate of the relevant fuel index in the international market for the last 30 years for coal and 15 years for gas / LNG (as per CERC’s notification in (vi) below) shall be used for escalating the energy charge quoted by the bidder. However this shall not apply for cases where the bidder quotes firm energy charges for each of the years of proposed supply, and in such case the energy charges proposed by the bidder shall be adopted for bid evaluation. The rate for discounting the combination of fixed and variable charges for computing the levellised tariff shall be the prevailing rate for 10 year GoI securities; V.

The RFP shall provide the maximum period within which the selected bidder must commence supplies after the PPA is entered into by the procurer with the selected bidder, subject to the obligations of the procurer being met. This shall ordinarily not be less than four years from the date of signing of the PPA with the selected bidder in case supply is called for long term procurement. The RFP shall also specify the liquidated damages that would apply in event of delay in supplies.

VI.

Following shall be notified and updated by the CERC every six months for the purpose of bid evaluation: a. Applicable discount rate b. Escalation rate for coal c. Escalation rate for gas /LNG

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d. Inflation rate to be applied to indexed capacity charge component.

Approaches for Tariff Determination Taking into account the special features of small hydro generating units, it has to be examined whether tariff determination for such units can be simplified and what options are available for this purpose. Theoretically and based on international experience, the dominant approaches that are available for tariff determination are: 1. Cost based approach 2. Benchmark pricing approach 3. Avoided cost based approach

Cost based approach The cost based approach relies on the availability of requisite station-wise information for the generating stations, and thereafter builds up the tariffs from the costs. The exercise for SHP tariff setting in India has so far followed a cost based approach adjusted for performance standards set by regulators, where rate of return on the capital investments is regulated and a cap is imposed on clear profit earned by the generator. This methodology of tariff computation takes into account the recovery of fixed cost components such as interest on debt, operation and maintenance (O&M) costs and also assures a fixed return on an investor’s equity. This would be similar to the pricing of conventional power projects with Power Purchase Agreements. This approach necessitates validating each element of costs with the historical data/past trends and other supporting information, which is either not available at present or is unreliable due to the data being available for a short period of time and based on very small sample. This approach is, therefore, practically difficult when applied to such large number of tiny and widely distributed generating stations.

Benchmarking Approach The Benchmarking approach is another alternative of the cost based approach but it is highly dependent on a broad based and reliable data for defining the benchmarks or norms. Benchmark pricing typically adopts a representative station for determination of tariffs. In this method typically all cost elements are considered for this benchmark determination. The benchmark costs could result in unattractiveness of projects that are above the cost benchmark but are nonetheless viable from an economic perspective, considering the low losses involved in such local generation, social benefits and also the higher avoided costs of alternative sources. A summary of the key merits and demerits of the cost based and the benchmarking approach of tariff calculation is given below. Merits o

The cost based approach takes into account specific issues such as terrain, hydrology, capacity factor etc.

o

This approach has the ability of incorporating any incentive that is introduced, for instance the return on equity (say for a particular technology) and this gets reflected in the tariff that is calculated.

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o

Since the tariffs can be set for a longer period, the annual exercise of tariff setting can be avoided.

Demerits o

In the cost based methodology, tariffs need to be estimated separately for each type of project.

o

The cost based approach is heavily dependent on cost and performance parameters as input data, which might be difficult to obtain or verify.

Avoided Cost Approach Another alternative approach namely avoided cost based approach considers the unit cost of energy displaced at the margin by the energy generated at the margin by the renewable energy based power plant. The avoided costs thus become payable for the energy generated by the renewable energy plant. Avoided cost is the price that is equal to the incremental cost that a particular utility would have incurred if it had to produce the power itself or obtained the power from some another source. An issue that comes up in this approach relates to what is actually the avoided cost in such cases. One view is that the avoided cost is the cost that the licensee would have incurred in procuring the same energy from another existing source at the top end of the merit order. Another view is that the avoided cost should be the cost of supply to the licensee’s consumer at the place and at the voltage on which power from such tiny generating stations is injected into the grid. As this marginal power required for state consumption varies from cheapest to costliest Generating Station throughout the different months of a year, the ideal approach would be to run a daily or at least a monthly merit order for determination of cost of this replaced power. However, looking at the small quantities of and impact of such power and also the complexity in computation, such approach could run into difficulties. For practical reasons a less specific approach like the average procurement costs of power would seem desirable. In case of the cost of supply approach, the problems of working out precisely the cost of supply at a particular place and on a specified voltage arise with no easy solutions. Another issue which arises in this connection is whether the cost of inefficiency of carrying such power on low voltage resulting in avoidable losses should be thrust on the licensee or should it be compensated for the same while computing such avoided costs. The key merits and demerits of the avoided cost based tariff setting approach are discussed below: Merits o

Economic efficiency principles imply that the scarce resources in an economy should be allocated in such a manner that they provide the greatest benefit to the society or, they produce maximum output at the least cost. Therefore, when prices are set equal to marginal cost, it results in market equilibrium at a certain level and pattern of electricity supply that leads to the most efficient allocation of scarce resources.

o

In the context of different renewable energy technologies, this method of tariff calculation is technology neutral i.e. it does not differentiate between the different types of Renewable Energy Technologies (RETs).

Demerits o

This method requires a detailed performance data of all conventional power plants, in terms of plant availability and energy generation.

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o

The tariff calculation process has to be carried out every year.

Since the tariff for small hydropower stations determined in the avoided cost approach is linked to the cost of power purchase from other sources including central generating stations, which in turn is based on rates approved by Central Electricity Regulatory Commission (CERC), such tariff would need periodic revision arising out of changes in CERC’s tariffs. However, its advantage is that it would cover the inflationary increases as well as other changes, which would have to be periodically addressed in the tariff determination exercise. Based on the above discussion on specific advantages and disadvantages as well as different issues related to tariff methodologies it emerges that both the cost based approach and the avoided cost based tariff setting methodologies have (a) specific advantages and (b) can be adopted/modified to address specific issue(s). However, in the case of Indian states, it is seen that in order to promote the development of renewable energy technologies, a cost based approach with a return on equity, has been followed by the different state electricity regulatory commissions. This is primarily because the main advantage of a cost based tariff approach is that it has the ability of incorporating any incentive that is introduced for a particular technology and this gets reflected in the tariff that is calculated. Further, since the tariffs can be set for a longer period, the annual exercise of tariff setting can be avoided.

