power sector scenario

8/8/2019 Power Sector Scenario

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Power Scenario: In times to come

Some basic facts

Total Installed Capacity : 163 GW + 19.5 (Captive Capacity) Figures: July 2010

Base Load Deficit : 10.6% Expected 2010-11

Peak Load Deficit : 12.1% Expected 2010-11

Per Capita Cos : 646 KWh

Growth in Demand : 5.3% CAGR Annually

Number of Villages : 593,732 (1991 Census)

Villages Electrified : 498,735 (30 May 2006)

Village Electrification : 84.0%

Average PLF : 81.42% (June, 2010)

India is now the eleventh largest economy in the world, fourth in terms of purchasing power. It is

poised to make tremendous economic strides over next ten years, with significant economic

development already in planning stage.

Power is a major input for the socio economic development of a country and is one of the key

drivers for achieving GDP growth. In fact, the two are inter-related such that for a country to grow at

more than 8%, power sector has to grow at a similar rate. Unfortunately, the Indian power sector

has not kept pace with the continuously accelerating GDP growth rate of the economy with the

country facing severe energy and peaking power shortages pecked at 10.6% and 12.1% respectively.

Current installed capacity stands at 163 GW (excluding 19.5 GW captive capacities). Peak demand is

expected to touch 153 GW by 2012 and energy requirement is expected to be 9,69,000 GWh as per

17th EPS by CEA. With the deficit between the demand and supply position widening need for new

addition of generation capacity takes precedence. Renewable sources of energy are expected to

take front seat as the demand for cut down on emission as well as the concerns about the limitation

of coal reserves rises globally.


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Renewable Energy

Need for renewable energy

In the past century, it has been seen that the consumption of non-renewable sources of energy hascaused more environmental damage than any other human activity. Electricity generated from fossil

fuels such as coal and crude oil has led to high concentrations of harmful gases in the atmosphere.

This has in turn led to many problems being faced today such as ozone depletion and global

warming. Therefore, renewable sources of energy have become very important and relevant to

todays world. They cause fewer emissions and cannot be exhausted. Their use can, to a large

extent, reduce chemical, radioactive, and thermal pollution. They stand out as a viable source of

clean and limitless energy. These are also known as non-conventional sources of energy. Most of the

renewable sources of energy are fairly non-polluting and considered clean though biomass, a

renewable source, is a major polluter indoors. Renewable energy technologies vary widely in their

technical and economic maturity, but their common feature is that they produce little or no

greenhouse gas, and rely on virtually inexhaustible natural sources.

Present Scenario

India has the distinction of being the only country in the world to have an exclusive Ministry dealing

with new and Renewable Energy sources. During the last two and a half decades there had been a

vigorous pursuit of activities relating to the research, development, trial and induction of a variety of

Renewable Energy technologies for use in different sectors.

The Electricity Act 2003 contains several provisions to promote the accelerated development of

power generation from non- conventional sources. It provides that cogeneration and generation of

electricity for renewable sources would be promoted by the SERCs by providing suitable measures

for connectivity with grid and sale of electricity to any person and also by specifying, for purchase of

electricity for such sources, a percentage of the total consumption of electricity in the area of a

distribution licensee.

There has been a growing awareness of the benefits of Renewable Energy, mainly on account of

sustained public awareness generation campaigns. An outlay was provided under the Xth plan to

provide electrification to around 25,000 remote un-electrified villages and hamlets by 2007. The

government has set a target of installing 15% of the additional power generation capacity in the

country through grid-interactive renewable power by 2012. The present grid connected renewable

energy based installed capacity is 17173.90 MW whereas off-grid installed capacity is 420.32 MW as

on June 30, 2010.

Hydel Power

Need

Hydro power is a renewable economic, non-polluting and environmentally benign source of energy.

Hydro power stations have inherent ability for instantaneous starting, stopping, load variations etc.

and help in improving reliability of power system. Hydro stations are the best choice for meeting the

peak demand. The generation cost is not only inflation free but reduces with time. Hydroelectric

projects have long useful life extending over 50 years and help in conserving scarce fossil fuels. They

also help in opening of avenues for development of remote and backward areas.

