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Description of Power Sector of India and analysis of project economics - Abhishek Anand
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2007
IIM Indore
Abhishek Anand
[ASTRO MEASAT SUMMER INTERNSHIP PROJECT] Power Sector Analysis and Project Economics
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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
27.68%
28.97%
28.72%
12.66%
1.91%0.06%
Installed Capacity
Northern Region
Western Region
Southern Region
Eastern Region
North Eastern Region
Islands
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30%
56%
12% 2%
Source of Generation -Southern Region
HYDRO
Thermal
RES
NUCLEAR
15%
84%
1%0%
Source of Generation -Eastern Region
HYDRO
Thermal
RES
NUCLEAR
47%
51%
2%0%
Source of Generation -North Eastern
Region
HYDRO
Thermal
RES
NUCLEAR
19%
73%
3% 5%
Sources of Generation Western Region
HYDRO
Thermal
RES
NUCLEAR
6%
87%
7% 0%
Source of Generation -Islands
HYDRO
Thermal
RES
NUCLEAR
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Total Installed Capacity:
Sect
or
MW %age
State Sector 71,250 55.4
Central Sector 43,231 33.7
Private Sector 13,951 10.9
Total 1,28,432
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
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) 593,732
Central and State sector are the
dominant players in the generation
with private sector contributing only
10.9% of total installed capacity
Coal is the primary source of fuel for
generation and accounts for over 50%
of generation.
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).
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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.
Villages Electrified 30th May
2006)
471,360
Electrification %age 79.40%
Rural Households (Census
2001)
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
MU
-9.30%
Peak Demand 100,403
MW
86,425
MW
-13.90%
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
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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:
National Load Dispatch Centres
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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. Non-
conventional 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 south-
eastern 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 end-
user 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 South-
east 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
Central Sector
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
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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
Fuel price outlook
Domestic 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.
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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.
Fixed Component
19 | P a g e
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. Interest on long-term debt
2. Depreciation
3. O&M expenses (including insurance expenses)
4. Return on equity
5. Incentive return on equity
6. Interest on working capital
7. 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
20 | P a g e
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.
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
Average frequency of time block
(Hz)
21 | P a g e
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
employed is considered for depreciation. Land cost should not be
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.
YearRs in
million/MW
2009 1.190
2010 1.238
2011 1.287
2012 1.339
2013 1.392
2014 1.448
2015 1.506
2016 1.566
2017 1.629
2018 1.694
2019 1.761
2020 1.832
2021 1.905
2022 1.981
2023 2.061
2024 2.143
2025 2.229
2026 2.318
2027 2.411
2028 2.507
2029 2.607
2030 2.712
2031 2.820
2032 2.933
2033 3.050
2034 3.172
Operation and Maintenance Charges
22 | P a g e
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.
23 | P a g e
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 price Rs/Unit
Transportation Cost/
1000 Km per unit
Calorific Value
Kcal/unit
Heat Rate
kcal/kwh
Coal Domestic
(pithead) Kg 0.9 0.8 3500 2500
24 | P a g e
Tariff Computation of Various Components
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.