Payment Security The PSM (Power Supply Monitoring) has been stipulated by Ministry of Power for off-take of power from these projects in the following manner: • Revolving Letter of Credit (LC) by distribution licensees. • Escrow account establishing irrevocable claims on receivable of utilities. • In case of default, sale to other sharing procurers on inter-state power trading or direct supply to HT consumers as per provision of Electricity Act, 2003.

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Sector Players NTPC Summary: NTPC is India’s largest power generation company with current capacity of 26 GW. It has topline of $ 6.4 bn and PAT of $ 1.3 bn. It is listed on National stock exchange and Bombay stock exchange. Its market cap is $ 25 bn. Its world’s sixth largest thermal power producer. It is world’s second most efficient thermal power producer. (Source: Datamonitor, UK) Its PLF (Plant Load Factor) is 83% At present, Government of India holds 89.5% of the total equity shares of the company and the balance 10.5% is held by FIIs, Domestic Banks, Public and others.

Business Strategy: NTPC’s core business is engineering, construction and operation of power generating plants. It also provides consultancy in the area of power plant constructions and power generation to companies in India and abroad. In the next decade it plans to increase its generation capacity to 66 GW and also planning to set up national transmission grid in association with state owned transmission utilities.

Key Performance Indicators: With capacity of 26 GW, it accounts for 20% of the power capacity of India. NTPC generated total of 170 Billion Units of electricity in FY2006. It accounts for 28% of power generated in India Plant load factor (PLF) achieved in FY2006 is 87.5% for coal plants PLF for gas plants is 65.8%

Installed capacity has grown by 50% in last 8 years with almost same employee base.

Description

Unit

1997-98

2005-06

% of increase

Installed Capacity

MW

16,847

24,249

43.93

Generation

MUs

97,609

1,70,880

75.07

No. of employees

No.

23,585

24,044

1.95

Generation/employee

MUs

4.14

7.81

88.65

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Distribution of capacity: The installed capacity of NTPC is 26,404 MW through its 14 coal based (21,395 MW), 7 gas based (3,955 MW) and 4 Joint Venture Projects (1,054 MW). NTPC acquired 50% equity of the SAIL Power Supply Corporation Ltd. (SPSCL). This JV company operates the captive power plants of Durgapur (120 MW), Rourkela (120 MW) and Bhilai (74 MW). NTPC also has 28.33% stake in Ratnagiri Gas & Power Private Limited (RGPPL) (Earlier Dabhol Power Corporation) a joint venture company between NTPC, GAIL, Indian Financial Institutions and Maharashtra SEB Holding Co. Ltd. The present capacity of RGPPL is 740 MW.

Financial Highlights: Gross revenues of Rs 287 billion in FY2006 ($ 6.4 bn) EBITDA of Rs 98.33 bn. ($ 2.2 bn) PAT of Rs 58 billion in FY2006 ($ 1.3 bn) Revenues for 9 months ended FY2007 are Rs 222 billion ($ 4.9 bn) PAT for 9 months ended FY2007 is Rs 51.3 billion ($ 1.1 bn) Market Cap on Bombay Stock Exchange is Rs 110000 crore. ($ 24.4 bn)

Profile of Chairman NTPC Shri T. Sankaralingam Shri T.Sankaralingam (58 yrs) has been serving the power sector for the past 37 years. Before joining NTPC in 1977, he was associated with Tamil Nadu Electricity Board and Bharat Heavy Electricals Limited. Prior to taking over as Chairman and Managing Director, NTPC Limited, on April 01, 2006, he has been Director (Projects) since August 2001. Shri Sankaralingam has rich hands-on experience in all facets of electricity generation and transmission. In recognition of his expertise, he has been elected as Vice-Chairman of CIGRE, India and awarded ‘Eminent Engineer Award’ by Institution of Engineers. He is a Member of IEEE, USA; Honorary Fellow of Project Management Association; Member of the Committee appointed by Government of India to evaluate adoption of 800 MW Super Critical Units; Member of Expert Committee of CERC to formulate the Operational Norms for Tariff under ABT Regime; Member of the Board of University of Petroleum and Energy Studies; Member of Steering Committee of Centre for Research on Energy Security, TERI. Director (Projects) Mr. K.B. Dubey has taken over as Director (Projects) of the Company w.e.f. January 12, 2007. Mr. K.B. Dubey is a Graduate in Mechanical Engineering from Pant Nagar University with rich and varied work experience of more than 33 years in different fields. He has been with NTPC for last 25 years holding different leadership positions. Prior to his joining as Director (Projects), NTPC, he has held position of Executive Director (Hydro) and Executive Director (Corporate Monitoring Group) of NTPC Limited. Director (Commercial) Mr. R. S. Sharma is director (Commercial) w.e.f. October 8, 2004

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Mr. Sharma has vast and rich experience of 35 years in thermal power stations. Prior to joining NTPC he has worked in Madhya Pradesh state electricity board. He authored several Technical papers on power plant operations. Growth plans: India’s generation capacity can be expected to grow from the current levels of about 120 GW to about 225-250 GW by 2017. NTPC currently accounts for about 20% of the country’s installed capacity and almost 60% of the total installed capacity in the Central sector in the country. NTPC targets to build an overall capacity portfolio of over 66,000 MW by 2017.

Station wise Power generation

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PLF comparison of NTPC vs. other power producers

NTPC Subsidiaries

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and JVs

Growth plans – Power projects Planned

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Shareholding Pattern

Sr. No (A)

(a) (b) (c) (d) (e)

(a) (b) (c) (d)

Category of shareholder Shareholding of Promoter and Promoter Group -1 Indian Individuals/ Hindu Undivided Family Central Government/ State Government(s) Bodies Corporate Financial Institutions/ Banks Any Other (specify) Sub-Total (A)(1) -2 Foreign Individuals (Non- Resident Individuals/ Foreign Individuals) Bodies Corporate Institutions Any Other (specify) Sub-Total (A)(2)

(c) (d) (e) (f)

Total Shareholding of Promoter and Promoter Group (A)= (A)(1)+(A)(2) Public shareholding -1 Institutions Mutual Funds/ UTI Financial Institutions/ Banks Central Government/ State Government(s) Venture Capital Funds Insurance Companies Foreign Institutional Investors

(g) (h)

Foreign Venture Capital Investors Any Other (specify)

(B) (a) (b)

(a) (b)

(i)

(ii) (c)

(C)

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Sub-Total (B)(1) -2 Non-institutions Bodies Corporate Individuals Individual shareholders holding nominal share capital up to Rs. 1 lakh Individual shareholders holding nominal share capital in excess of Rs. 1 lakh Any Other (specify) Non Resident Clearing Members Foreign Nationals Trusts Sub-Total(B)(2) Total Public Shareholding (B)= (B)(1)+(B)(2) TOTAL(A)+(B) Shares held by Custodians and against which Depository Receipts have been issued GRAND TOTAL (A)+(B)+(C)