As per the re-assessment studies carried out by CEA during 1978-87, the economically exploitable

hydro-electric power potential of the country has been estimated as 84044 MW at 60% load factor


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from 845 schemes. The hydro potential of 84044 MW at 60% load factor when fully developed

would result in an installed capacity of about 1,50,000 MW on the basis of probable average load

factor.

In addition, 6781.81 MW in terms of installed capacity from small, mini and micro hydel schemes

have been assessed. Also, 56 sites for pumped storage schemes with an aggregate installed capacity

of 94,000 MW have been identified. However, only 15% of the hydroelectric potential has beenharnessed so far and 7% is under various stages of development. Hence 78% of the hydel power

potential remains without any plan for exploitation. The basin wise estimated hydro potential and

probable installed capacities are given below:

Basin / RiverPotential at 60%Load Factor

Probable InstalledCapacity

Indus 19988 33832

Ganga 10715 20711

Central IndianRivers 2740 4152

West-flowingRivers

6149 9430

East-flowingRivers

9532 14511

Brahmaputra 34920 66065

Total 84044148701 say150,000

Source: CEA


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Major River systems India

Despite hydroelectric projects being recognised as the most economic and preferred source of

electricity, share of hydro power has been declining steadily since 1963. The share of hydro power

has been continuously declining during the last three decades. The hydro share has declined from 44

per cent in 1970 to 25 per cent in 1998. The ideal hydro thermal mix should be in the ratio of 40:60.

The present hydro power share is only 22.6%.


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Because of an imbalance in the hydel thermal mix especially in the Eastern and Western regions,

many thermal power stations are required to back down during off peak hours. The capacity of the

thermal plants cannot be fully utilised resulting in a loss of about 4 to 5 per cent in the plant load

factor.

Region wise Installed Capacity - July 31,

2010

Northern 13430.75

Western 7447.50

Southern 11157.03

Eastern 3882.12

North Eastern 1116.00

Total 37033.40

Advantages

1. The pollution created by hydroelectric energy generation is quite minimal. It also does not

produce radioactive waste or involve the environmental impact of fuel being transported to

it.

2. When in use, electricity produced by dam systems do not produce green house gases. They

do not pollute the atmosphere.

3. Another of its advantages is that hydroelectric is a renewable form of energy, like wind andsolar; it does not rely upon finite resources like natural gas or coal to generate power.


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4. Fuel for a hydel power project is free of cost as the water flow that is used to produce

electricity does not cost anything. Moreover the fuel is inflation free.5. Operational cost of running a hydel power plant is minimal since it doesn't require

many employees to run a hydroelectric station. Most plants of this type are largely

automated. This is another one of the advantages which help keep the cost of

hydroelectricity low.

6. Hydro projects provide valuable peak power and have inherent capability for instantaneousstarting and stoppage based on variation of load.

7. If electricity is not needed, the sluice gates can be shut, stopping electricity generation. The

water can be saved for use another time when electricity demand is high.8. The lake that forms behind the dam can be used for secondary purposes such as irrigation,

pisciculture, water sports and leisure / pleasure activities. Often large dams become tourist

attractions in their own right.9. Hydroelectric power stations can be set up in almost any size, depending upon the

river or stream used to operate them; big enough to power a single home, factory,

small town, or large city.10. Dams are designed to last many decades and so can contribute to the generation of

electricity for many years / decades.11. The build up of water in the lake means that energy can be stored until needed, when the

water is released to produce electricity.

DISADVANATGES:

1. Dams are extremely expensive to build and must be built to a very high standard.

2. The high cost of dam construction means that they must operate for many decades to

become profitable.

3. The flooding of large areas of land means that the natural environment is destroyed.

4. People living in villages and towns that are in the valley to be flooded, must move out. Thismeans that they lose their farms and businesses. In some countries, people are forcibly

removed so that hydro-power schemes can go ahead.

5. The building of large dams can cause serious geological damage. For example, the building of

the Hoover Dam in the USA triggered a number of earth quakes and has depressed the

earths surface at its location.

6. Although modern planning and design of dams is good, in the past old dams have been

known to be breached (the dam gives under the weight of water in the lake). This has led to

deaths and flooding.