Year
Interest on
Long term Loan
Depreciati
on ROE
Interest on
working
capital
O&M
Charges Tax Incentive
Total
Fixed
Cost Fuel Cost
per unit
cost
2009 0.271 0.193 0.243 0.039 0.172 0.0801 0.1075 1.1055 0.73 1.8397
2010 0.256 0.193 0.243 0.040 0.179 0.0801 0.1075 1.0983 0.73 1.8326
2011 0.240 0.193 0.243 0.040 0.186 0.0801 0.1075 1.0903 0.73 1.8245
2012 0.223 0.193 0.243 0.041 0.193 0.0801 0.1075 1.0813 0.73 1.8155
2013 0.204 0.193 0.243 0.042 0.201 0.0801 0.1075 1.0712 0.73 1.8054
2014 0.184 0.193 0.243 0.043 0.209 0.0801 0.1075 1.0598 0.73 1.7941
2015 0.162 0.193 0.243 0.044 0.217 0.0801 0.1075 1.0472 0.73 1.7815
2016 0.139 0.193 0.243 0.045 0.226 0.0801 0.1075 1.0331 0.73 1.7674
2017 0.113 0.193 0.243 0.046 0.235 0.0801 0.1075 1.0175 0.73 1.7517
2018 0.085 0.193 0.243 0.047 0.245 0.0801 0.1075 1.0000 0.73 1.7343
2019 0.055 0.193 0.243 0.048 0.254 0.0801 0.1075 0.9807 0.73 1.7150
2020 0.022 0.193 0.243 0.049 0.265 0.0801 0.1075 0.9593 0.73 1.6935
2021 0.193 0.243 0.051 0.275 0.0801 0.1075 0.9493 0.73 1.6836
2022 0.193 0.243 0.052 0.286 0.0801 0.1075 0.9617 0.73 1.6960
2023 0.193 0.243 0.053 0.298 0.0801 0.1075 0.9746 0.73 1.7088
2024 0.193 0.243 0.055 0.309 0.0801 0.1075 0.9880 0.73 1.7223
2025 0.193 0.243 0.057 0.322 0.0801 0.1075 1.0020 0.73 1.7363
2026 0.193 0.243 0.058 0.335 0.0801 0.1075 1.0166 0.73 1.7509
2027 0.193 0.243 0.060 0.348 0.0801 0.1075 1.0318 0.73 1.7661
2028 0.193 0.243 0.062 0.362 0.0801 0.1075 1.0476 0.73 1.7819
2029 0.193 0.243 0.064 0.377 0.0801 0.1075 1.0642 0.73 1.7984
2030 0.193 0.243 0.066 0.392 0.0801 0.1075 1.0814 0.73 1.8156
2031 0.193 0.243 0.068 0.407 0.0801 0.1075 1.0993 0.73 1.8335
2032 0.193 0.243 0.071 0.424 0.0801 0.1075 1.1180 0.73 1.8522
2033 0.193 0.243 0.073 0.440 0.0801 0.1075 1.1375 0.73 1.8717
25 | P a g e
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:
26 | P a g e
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.
27 | P a g e
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. Appointment of Consultant to undertake studies and preparation of Project Report
2. Initiate land acquisition proceedings
3. Allocation of fuel blocks for pit-head projects
4. Allocation of water through State Government/concerned statutory authority
5. Appointment of Consultant for ICB, preparation of document and evaluation of bids
6. Obtain various approvals and statutory clearances
7. Commitment of Payment Security Mechanism (PSM) and Off-take of power by Distribution Utilities.
28 | P a g e
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
29 | P a g e
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.
30 | P a g e
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.
31 | P a g e
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.
32 | P a g e
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
34 | P a g e
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
35 | P a g e
PLF comparison of NTPC vs. other power producers
NTPC Subsidiaries and JVs
36 | P a g e
Growth plans – Power projects Planned
37 | P a g e
38 | P a g e
Shareholding Pattern
Sr. No Category of shareholder
Number
of
sharehold
ers
Total number
of shares
Number of
shares held
in de
materialized
form
% of
shares
(A+B)
% of
shares
(A+B+C)
(A)
Shareholding of Promoter and
Promoter Group
-1 Indian
(a) Individuals/ Hindu Undivided Family 0 0 0 0 0
(b)
Central Government/ State
Government(s) 1 7379634400 7379634400 89.5 89.5
(c) Bodies Corporate 0 0 0 0 0
(d) Financial Institutions/ Banks 0 0 0 0 0
(e) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(1) 1 7379634400 7379634400 89.5 89.5
-2 Foreign
(a)
Individuals (Non- Resident
Individuals/ Foreign Individuals) 0 0 0 0 0
(b) Bodies Corporate 0 0 0 0 0
(c) Institutions 0 0 0 0 0
(d) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(2) 0 0 0 0 0
Total Shareholding of Promoter and
Promoter Group (A)= (A)(1)+(A)(2) 1 7379634400 7379634400 89.5 89.5
(B) Public shareholding
-1 Institutions
(a) Mutual Funds/ UTI 69 45789389 45789389 0.56 0.56
(b) Financial Institutions/ Banks 32 6443352 6443352 0.08 0.08
(c)
Central Government/ State
Government(s) 0 0 0 0 0
(d) Venture Capital Funds 0 0 0 0 0
(e) Insurance Companies 14 53261004 53261004 0.65 0.65
(f) Foreign Institutional Investors 180 581304573 581304573 7.05 7.05
(g) Foreign Venture Capital Investors 0 0 0 0 0
(h) Any Other (specify)
0 0 0 0 0
Sub-Total (B)(1) 295 686798318 686798318 8.34 8.34
-2 Non-institutions
(a) Bodies Corporate 3072 26986675 26986675 0.33 0.33
(b) Individuals
(i)
Individual shareholders holding
nominal share capital up to Rs. 1 lakh 578248 146170920 146069936 1.77 1.77
(ii)
Individual shareholders holding
nominal share capital in excess of Rs.