Number of sharehold Total number ers of shares

0

0

Number of shares held in de % of materialized shares form (A+B)

% of shares (A+B+C)

0

0

0

1 0 0

7379634400 7379634400 0 0 0 0

89.5 0 0

89.5 0 0

0 1

0 0 7379634400 7379634400

0 89.5

0 89.5

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0

0 0

0 0

0 0

0 0

7379634400 7379634400

89.5

89.5

1

69 32

45789389 6443352

45789389 6443352

0.56 0.08

0.56 0.08

0 0 14 180

0 0 53261004 581304573

0 0 53261004 581304573

0 0 0.65 7.05

0 0 0.65 7.05

0

0

0

0

0

0 295

0 686798318

0 686798318

0 8.34

0 8.34

3072

26986675

26986675

0.33

0.33

578248

146170920

146069936

1.77

1.77

476

1613951

1613951

0.02

0.02

4208 492 2 69 586567

2785072 1011395 714 462955 179031682

2785072 1011395 714 462955 178930698

0.03 0.01 0 0.01 2.17

0.03 0.01 0 0.01 2.17

586862 586863

865830000 865729016 10.51 8245464400 8245363416 100.01

10.51 100.01

0 586863

0 0 8245464400 8245363416

0 100

Tata Power Summary: Tata power is India’s largest private sector power utility. Its revenues are $ 1 bn. Its Profit after tax is $ 137 mn. Its generation capacity is 2300 MW. Out of that in Mumbai, the capacity is 1800 MW. It has presence in generation, transmission and distribution of power. It supplies power to Mumbai and Delhi regions.

Business strategy: The core business of Tata Power Company is to generate, transmit and distribute electricity. The Company operates in two business segments: Power and Other services. The Power segment is engaged in generation, transmission and distribution of electricity. The other services segment includes electronic equipment, broadband services, and project consultancy and oil exploration.

Key performance indicators: Generation: Tata Power has an installed power generation capacity of above 2300 Mega Watts. Mumbai power business at Trombay, Bhira, Bhivpuri and Khopoli, accounts for 1797 MW. Highest ever generation of power in FY06 at 13746 MUs. Out of this hydro generation accounts for 2000 MUs. Sales in FY06 are 13616 MUs. Transmission: It has a 51:49 JV (It holds 51%) with state power utility power grid for 1200 Km Tala transmission project. It will carry the surplus electricity produced from Bhutan to power deficient North and North Eastern states. Distribution: It supplies power to Mumbai Region and North Delhi region. These two cities are lucrative markets for power distribution. It has unique technology called islanding protection system, which maintains uninterrupted power supply in Mumbai, even when the western power grid fails. It has taken over the North Delhi power supply from government in 2002 and since has brought down transmission losses to 28% from 53%. It serves over 8 lac satisfied consumers with a peak load of 1050 MW. It also provides providing state-of-the-art technology driven processes for enhancing consumer billing and related services.

Financial Highlights: Revenues for FY06 are Rs 4563 crore ( $ 1 bn) EBITDA of Rs 835 crore. ($ 186 mn) PAT for FY06 is Rs 610 crore ($ 137 mn) Revenues for 9 months ended FY07 are Rs 3770 cr. ($ 840 mn) Profits for 9 months ended FY07 are Rs 604 cr. ( $ 135 mn)

39 | P a g e

Market cap on BSE index is Rs 12000 cr. ( $ 2.7 bn)

Growth plans: Tata power has recently won 4000 MW Ultra Mega Power Project which is to be developed at Mundra (Gujarat) TPC is currently implementing 250 MW coal based plant at Trombay 100 MW diesel generating sets to be completed by 2008 1000 MW imported coal based coastal power plant in Maharashtra is proposed to be set up by 2010 1000 MW Maithon Right bank thermal power project to be set up in collaboration with state utility. 120 MW captive plant for Tata steel Tala Transmission project involves the construction of 1200 km of 400 kV transmission lines.

Transmission and Distribution Capacity

Total Transmission Lines Overhead

973 KM

Underground

122 KM

Total Distribution Lines Overhead

232 KM

Underground

842 KM

Total Substations Transmission (Receiving Stations)

17

Distribution

85

Subsidiaries North Delhi Power Limited: A joint venture with the State Government of Delhi for its North Delhi consumers, the NDPL serves over 8 lac consumers with a peak load of 1050 MW, also providing state-of-the-art technology driven processes for enhancing consumer billing and related services. Tata Power Trading Company: Tata Power Trading Company Limited (TPTCL), a wholly owned subsidiary of the Tata Power Company (TPC) has been awarded the first ever power trading license by the Central Electricity Regulatory Commission (CERC) under section 14 of the Electricity act 2003, enabling it to carry out transactions all over India. Tata Power Trading Company Limited (TPTCL), in its first full year of operation, traded 675 MUs, earning revenues of Rs. 207.76 crore and profit after tax of Rs. 3.18 crore. Strategic Electronics Division (SED):

40 | P a g e

The Strategic Electronics Division of Tata Power has been in operation for over 30 years and has been pursuing development and production activities for the Indian defense sector. SED successfully developed the Multi Barrel Rocket Launcher, ‘Pinaka’, proven in the field through extended user trials which led to its induction into the Indian Army. The Division has developed specialized equipment for Air Defense and Naval Combat systems. Powerlinks Transmission: Tala Transmission project involves the construction of 1200 km of 400 kV transmission lines from Siliguri in West Bengal to Delhi region and it will evacuate 1020 MW of power from Bhutan and transmit it to the power deficit states in North India, while also facilitating the transmission of surplus power from the North-Eastern region. It is 51:49 JV between TPC and Powergrid Corporation.