7. Dams built blocking the progress of a river in one country usually means that the water

supply from the same river in the following country is out of their control. This can lead to

serious problems between neighbouring countries.8. Building a large dam alters the natural water table level. For example, the building of the

Aswan Dam in Egypt has altered the level of the water table. This is slowly leading to

damage of many of its ancient monuments as salts and destructive minerals are deposited in

the stone work from rising damp caused by the changing water table level.

Constraints

The constraints which have affected hydro development are technical (difficult investigation,

inadequacies in tunnelling methods), financial (deficiencies in providing long term financing),

tariff related issues and managerial weaknesses (poor contract management). The hydro

projects are also affected by geological surprises (especially in the Himalayan region where

underground tunnelling is required), inaccessibility of the area, problems due to delay in land

acquisition, and resettlement of project affected families, law & order problem in militant

infested areas.


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Constraints Affecting Hydro Development

The main barriers/concerns that have come in the way of development of hydropower projects

are briefly discussed below.

Longer gestation period and capital intensive nature of the projects: Preparation of

detailed projects reports (DPRs) for hydropower projects takes relatively longer period than

for thermal projects because reliable hydrological, geological, seismological andenvironmental studies have to be carried out for a longer period. Thus hydropower projects

generally entail a long gestation period. In addition to this, these projects are comparatively

capital intensive. In the context of resource shortages and continuing power shortages,

thermal projects (coal, liquid fuel and gas), which need a relatively short gestation period,

have been getting priority in fund allotments.

Dearth of good contractors: A matter of concern in the execution of large projects is the

dearth of competent and resourceful contractors, as it often results in time and cost

overruns of hydro projects.

Inter-state aspects: A large number of hydropower projects having common river systems

between adjoining states are held up on account of inter-state aspects. Some of these

projects have received the techno-economic clearance (TEC) of CEA but the investment

sanction could not be accorded due to inter-state aspects. A number of projects have also

not been accorded CEA clearance on account of inter-state issues.

Environmental impact and rehabilitation issues: Important environmental concerns in

hydro-electric projects are: (a) rehabilitation of project-affected people; (b) deforestation;

(c) likely submergence of archaeological, religious and historical monuments; (d) protection

of flora, fauna, forests, and wildlife; (e) degradation of catchment area; and (f) disaster

potential in the event of earthquakes, reservoir induced seismicity, surplusing of reservoirs,

etc. Rehabilitation of project-affected people is also a major issue in implementation,

especially in case of storage-based hydro development. It is essentially a human problem

and has to be dealt with understanding and sensitivity. In fact, many times it is one of the

main reasons for the delay in the execution of projects. Sardar Sarovar, Indira Sagar,

Bansagar Tons and Tehri are some of the hydro projects where the progress had been

severely hampered in the past from sustained opposition to project construction by

environment activists and project-affected people.

Valuation of forestland based on net present value: The manner of valuation of forest land

diverted for non-forestry purposes based on the net present value (NPV) of diverted land

has been a matter of concern for developers of hydropower projects. As per the

recommendations of a Centrally Empowered Committee (CEC), the NPV of forestland

diverted for non-forest use has been charged at Rs5.809.20 lakhs per hectare, depending

upon the density of forest involved. Under NPV, the state government has to pay to the CEC

the NPV of forestland lost to mining and other projects, including resettlement. State

governments, in turn, have asked for exemption in case of projects such as government

hospitals, schools, and rainwater harvesting meant for public welfare. In some cases, it is

argued that loading of NPV on the project may result in increase in tariff of hydro-

electricity.There is thus an urgent need to rationalize NPV calculations of forestland in case

of hydroelectric projects. The matter had also come up before the Supreme Court of India,

which has directed the formation of a committee to look into various issues pertaining to

assessment of NPV. The Energy and Resources Institute is also undertaking a study to

analyze various aspects of NPV calculation for hydroelectric projects in India.

Law and order problems: Disturbed law and order is one of the factors causing delay in

project execution and even suspension of work. Some of the hydropower projects affected

due to these problems are Dulhasti, Upper Sindh, Doyang and Dhansiri. Land acquisition

problems: The problems arising in acquisition of land for hydropower project are causing

suspension and delay in the construction activities. Thein Dam, Doyang, Ghatgar pumped

storage plants are some of the projects affected in the past due to this problem.