1 lakh 476 1613951 1613951 0.02 0.02
(c) Any Other (specify)
Non Resident 4208 2785072 2785072 0.03 0.03
Clearing Members 492 1011395 1011395 0.01 0.01
Foreign Nationals 2 714 714 0 0
Trusts 69 462955 462955 0.01 0.01
Sub-Total(B)(2) 586567 179031682 178930698 2.17 2.17
Total Public Shareholding (B)=
(B)(1)+(B)(2) 586862 865830000 865729016 10.51 10.51
TOTAL(A)+(B) 586863 8245464400 8245363416 100.01 100.01
(C)
Shares held by Custodians and against
which Depository Receipts have been
issued 0 0 0 0
GRAND TOTAL (A)+(B)+(C) 586863 8245464400 8245363416 100
39 | P a g e
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)
40 | 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):
41 | 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.
42 | P a g e
Shareholding pattern
Sr. No Category of shareholder
Number of
shareholders
Total number
of shares
Number of shares
held in de
materialized form
% of
shares
(A+B)
% of
shares
(A+B+C)
(A)
Shareholding of Promoter and
Promoter Group
1) Indian
(a)
Individuals/ Hindu Undivided
Family 0 0 0 0 0
(b)
Central Government/ State
Government(s) 0 0 0 0 0
(c) Bodies Corporate 13 63766080 63765328 32.28 32.22
(d) Financial Institutions/ Banks 0 0 0 0 0
(e) Any Other (specify)
Trust 3 65624 65624 0.03 0.03
Sub-Total (A)(1) 16 63831704 63830952 32.31 32.25
2) Foreign
(a)
Individuals (Non- Resident
Individuals/ Foreign Individuals) 0 0 0 0 0
(b) Bodies Corporate 0 0 0 0 0
(c) Institutions 0 0 0 0 0
(d) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(2) 0 0 0 0 0
Total Shareholding of Promoter
and Promoter Group (A)=
(A)(1)+(A)(2) 16 63831704 63830952 32.31 32.25
(B) Public shareholding
1) Institutions
(a) Mutual Funds/ UTI 113 5563425 5470953 2.82 2.81
(b) Financial Institutions/ Banks 196 1756981 1705303 0.89 0.89
(c)
Central Government/ State
Government(s) 6 198155 172899 0.1 0.1
(d) Venture Capital Funds 0 0 0 0 0
(e) Insurance Companies 44 45304744 45279920 22.93 22.89
(f) Foreign Institutional Investors 164 37162888 37155740 18.81 18.78
(g) Foreign Venture Capital Investors 0 0 0 0 0
(h) Any Other (specify)
0 0 0 0 0
Sub-Total (B)(1) 523 89986193 89784815 45.55 45.47
2) Non-institutions
(a) Bodies Corporate 1684 1802846 1581445 0.91 0.91
(b) Individuals
(i)
Individual shareholders holding
nominal share capital up to Rs. 1
lakh 139389 39122294 26396307 19.8 19.77
(ii)
Individual shareholders holding
nominal share capital in excess of
Rs. 1 lakh 135 2723658 2494584 1.38 1.38
(c) Any Other (specify)
Overseas Corporate Bodies 4 1160 0 0 0
Trust 36 74849 73459 0.04 0.04
Sub-Total(B)(2) 141248 43724807 30545795 22.13 22.1
Total Public Shareholding (B)=
(B)(1)+(B)(2) 141771 133711000 120330610 67.68 67.57
TOTAL(A)+(B) 141787 197542704 184161562 99.99 99.82
(C)
Shares held by Custodians and
against which Depository Receipts
have been issued 3 355160 354930 0.18
GRAND TOTAL (A)+(B)+(C) 141790 197897864 184516492 100
43 | P a g e
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 $13
billion.