41 | P a g e

Shareholding pattern

Sr. No (A) 1) (a) (b) (c) (d) (e)

(a) (b) (c) (d)

(B) (a) (b) (c) (d) (e) (f) (g) (h)

(a) (b)

(i)

(ii) (c)

(C)

42 | P

Category of shareholder Shareholding of Promoter and Promoter Group Indian Individuals/ Hindu Undivided Family Central Government/ State Government(s) Bodies Corporate Financial Institutions/ Banks Any Other (specify) Trust Sub-Total (A)(1) 2) Foreign Individuals (Non- Resident Individuals/ Foreign Individuals) Bodies Corporate Institutions Any Other (specify) Sub-Total (A)(2) Total Shareholding of Promoter and Promoter Group (A)= (A)(1)+(A)(2) Public shareholding 1) Institutions Mutual Funds/ UTI Financial Institutions/ Banks Central Government/ State Government(s) Venture Capital Funds Insurance Companies Foreign Institutional Investors Foreign Venture Capital Investors Any Other (specify) Sub-Total (B)(1) 2) Non-institutions Bodies Corporate Individuals Individual shareholders holding nominal share capital up to Rs. 1 lakh Individual shareholders holding nominal share capital in excess of Rs. 1 lakh Any Other (specify) Overseas Corporate Bodies Trust Sub-Total(B)(2) Total Public Shareholding (B)= (B)(1)+(B)(2) TOTAL(A)+(B) Shares held by Custodians and against which Depository Receipts have been issued a gGRAND e TOTAL (A)+(B)+(C)

Number of shareholders

Number of shares held in de materialized form

Total number of shares

% of shares (A+B)

% of shares (A+B+C)

0

0

0

0

0

0 13 0

0 63766080 0

0 63765328 0

0 32.28 0

0 32.22 0

3 16

65624 63831704

65624 63830952

0.03 32.31

0.03 32.25

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0

0 0

0 0

0 0

0 0

16

63831704

63830952

32.31

32.25

113 196

5563425 1756981

5470953 1705303

2.82 0.89

2.81 0.89

6 0 44 164

198155 0 45304744 37162888

172899 0 45279920 37155740

0.1 0 22.93 18.81

0.1 0 22.89 18.78

0

0

0

0

0

0 523

0 89986193

0 89784815

0 45.55

0 45.47

1684

1802846

1581445

0.91

0.91

139389

39122294

26396307

19.8

19.77

135

2723658

2494584

1.38

1.38

4 36 141248

1160 74849 43724807

0 73459 30545795

0 0.04 22.13

0 0.04 22.1

141771 141787

133711000 197542704

120330610 184161562

67.68 99.99

67.57 99.82

3 141790

355160 197897864

354930 184516492

0.18 100

Reliance Energy Summary Reliance Energy Ltd (REL) formerly known as Bombay Suburban Electric Supply (BSES), is a part of the Anil Dhirubhai Ambani Group. It is an integrated power utility company in the private sector in India which came into existence when it took over BSES in 2002. The company is the sole distributor of electricity to consumers in the suburbs of Mumbai. It also runs power generation, transmission and distribution businesses in other parts of Maharashtra, Goa and Andhra Pradesh. REL has significant presence in the field of execution of the Power projects on EPC (Engineering, Procurement and Commissioning) basis.

Key performance Indicators Generation REL is currently generating 941 MW of electricity through its power stations located in Maharashtra, Andhra Pradesh, Kerala, Karnataka & Goa. The Dhanau Thermal Power Station (DTPS) which has a capacity of 500 MW’s achieved a Plant Load Factor (PLF) of 98.70 %. Distribution Reliance Energy distributes more than 21 billion units of electricity to over 25 million consumers in Mumbai, Delhi, Orissa and Goa, across an area that spans 123400 sq. kms. Reduced distribution losses around 12.01% - The lowest in the country. Mumbai operations cover a population of 9.0 million within an area of about 384 sq. kilometers. The Distribution network handled and sold 6881 MUs in the year 2005-2006. Transmission The Transmission Department is an intermediary between Generation & Distribution and is responsible for transmission of power at 220 kV from DTPS to the Company's area of supply in Mumbai Suburbs. REL has a customer base of 5 million and has achieved the distinction of operating its network with 99.93% reliability EPC The EPC Division provides a full service project advisory capability. It can manage a power plant on a turnkey basis or it can provide one or more industry specialist services such as fuel management advice or fiscal advice.

Growth Plans Reliance Energy plans to increase its power generation capacity by adding 16,000 MW with investments of $13 billion. Of which 12500 MW would be gas, coal, wind and hydro based power generation projects in Maharastra, Uttar Pradesh, Andhra Pradesh and Uttranchal. These projects are in various stages of development.

The Dadri Power Plant being constructed has a capacity of 5500MW.This gas generation power plant is proposed to be the single largest gas grass root gas fired generation plant in the world. A 4000 MW Power Project at Shahapur in Maharastra.

43 | P a g e

Reliance's gas finds in KG-D6 block in Krishna Godavari basin which constitutes 60% of India's present total gas production, will provide an enormous opportunity to scale up power generation capacities in India. Reliance Energy is also participating in emerging opportunities in the areas of trading and transmission of power. Reliance Energy is looking at bidding for Global Power Assets.

Key Financials

Units Installed Capacity PLF Financials Networth Net Sales OPBDIT Net Profit

%

Reliance energy 2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 2006-07 508 508 885 941 941 941 941 82.6 87.8 90.5 138 86 86 NA

Rs. Million Rs. Million Rs. Million Rs. Million

Ratios Operating Profit Margin Net Profit Margin

25761.5 22724 5104 2955

26778 26183 5275 3051

25592 36906 4022 1218

43544 34567 6931 2383

50193 40479 6710 3874

78732.8 40,759.00 8605 6503.4

68,315.70 14,760.00 8,597.70

22.5% 13.0%

20.1% 11.7%

10.9% 3.3%

20.1% 6.9%

16.6% 9.6%

21.1% 16.0%

21.6% 12.6%

Key Management Personnel Anil D. Ambani - Chairman & Managing Director Regarded as one of the foremost corporate leaders of contemporary India, Anil Dhirubhai Ambani is the Chairman of all listed Group companies, namely: Reliance Communications, Reliance Capital, Reliance Energy and Reliance Natural Resources Limited. Till recently, he also held the post of Vice Chairman and Managing Director in Reliance Industries Limited (RIL), India's largest private sector enterprise. Anil D Ambani joined Reliance in 1983 as Co-Chief Executive Officer, and was centrally involved in every aspect of the company's management over the next 22 years. He is credited with having pioneered a number of path-breaking financial innovations in the Indian capital markets. He spearheaded the country's first forays into the overseas capital markets with international public offerings of global depositary receipts, convertibles and bonds. Starting in 1991, he directed Reliance Industries in its efforts to raise over US$ 2 billion. He also steered the 100-year Yankee bond issue for the company in January 1997. Satish Seth - Vice Chairman Shri Satish Seth, (50), is a Fellow Chartered Accountant and a law graduate. He has had a wide exposure in developing, strategizing and overseeing businesses in petrochemicals, petroleum and financial sectors. Presently, he oversees and leads businesses in power, telecommunication and infrastructure sectors. He has vast experience in the areas of finance, commercial, banking, accounts, audit, taxation, legal, project execution and general management. Shri Seth was appointed to the Board on 24th November,2000 and was appointed Vice Chairman on 18th January,2003. He was appointed as Executive Vice Chairman on 21st April,2003. He is also a Director of Reliance Energy Ventures Limited, Reliance Energy Trading Limited, Reliance Entertainment Private Limited, Reliance Telecom Limited, Rollwell Holdings and Trading Private Limited, Innovative Management Services Private Limited, WorldTel Holdings Limited, The Federation of Electricity Undertakings