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Geological surprises: The features of the hydropower projects being site specific, depend on

the geology, topography and hydrology at the site. The construction time of a hydro project

is greatly influenced by the geology of the area and its accessibility. Even when extensive

investigation using new techniques of investigations are undertaken, an element of

uncertainty remains in the sub-surface geology and the geological surprises during actual

construction cannot be ruled out. This in turn adds to the construction risks.

Power evacuation: A number of the hydropower projects are located in remote sites andthe home states do not have adequate demand. Timely provision of power evacuation

system presents many complexities in such cases, since (a) the beneficiaries are to be

identified well in advance, and (b) where there are serious right-of-way constraints, excess

capacity would have to be built in one go considering likely future development of projects

in the evacuation corridor. This could result in high transmission tariffs initially and also

adversely affect sustainability of the project in case of slippages in projects. These issues are

especially relevant in case of projects in NER.

Lack of private sector interest: The private sector has also not been evincing much interest

in taking up hydro projects in view of non-availability of adequately investigated projects,

construction risks, etc.

Tariff and regulatory issues:The existing tariff formulation norms for hydro projects (based

on a cost plus approach) with no premium for peaking services and the provision for 12%

free power to distressed states from the initial years are also proving to be deterrents.

Small hydro segment: Development of small hydro often suffered due to inaccessibility of

the sites, lack of power evacuation infrastructure, investigation and construction difficulties,

land acquisition and financing difficulties, inadequacies in institutional support and in some

cases law and order problems.

Government of India initiatives for development of hydel power

Preparation of Preliminary Feasibility Reports under 50,000 MW Hydroelectric

Initiative:

Prime Minister of India launched a programme for preparation of Preliminary Feasibility Reports

(PFRs) in respect of 162 Hydro-electric Schemes with an aggregate capacity of 47,930 (located in 16

States). Under this scheme, 11 Hydro projects were identified in the state of Sikkim with an

aggregate capacity of 1,430 MW.


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The basin wise details of Preliminary Feasibility Report prepared under the above programme aregiven below:

River Basin No. of Schemes Probable Installed Capacity (MW)

Indus 28 6003

Ganga 33 5282

Central India 3 205

West Flowing 6 726

East Flowing 20 2829

Brahmaputra 72 31885

All India 162 47930

Policy on Hydro Power Development (1998)

Liberalization measures in the year 1991 with a view to bring in additional resources for capacity

addition in Hydel front did not provide expected impetus to hydropower development. It also did

not generate much interest in private sector participation. Based on a review of the situation, GoI

brought out a policy on Hydro Power Development in the year 1998, which, inter alia, laid down

several policy instruments like full budgetary support to ongoing projects, establishment of a power

development fund, a mechanism to resolve interstate issues etc. Several initiatives were taken to

provide incentives to hydropower projects, which included the following:

Tariff was rationalised for hydro projects

The procedures of tech-economic clearance and the ceiling limits for techno-economicclearance by CEA were simplified

Small hydro projects upto 25 MW capacity were transferred to the Ministry of Non-

conventional Energy Sources (MNES)

Hydropower projects on MOU route were enhanced and notified to cover geological risks.

The policy also opined that, in case of private sector participation, project below 100 MW

capacities should be routed through MoU with respective state Government where as

project with capacity above 100 MW should be awarded through a competitive bidding

process

The Electricity Act, 2003

The conceptual framework underlying the Electricity Act, 2003 is that the electricity sector must be

opened-up for competition. The Act moves towards creating a market-based regime in the power

sector and is expected to provide a momentum for the overall development of the power sector in

India including development of Hydro Power. The Act seeks to consolidate, update and rationalize

laws related to generation, transmission, distribution, trading and use of power. It focuses on:

Creating competition in the industry

Ensuring supply of electricity to all areas

Encouraging autonomous regulation with the separation of policy, regulatory and

operational aspects

Some of the major provisions of the Electricity Act, 2003 are:

De-licensing of electricity generation

Provision for Open Access from the onset of the act with respect to transmission


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Open access in distribution is to be introduced in phases, and a surcharge for current level of

cross-subsidy will be gradually phased out along with cross-subsidies and obligation to

supply

Introduction of the concept of power trading as a distinct activity, and the introduction of a

spot market for bulk electricity

Further, the Act also allows independent power producers (IPPs) and captive power producers openaccess to transmission lines, thus allowing them to bypass the state utilities and sell power directly

to distribution and trading licensees.