Of which 12500 MW would be gas, coal, wind and hydro based power generation projects in Maharastra,
Uttar Pradesh, Andhra Pradesh and Uttranchal. These projects are in various stages of development.
The Dadri Power Plant being constructed has a capacity of 5500MW.This gas generation power plant is
proposed to be the single largest gas grass root gas fired generation plant in the world.
A 4000 MW Power Project at Shahapur in Maharastra.
44 | P a g e
Reliance's gas finds in KG-D6 block in Krishna Godavari basin which constitutes 60% of India's present
total gas production, will provide an enormous opportunity to scale up power generation capacities in
India.
Reliance Energy is also participating in emerging opportunities in the areas of trading and transmission of
power.
Reliance Energy is looking at bidding for Global Power Assets.
Key Financials
Key Management Personnel
Anil D. Ambani - Chairman & Managing Director
Regarded as one of the foremost corporate leaders of contemporary India, Anil Dhirubhai Ambani is the
Chairman of all listed Group companies, namely: Reliance Communications, Reliance Capital, Reliance Energy
and Reliance Natural Resources Limited. Till recently, he also held the post of Vice Chairman and Managing
Director in Reliance Industries Limited (RIL), India's largest private sector enterprise.
Anil D Ambani joined Reliance in 1983 as Co-Chief Executive Officer, and was centrally involved in every aspect
of the company's management over the next 22 years.
He is credited with having pioneered a number of path-breaking financial innovations in the Indian capital
markets. He spearheaded the country's first forays into the overseas capital markets with international public
offerings of global depositary receipts, convertibles and bonds. Starting in 1991, he directed Reliance
Industries in its efforts to raise over US$ 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
Units 2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 2006-07
Installed Capacity 508 508 885 941 941 941 941
PLF % 82.6 87.8 90.5 138 86 86 NA
Financials
Networth Rs. Million 25761.5 26778 25592 43544 50193 78732.8
Net Sales Rs. Million 22724 26183 36906 34567 40479 40,759.00 68,315.70
OPBDIT Rs. Million 5104 5275 4022 6931 6710 8605 14,760.00
Net Profit Rs. Million 2955 3051 1218 2383 3874 6503.4 8,597.70
Ratios
Operating Profit Margin 22.5% 20.1% 10.9% 20.1% 16.6% 21.1% 21.6%
Net Profit Margin 13.0% 11.7% 3.3% 6.9% 9.6% 16.0% 12.6%
Reliance energy
45 | 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) PLF
Thermal Power
(multi fuel based)
Dhanau near Mumbai
500
( 2x250)
98.70%
Wind Farm Jogimatti in Karnataka 8 34.1%
Cycle Power
Kochi ,Kerala 165 -
Samalkot,Andhra Pradesh 220 61%
Naptha based
(combined cycle power)
Goa
48 93.32%
Total 941
46 | P a g e
Details of Share Holding Pattern
Sr. No Category of shareholder
Number of
shareholders
Total number
of shares
Number of
shares held in
de
materialized
form
% of shares
(A+B)
% of shares
(A+B+C)
(A)
Shareholding of Promoter and Promoter
Group
1) Indian
(a) Individuals/ Hindu Undivided Family 11 663378 663371 0.3 0.29
(b) Central Government/ State Government(s) 0 0 0 0 0
(c) Bodies Corporate 22 78063368 78061712 34.98 34.16