44 | P a g e

of India, BSES Rajdhani Power Limited, BSES Yamuna Power Limited, Reliance Gateway Net Limited and Reliable Internet Services Limited. J. P. Chalasani - Director (Business Development) Shri J P Chalasani, (48), is an engineering graduate and has about 25 years experience in the power sector and held responsible positions with National Thermal Power Corporation Limited and Reliance Power Limited. He was appointed to the board of the Company on 18th January,2003. He is also on the boards of Hirma Power Private Limited, Reliance Energy Trading Limited, BSES Rajdhani Power Limited, Utility Powertech Limited and Jayamkondam Power Private Limited. S. C. Gupta - Director (Operations) Shri S C Gupta, (57), is a graduate in electrical and mechanical engineering and also MSc.(Engineering)in power systems.He was appointed to the board on 18th January, 2003.He was formerly the group senior executive vice president in Reliance Power Limited. He was actively involved in the design and implementation of captive power plants of Reliance Industries Limited at Hazira, Patalganga, Naroda and Jamnagar totalling 750 MW and development of Independent Power Projects (IPPs) at various locations. He is on the boards of Creative Energy Optimisations Private Limited, Reliance Energy Trading Limited, Utility Powertech Limited, BSES Kerala Power Limited and Reliance Energy Generation Limited. He is a member of the Shareholders/Investors ’Grievances Committee and Environment, Health &Safety Committee of Reliance Energy Limited. He is a member of the audit committee of BSES Kerala Power Limited. Station wise Power Generation and Plant Factor Load (PLF) Type

Plant Location

Output (in MW)

Thermal Power

Dhanau near Mumbai

500

(multi fuel based)

( 2x250)

PLF 98.70%

Wind Farm

Jogimatti in Karnataka

8

34.1%

Cycle Power

Kochi ,Kerala

165

-

Samalkot,Andhra Pradesh

220

61%

48

93.32%

Naptha based (combined cycle power) Total

45 | P a g e

Goa

941

Details of Share Holding Pattern

Sr. No Category of shareholder Shareholding of Promoter and Promoter Group (A) 1) Indian Individuals/ Hindu Undivided Family (a) (b) (c) (d) (e)

(a) (b) (c) (d)

Central Government/ State Government(s) Bodies Corporate Financial Institutions/ Banks Any Other (specify) Sub-Total (A)(1) 2) Foreign Individuals (Non- Resident Individuals/ Foreign Individuals) Bodies Corporate Institutions Any Other (specify)

(a) (b)

Sub-Total (A)(2) Total Shareholding of Promoter and Promoter Group (A)= (A)(1)+(A)(2) Public shareholding 1) Institutions Mutual Funds/ UTI Financial Institutions/ Banks

(c) (d) (e) (f) (g) (h)

Central Government/ State Government(s) Venture Capital Funds Insurance Companies Foreign Institutional Investors Foreign Venture Capital Investors Any Other (specify)

(B)

(a) (b) (i) (ii) (c)

(C)

Number of shares held in de Number of Total number materialized % of shares shareholders of shares form (A+B)

% of shares (A+B+C)

11

663378

663371

0.3

0.29

0 22 0

0 78063368 0

0 78061712 0

0 34.98 0

0 34.16 0

0 33

0 78726746

0 78725083

0 35.28

0 34.45

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0

0 0

0 0

0 0

0 0

33

78726746

78725083

35.28

34.45

283 407

15023681 1545713

14979354 1528940

6.73 0.69

6.57 0.68

70 0 23 511 0

273462 0 49034269 46391612 0

195758 0 49033338 46170812 0

0.12 0 21.97 20.79 0

0.12 0 21.46 20.3 0

0 1294

0 112268737

0 111908202

0 50.3

0 49.13

Sub-Total (B)(1) 2) Non-institutions Bodies Corporate Individuals Individual shareholders holding nominal share capital up to Rs. 1 lakh Individual shareholders holding nominal share capital in excess of Rs. 1 lakh Any Other (specify) NRIs / OCBs Sub-Total(B)(2)

6686

4074657

3918114

1.83

1.78

1551487

25274026

18336283

11.33

11.06

47

1453826

1401204

0.65

0.64

17208 1575428

1367647 32170156

906387 24561988

0.61 14.42

0.6 14.08

Total Public Shareholding (B)= (B)(1)+(B)(2) TOTAL(A)+(B)

1576722 1576755

144438893 223165639

136470190 215195273

64.72 100

63.21 97.66

Shares held by Custodians and against which Depository Receipts have been issued GRAND TOTAL (A)+(B)+(C)

3 1576758

5364669 228530308

5363938 220559211

46 | P a g e

2.35 100

Recent Projects bagged by REL The company has bagged two contracts for Rs. 398.76 crores for undertaking engineering, procurement and construction work. The first contract is for Rs. 3.76 crores from Haryana Power Generation Corporation for 2 x 600 MW coal based power project at Hissar. The project is to be implemented in 3538 months. The second order is for Rs. 395 crores from Uttar Pradesh Rajya Vidyut Utpadan Nigam for the Balance of plant package for the 2 x 250 MW extension units 5 & 6 of the Panchha Thermal Power Station near Jhansi. Reliance Energy won on competitive bidding last year for 280 MW Urthing Sobla hydro power project in Uttaranchal. It has also won two power projects totaling 1700 MW in Arunachal Pradesh. Recently Reliance energy has bagged 1200 MW Hissar and 2X250 MW Pariccha projection EPC Contract. It is also building 1200 MW Rosa Power Plant.

Other Projects under Commissioning /Execution 2 x 300 MW Yamunanagar Thermal Power Station for Haryana power generation Corporation. More than 7000 Village Electrification, commissioning of new 52 GSS & Augmentation of 82 GSS under RGGVY - UPRE Project 4 x 70 MW Urthing Sobla Hydro Electric Project in Uttaranchal 2 x 210 MW Parichha Thermal Power Station for Uttar Pradesh Rajya Vidyut Utpadan Nigam Limited at Parichha, U.P. Main Electrical System Packages for 2 x 220 MW Nuclear Power Plant at Kaiga, Karnataka and 2 x 220 MW Nuclear Power Plant at Kota, Rajasthan for Nuclear Power Corporation of India Limited. Changeover from overhead to underground Transmission Lines under Ranchi beautification scheme for Jharkhand State Electricity Board 110 KV Switchyard and Revamping of Electrical System in the State of Tamil Nadu for Chennai Petroleum Corporation. 220 kV d/c transmission lines Project from Panarsa to Nalagarh for AD Hydro Power Ltd.

Key Projects of EPC Division EPC division has undertaken and successfully commissioned the following major projects: Its first ever IPP, 2 x 250 MW Coal based Thermal Power Station at Dahanu, Maharastra Reliance Energy Limited-Samalkot Power Station: 220 MW Dual Fuel based (Natural gas & Liquid Fuel) Combined Cycle Power Plant at Samalkot, Andhra Pradesh. The Power Plant is already operational and supplying power to the State Grid of Andhra Pradesh 165 MW liquid-fuels based combined cycle power project for its subsidiary, Reliance Energy Limited Kochi Power Station at Kochi in Kerala with an aero-derivative unit of 40 MW along GE's LM6000 module, completed on 15 June 2001 106 MW Combined Cycle Power Plant of Gujarat State Electricity Corporation Ltd. at Dhuvaran, Gujarat 24 MW Bagassed based Co-generation Power Plant for Godavari Sugar Mills Limited at Sameerwadi, Karnataka 20 MW Diesel based D.G.Sets for Surya Chakra Power Ltd. at Islands of Andaman and Nicobar. 12.5 MW Lignite Based Power Project for Grasim Industries Limited at Ariyalur, Tamil Nadu

47 | P a g e

10.5 MW (5 x 2 MW + 1 x 0.5 MW) Diesel based captive power project for IT-Park for TIDEL- Chennai. 7.5 MW Thermal Power Plant for Monnet Power Ltd. at Raipur, Madhya Pradesh. 3 x 2.5 M DG based Power Plant for National Institute of Biologicals, Noida. 5 MW Bagasse based Thermal Power Plant for Global Energy Ltd., Belgundi, Karnataka, 3 MW Captive Power Project for Alok Industries Limited at Vapi, Gujarat. 2.5 MW D.G. set based Captive Power Plant for ITC, Bangalore. 2 x 250 MW Tau Devilal Thermal Power Station for Haryana Power Generation Corporation Limited at Panipat, Haryana. (Unit - 8 of Tau Devilal Thermal Power Project of HPGCL has been awarded the "Best executed 250 MW Thermal Power Project” of the Year 2004-05) Renovation and Modernization of Delhi Distribution System.

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CESC Company Overview— CESC, a power utility in India was setup in 1899. It brought electricity to Calcutta, just a few years after electricity was first used to light up London. CESC Limited is a flagship company of RPG Enterprises, which is one of India's well-managed groups of companies with a diversified presence. Company brought thermal power to India more than 100 years ago and supplies power to the city of kolkata. It is part of the RPG group and the company is engaged in the business of generation and distribution of electricity in Calcutta, Howrah and the surrounding areas. CESC Directly distributes electricity to nearly 12 million people of Calcutta, over a 567 sq kms area, through a vast distribution network. Companies merged its wholly owned subsidiaries CESCON Ltd and Balagarh Power Company Ltd in the company in the year 2004. Merger of its two subsidiaries with the company would result in synergies in operations and lower overhead costs enabling higher efficiencies for the company.

Products & Services— CESC, an RPG group company is one of the oldest private distribution companies in India and supplies power to Kolkata serving 12 million citizens across its licensed area spread over 567 Sq Km, through a vast distribution network. Company is engaged in the business of generation and distribution of electricity in Calcutta, Howrah and the surrounding areas. CESE has four generating stations viz.Budge Budge, New Cossipore, Southern and Titagarh located in Kolkata.

Recent Developments— RPG group flagship CESC is planning to invest Rs 200 billion in power over a period of seven years to enhance its generating capacity. In the proposed amount of Rs 200 billion, around Rs 100 billion would be allocated for additional generating capacity in West Bengal. Company is planning to set up a 2,000-megawatt unit at Haldia for around Rs 80 billion. This project will be built in two phases as three units of 660 megawatt each and West Bengal will be one of the consumers. CESC also has a plan of a mega project in Jharkhand. Company is likely to start a subsidiary for power project in Jharkhand. The company has already signed MOU with Jharkhand govt. for a 1,000megawatt power project. This project will follow ntpc model of power generation with stand-alone power generating stations selling power to distribution companies. Company is expecting 400-500 megawatt additional demand from Kolkata region by 2010-11.

Vision We will be a profitable consumer oriented power utility consistent with global standards meeting the expectations of consumers, employees and other stake holders. We will achieve this vision by: Achieving efficiency of operations and further developing core competencies. Readjusting the business consistent with the changing environment, technologically and commercially. Maintaining a rewarding and stimulating organisational climate with people orientation. Reaffirming faith in the organisation's ethics and values developed in course of our long existence.\ Harnessing and developing our professional competence. Being responsive to social requirements. Mission We will meet consumer's expectations continuously by providing safe, reliable and economic electricity through optimisation of available resources. We will achieve this mission:

49 | P a g e

Accomplishing targetted performance in the key result areas of our business operations. Enhancing consumer satisfaction through value addition to service supported by a consumer feedback monitoring system. Being recognised as an ethical and environmentally responsive organisation. Improving work environment and helping employees for personal development and career satisfaction through an interactive approach. Quality Policy CESC is committed to achieve and sustain leadership in Generation, Distribution of Electricity and other allied services to all consumers as per acclaimed standards to meet their expectations in regard to Quality and Reliability.