(d) Financial Institutions/ Banks 0 0 0 0 0
(e) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(1) 33 78726746 78725083 35.28 34.45
2) Foreign
(a)
Individuals (Non- Resident Individuals/
Foreign Individuals) 0 0 0 0 0
(b) Bodies Corporate 0 0 0 0 0
(c) Institutions 0 0 0 0 0
(d) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(2) 0 0 0 0 0
Total Shareholding of Promoter and Promoter
Group (A)= (A)(1)+(A)(2) 33 78726746 78725083 35.28 34.45
(B) Public shareholding
1) Institutions
(a) Mutual Funds/ UTI 283 15023681 14979354 6.73 6.57
(b) Financial Institutions/ Banks 407 1545713 1528940 0.69 0.68
(c) Central Government/ State Government(s) 70 273462 195758 0.12 0.12
(d) Venture Capital Funds 0 0 0 0 0
(e) Insurance Companies 23 49034269 49033338 21.97 21.46
(f) Foreign Institutional Investors 511 46391612 46170812 20.79 20.3
(g) Foreign Venture Capital Investors 0 0 0 0 0
(h) Any Other (specify)
0 0 0 0 0
Sub-Total (B)(1) 1294 112268737 111908202 50.3 49.13
2) Non-institutions
(a) Bodies Corporate 6686 4074657 3918114 1.83 1.78
(b) Individuals
(i)
Individual shareholders holding nominal share
capital up to Rs. 1 lakh 1551487 25274026 18336283 11.33 11.06
(ii)
Individual shareholders holding nominal share
capital in excess of Rs. 1 lakh 47 1453826 1401204 0.65 0.64
(c) Any Other (specify)
NRIs / OCBs 17208 1367647 906387 0.61 0.6
Sub-Total(B)(2) 1575428 32170156 24561988 14.42 14.08
Total Public Shareholding (B)= (B)(1)+(B)(2) 1576722 144438893 136470190 64.72 63.21
TOTAL(A)+(B) 1576755 223165639 215195273 100 97.66
(C)
Shares held by Custodians and against which
Depository Receipts have been issued 3 5364669 5363938 2.35
GRAND TOTAL (A)+(B)+(C) 1576758 228530308 220559211 100
47 | P a g e
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 35-
38 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
48 | 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.
49 | P a g e
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 1,000-
megawatt 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:
50 | 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
Units 2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 2006-07
Installed Capacity MW 1065 1065 1065 1065 975 975 975
PLF % n.a. 73.4 75.6 80.2 85.6 NA NA
Financials
Networth Rs. Million 2001 4470.7 4865.7 10653.9 12724.9 16448.8
Net Sales Rs. Million 18054.5 21420.1 22491.5 24106.5 23911 26,727.00 25,830.00
OPBDIT Rs. Million 5687.9 6992.7 7872.7 8775 7413 7,917.40 6,690.00
Net Profit Rs. Million -1920.6 -879.6 97.4 1905.4 1506.5 1,774.70 2,970.00
Ratios
Operating Profit Margin 31.5% 32.6% 35.0% 36.4% 31.0% 29.6% 25.9%
Net Profit Margin -10.6% -4.1% 0.4% 7.9% 6.3% 6.6% 11.5%
CESC
51 | P a g e
Shareholding Pattern
Sr. No Category of shareholder
Number of
shareholders
Total
number of
shares
Number of
shares held in
de materialized
form
% of shares
(A+B)
% of shares
(A+B+C)
(A)
Shareholding of Promoter and Promoter
Group
-1 Indian
(a) Individuals/ Hindu Undivided Family 6 351302 351302 0.42 0.42
(b)
Central Government/ State
Government(s) 0 0 0 0 0
(c) Bodies Corporate 30 34166726 20724083 40.59 40.52
(d) Financial Institutions/ Banks 0 0 0 0 0