Financials

Installed Capacity PLF Financials Networth Net Sales OPBDIT Net Profit Ratios Operating Profit Margin Net Profit Margin

50 | P a g e

Units MW % Rs. Million Rs. Million Rs. Million Rs. Million

CESC 2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 2006-07 1065 1065 1065 1065 975 975 975 n.a. 73.4 75.6 80.2 85.6 NA NA 2001 18054.5 5687.9 -1920.6

4470.7 21420.1 6992.7 -879.6

4865.7 22491.5 7872.7 97.4

10653.9 24106.5 8775 1905.4

12724.9 23911 7413 1506.5

31.5% -10.6%

32.6% -4.1%

35.0% 0.4%

36.4% 7.9%

31.0% 6.3%

16448.8 26,727.00 25,830.00 7,917.40 6,690.00 1,774.70 2,970.00

29.6% 6.6%

25.9% 11.5%

Shareholding Pattern

Sr. No Category of shareholder Shareholding of Promoter and Promoter Group (A) -1 Indian Individuals/ Hindu Undivided Family (a) Central Government/ State Government(s) (b) Bodies Corporate (c) Financial Institutions/ Banks (d) Any Other (specify) (e) Sub-Total (A)(1) -2 Foreign Individuals (Non- Resident Individuals/ Foreign Individuals) (a) Bodies Corporate (b) Institutions (c) Any Other (specify) (d) Sub-Total (A)(2) Total Shareholding of Promoter and Promoter Group (A)= (A)(1)+(A)(2) Public shareholding (B) -1 Institutions Mutual Funds/ UTI (a) Financial Institutions/ Banks (b) Central Government/ State Government(s) (c) Venture Capital Funds (d) Insurance Companies (e) Foreign Institutional Investors (f) Foreign Venture Capital Investors (g) Any Other (specify) (h) Sub-Total (B)(1) -2 Non-institutions Bodies Corporate (a) Individuals (b) Individual shareholders holding nominal share capital up to Rs. 1 lakh (i)

(ii) (c)

(C)

Individual shareholders holding nominal share capital in excess of Rs. 1 lakh Any Other (specify) Sub-Total(B)(2) Total Public Shareholding (B)= (B)(1)+(B)(2) TOTAL(A)+(B) Shares held by Custodians and against which Depository Receipts have been issued GRAND TOTAL (A)+(B)+(C)

51 | P a g e

Number of shares held in de materialized % of shares % of shares form (A+B) (A+B+C)

Total number of shares

Number of shareholders

6

351302

351302

0.42

0.42

0 30 0

0 34166726 0

0 20724083 0

0 40.59 0

0 40.52 0

0 36

0 34518028

0 21075385

0 41.01

0 40.94

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0

0 0

0 0

0 0

0 0

36

34518028

21075385

41.01

40.94

28 28

3404746 59547

3397956 38993

4.04 0.07

4.04 0.07

1 0 5 67 0

2152 0 7672440 24385139 0

0 0 7671222 24373319 0

0 0 9.11 28.97 0

0 0 9.1 28.92 0

0 129

0 35524024

0 35481490

0 42.19

0 42.13

910

6869238

3997273

8.16

8.15

25252

4983794

2875939

5.92

5.91

49

2284357

1895617

2.71

2.71

0 26211

0 14137389

0 8768829

0 16.79

0 16.77

26340 26376

49661413 84179441

44250319 65325704

58.98 99.99

58.9 99.84

1 26377

138070 84317511

120719 65446423

0.16 100

Company Comparison NTPC

REL

Tata Power

CESC

Installed Capacity(MW)

27,404.00

941.00

2,323.00

975.00

Units of Electricity Sold(MU)

159,019.00

8,064.00

13,616.00

6,251.00

Energy Sales (Rs. Million)

260,701.00

31,873.90

43,141.90

25,158.80

Consultancy Services/EPC

452.00

8,544.50

-

-

1.64

3.95

3.17

4.02

Commercial Generation(MU)

169,789.00

8,064.00

13,746.00

7,909.00

Fuel (Rs. Million)

163,947.00

10,875.60

23,965.10

8,648.21

0.97

1.35

1.74

1.09

Employee Remuneration (Rs Million)

9,684.00

1,865.30

1,736.80

2,191.20

Employee Remuneration (Rs /Kwh)

0.06

0.23

0.13

0.28

Generation Administration and other expenses (Rs. Million)

12,721.00

1,790.50

5,474.70

7,342.00

Generation Administration and other expenses (Rs. Per Kwh)

0.07

0.22

0.40

0.93

Operating Income (Rs. Million)

271,210.00

40,759.00

45,794.30

26,727.00

Operating Profit(Rs. Million)

80,785.00

8,605.00

8,783.60

7,917.40

EBITA (Rs. Million)

60,308.00

5,118.00

5,902.30

5,371.70

PAT(Rs. Million)

58,202.00

6,503.40

6,105.40

1,774.70

Net Worth(Rs. Million)

448,279.00

78,732.80

49,802.20

16,448.80

Capital Employed(Rs. Million)

463,296.00

111,750.80

48,668.60

56,213.41

ROCE

13.02%

4.58%

12.13%

9.56%

EBITA margin

22.24%

12.56%

12.89%

20.10%

Operating profit margin

29.79%

21.11%

19.18%

29.62%

Market Capitalisation (Rs. Million)*

1,299,484.50

116,915.90

119,333.70

31,919.30

Enterprise Value(Rs. Million)

1,482,554.50

103,938.60

136,978.20

47,117.40

D /E

0.45

0.54

0.55

0.52

CRISIL Bond rating

AAA

AAA

AAA-

NA

ICRA

AAA

MAAA

AAA+

LA+

Tariff (Rs./Kwh)

(Rs. Per Kwh)

*Market Capitalisation as on May 7, 2007

52 | P a g e

All financial figures for FY’ 06

Company Name

Year EndEquity

Gr. Blk

Sales

NP

NP Var%

Div %

B.V Rs

EPS Rs.

Auro Energy

20030 3

20.53

43.65

6.45

0.24

0

0

10.1

0.1

BF Utilities

20060 9

18.83

117.73

12.75

2.3

0

0

54

0.6

Bhoruka Power

20030 3

14.11

99.1

37.36

6.14

14

0

37.8

4.4

BSES Powe

Andhra 20020 3

158.86

7.55

0

0

0

0

10

0

BSES Pow.

Kerala 20030 3

104.26

594.15

123.03

-37.16

-999

0

6.1

0

CESC

20060 3

84.32

8,261.0 0

2,556.9 4

178.36

21

25

200.8

20.8

D L F Power

20050 3

69.32

286.24

103.77

6.73

-36

0

21.7

1

DPSC

20060 3

4.23

85.2

298.91

8.74

225

10

187.8

20.5

Energy Devlop.Co

20060 3

27.5

47.05

12.98

6.07

84

10

24.6

2.1

Essar Power

20060 3

524

2,206.5 0

693.96

51.1

0

0

18.4

1

Guj. Inds. Power

200603

1,896.8 1

756.59

114.81

11

13

61.5

7.4

Guj. St. Energy

20000 3

75

25.43

4.19

0

100

0

10

0

Guj. Windfarms

20010 3

0.41

1.89

0.2

0.04

-56

0

26.3

1

Gujarat Paguthan

20030 3

728

2,425.0 4

965.11

295.12

8

53

24.5

4.1

GVK Inds.

20060

262

1,007.4

283.4

140.56

177

10

21.2

5.2

GVK Power Infra

20060 3

23.64

0.04

11.57

8.1

358

0

174.3

3.4

Haryana Power

20050 3

150.1

3,684.5 0

1,640.5 0

-35.03

0

0

420.8

0

HPL Cogeneration

20040 3

61.2

524.15

135.09

39.74

-2

46

12

4.2

53 | P a g e

151.2 5

Company Name

Year EndEquity

Gr. Blk

Sales

NP

NP Var%

Div %

B.V Rs

EPS Rs.

IL & FS Energy

20050 3

17.3

36.31

3.07

0.82

21

0

10

0.5

Jaiprakash Hydro

20060 3

491

1,647.1 3

294.17

78.77

54

0

14.3

1.6

Jaiprakash Power

20020 3

255

8.12

0

0

0

0

10

0

Jindal Thermal

20050 3

289

1,069.5 8

490.84

60.31

-50

0

22.3

2.1

JSW Energy

20060 3

346.8

0

541.83

121.63

0

25

21.3

3.5

Lanco Kondapalli 20040 3

340

1,108.9 5

566.99

58.48

-5

16

10.9

1.5

Malana Co.

66.78

331.1

66.73

10.46

398

0

11.8

1.6 2.9

Power 20030 3

Murdeshwar Power

20000 3

8.44

53.88

7.48

2.47

0

0

21.6

Natl. Hydroelect

20060 3

10,215.2 8

12,755. 52

1,667.9 6

742.11

8

2

1,561.9 69.6 0

NE Elec. Power

20060 3

1,906.11

4,605.3 5

839.62

198.55

1

3

1,261.6 99.7 0

Neyveli Lignite

20060 3

1,677.71

9,086.8 9

2,201.3 9

603.46

-50

20

47.7

3.3

NTPC

20060 3

8,245.46

46,039. 60

26,142. 90

5,825.3 0 0

28

55.1

6.7

Power 20060 3

10,145.3 3

12,662. 06

3,567.0 6

1,683.0 -1 3

5

2,003.4 158.8 0

Grid 20060 3

3,740.41

24,892. 25

3,145.3 4

1,009.0 28 2

8

2,705.3 258.4 0

Nuclear Co Power Corp.

Rel. Utilities

20040 6

131.01

1,092.1 6

367.63

168.19

59

0

80.4

12.8

Reliance Energy

20060 3

228.53

5,470.6 1

3,976.6 1

642.13

37

50

346.4

27.4

Renewable Energy

20020 3

11.84

62.99

20.1

-29.77

7

0

-99.9

0

Sagar Power

20060

5.43

37.34

7.73

2.11

57

12

18.4

3.4

54 | P a g e

Company Name

Year EndEquity

Gr. Blk

Sales

NP

NP Var%

Div %

B.V Rs

EPS Rs.

3 Spectrum Power

20060 3

117.93

1,056.2 2

295.07

139.38

-89

0

-10.7

0

Sun Source (I)

20040 3

14.39

3.41

0.11

0

0

0

12.5

0

Supreme Renew

20030 3

25

132.39

3.07

0.13

0

0

10

0.1

Company Name

Year EndEquity

Gr. Blk

Sales

NP

NP Var%

Div %

B.V Rs

EPS Rs.

TCP

20060 3

5.04

210.56

194.33

25.16

-12

100

283.5

48.5

Tata Power Co.

20060 3

197.9

5,924.7 4

4,608.1 1

472.47

23

85

280.7

22.7

Terra Energy

20060 9

24.21

161.02

45.52

6.07

0

0

27.4

2.5

Thermax EPS

2001

1.94

0.04

2.6

0.12

-20

0

0.3

0.6

Torrent Power

20060 9

472.45

2,799.9 6

3,831.5 2

186.4

0

8

55.7

2.5

Utility Powertec

20040 3

2

2.44

86.12

3.45

-25

100

42.4

16

Vennar Ceramics

20060 3

4.97

11.85

3.64

0.01

-90

0

11.8

0

954.57

5,311.9 3

2,304.4 2

9.13

586

0

1,154.1 9.6 0

West Pow.

Bengal 20040 3

ICRA Long-Term Rating Scale: For Bonds, Non-Convertible Debentures (NCDs), and other Debt Instruments (excluding Public Deposits), all with original maturity exceeding one year. LAAA: The highest-credit-quality rating assigned by ICRA. The rated instrument carries the lowest credit risk. LAA: The high-credit-quality rating assigned by ICRA. The rated instrument carries low credit risk. LA: The adequate-credit-quality rating assigned by ICRA. The rated instrument carries average credit risk. LBBB: The moderate-credit-quality rating assigned by ICRA. The rated instrument carries higher than average credit risk.

55 | P a g e

LBB: The inadequate-credit-quality rating assigned by ICRA. The rated instrument carries high credit risk. LB: The risk-prone-credit-quality rating assigned by ICRA. The rated instrument carries very high credit risk. LC: The poor-credit-quality rating assigned by ICRA. The rated instrument has limited prospect of recovery. LD: The lowest-credit-quality rating assigned by ICRA. The rated instrument has very low prospect of recovery. Source: ICRA http://www.icraratings.com/drsscale.asp

CRISIL Rating For Bonds, Non-Convertible Debentures (NCDs), and other Debt Instruments (excluding Public Deposits), all with original maturity exceeding one year.

Symbol(Rating category)

Description(with regard to the likelihood of meeting the debt obligations on time)

AAA

Highest Safety

AA

High Safety

A

Adequate Safety

BBB

Moderate Safety

BB

Inadequate Safety

B

High Risk

C

Substantial Risk

D

Default

Source: CRISIL http://www.crisil.com/credit-ratings-risk-assessment/rating-scales-long-term.htm

Formula Used Capital Employed = Net Block + Capital Work in Progress + Working Capital Market Capitalisation = No. of Equity Subscribed Shares* Market Value Enterprise Value = Market Captilaisation + Debt + Minority Shareholding – Cash and cash equivalents ROCE (Return on Capital Employed) = EBIT/Capital Employed EBIT = Business Earnings Before Interest and Tax Net Worth = Paid up Capital + Reserve and Surplus – Accumulated Loss

56 | P a g e