(e) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(1) 36 34518028 21075385 41.01 40.94
-2 Foreign
(a)
Individuals (Non- Resident Individuals/
Foreign Individuals) 0 0 0 0 0
(b) Bodies Corporate 0 0 0 0 0
(c) Institutions 0 0 0 0 0
(d) Any Other (specify)
0 0 0 0 0
Sub-Total (A)(2) 0 0 0 0 0
Total Shareholding of Promoter and
Promoter Group (A)= (A)(1)+(A)(2) 36 34518028 21075385 41.01 40.94
(B) Public shareholding
-1 Institutions
(a) Mutual Funds/ UTI 28 3404746 3397956 4.04 4.04
(b) Financial Institutions/ Banks 28 59547 38993 0.07 0.07
(c)
Central Government/ State
Government(s) 1 2152 0 0 0
(d) Venture Capital Funds 0 0 0 0 0
(e) Insurance Companies 5 7672440 7671222 9.11 9.1
(f) Foreign Institutional Investors 67 24385139 24373319 28.97 28.92
(g) Foreign Venture Capital Investors 0 0 0 0 0
(h) Any Other (specify)
0 0 0 0 0
Sub-Total (B)(1) 129 35524024 35481490 42.19 42.13
-2 Non-institutions
(a) Bodies Corporate 910 6869238 3997273 8.16 8.15
(b) Individuals
(i)
Individual shareholders holding nominal
share capital up to Rs. 1 lakh 25252 4983794 2875939 5.92 5.91
(ii)
Individual shareholders holding nominal
share capital in excess of Rs. 1 lakh 49 2284357 1895617 2.71 2.71
(c) Any Other (specify)
0 0 0 0 0
Sub-Total(B)(2) 26211 14137389 8768829 16.79 16.77
Total Public Shareholding (B)=
(B)(1)+(B)(2) 26340 49661413 44250319 58.98 58.9
TOTAL(A)+(B) 26376 84179441 65325704 99.99 99.84
(C)
Shares held by Custodians and against
which Depository Receipts have been
issued 1 138070 120719 0.16
GRAND TOTAL (A)+(B)+(C) 26377 84317511 65446423 100
52 | P a g e
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 - -
Tariff (Rs./Kwh) 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
(Rs. Per Kwh) 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+
*Market Capitalisation as on May 7, 2007
All financial figures for FY’ 06
53 | P a g e
Company Name Year End Equity 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 Andhra
Powe
20020
3
158.86 7.55 0 0 0 0 10 0
BSES Kerala
Pow.
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
D P S C 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 151.2
5
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
54 | P a g e
Company Name Year End Equity 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 Power
Co.
20030
3
66.78 331.1 66.73 10.46 398 0 11.8 1.6
Murdeshwar
Power
20000
3
8.44 53.88 7.48 2.47 0 0 21.6 2.9
Natl. Hydroelect 20060
3
10,215.2
8
12,755.
52
1,667.9
6
742.11 8 2 1,561.9
0
69.6
NE Elec. Power 20060
3
1,906.11 4,605.3
5
839.62 198.55 1 3 1,261.6
0
99.7
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
Nuclear Power
Co
20060
3
10,145.3
3
12,662.
06
3,567.0
6
1,683.0
3
-1 5 2,003.4
0
158.8
Power Grid
Corp.
20060
3
3,740.41 24,892.
25
3,145.3
4
1,009.0
2
28 8 2,705.3
0
258.4
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
55 | P a g e
Company Name Year End Equity 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 End Equity Gr. Blk Sales NP NP
Var%
Div
%
B.V Rs EPS
Rs.
T C P 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
West Bengal
Pow.
20040
3
954.57 5,311.9
3
2,304.4
2
9.13 586 0 1,154.1
0
9.6
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.
56 | 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