The Act also provides for open access in distribution, thus opening the way for competition in the

retail supply segment. However, as State Regulatory Commissions (SERC) have the discretion to

allow open access; the whole process of granting open access in distribution sector would be

implemented in a phased manner based on the state of readiness of individual states.

New Hydro Policy 2008

The new hydro policy addresses different issues pertaining to development of hydro potential. The

provision to award projects to developers through tariff base bidding up to 2011 will give private

players flexibility to tie up with states for setting up projects. In order to enable the project

developer to recover the cost incurred by him in obtaining the project site, the policy permits a

special incentive by way of up to 40% of saleable energy for trade as merchant sales. This policy aims

for the welfare creation and creation of infrastructure and common facilities to achieve 1%

additional power above the existing 12% free power provided exclusively for local area

development. Under the policy, the government is likely to provide soft loans for small hydro plants

with capacity up to 25 MW.


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Power Sector in the Past

Growth of Installed Generation Capacity in India

India has installed power generation capacity of 163669.80 MW as on July 31, 2010, which is about

120 times the installed capacity in 1947 (1362 MW).The installed capacity and its growth rates since 1947 are given below

Installed Capacity

As on

Installed

Capacity

Annual Growth

Rate (%)

Capacity Addition in

the Year

Capacity Addition in

the Plan

1947 1,362 - - -

31.3.1979 (End of 5th

Plan)

26,680 - - -

31.3.1985 (End of 6th

Plan)

42,585 9.9 - 15,905

31.3.1990 (End of 7th

Plan)

63,636 - - 21,051

31.3.1991(AP) 66,086 3.9 2,450

31.3.1992(AP) 69,065 4.5 2,979

31.3.1993 72,330 4.7 3,265

31.3.1994 76,753 6.1 4,423

31.3.1995 81,171 5.8 4,418

31.3.1996 83,293 2.6 2,122

31.3.1997 (End of 8th

Plan)

85,795 3.0 2,502 16,730

31.3.1998 89,102 3.9 3,307

31.3.1999 93,293 4.7 4,191

31.3.2000 97,884 4.9 4,591

31.3.2001 1,01,626 3.8 3,742

31.3.2002 (End of 9th

Plan)

1,05,046 3.4 3,420 19,251

31.3.2003 1,07,877 2.7 2,831

31.3.2004 1,12,683 4.5 4,806

31.03.2005 1,18,425 5.1 5,742

31.03.2006 1,24,287 4.9 5,862

31.03.2007 (End of

10th Plan)

1,32,329 6.5 8,042 21,095

31.03.2008 1,43,061 7.5 10,732

31.03.2009 1,47,965 3.4 4,904

31.03.2010 1,59,398 7.72 9,585


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Since independence, there has been sizeable growth in the power sector. At the time of inception of

planning era, generating capacity in the country was only 1,750 MW which has increased to 159 GW

today (as on 31.03.2010). The annual generation has grown from about 5 billion units to 772 billion

units. Despite, rapid increase in population over period of time, per capita consumption has

increased from 15 kWh to 735 kWh during 2008-09. Growth profile in respect of Installed capacity

and per capita electricity consumption is given in figures present below:

Growth in Installed Generation Capacity

Power Sector remained largely ignored till the sixth five-year plan. After which the need for

investments in power sector were realised. Incidentally major focus shift towards power sector

coincided with liberalisation of the economy.

Growth in installed capacity

Source CEA


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Generation Capacity based on Feedstock

Breakup of Installed Capacity since Sixth Plan (source wise)Plan/Year Hydro Thermal Renewable Energy Sources Nuclear Total

March 1985 (End of 6th Plan) 14460.00 27030.00 1095 42585.00

March 1990 (End of 7th Plan) 18308.00 43763.00 1565 63636.00

March 1992 (End of 2 Annual Plans) 19194.00 48086.00 1785.00 69065.00

March 1997 (End of 8th Plan) 21658.00 61912.00 2225.00 85795.00

March 1998 21904.51 6404.64 968.12 2225.00 89102.27

March 1999 22479.13 67565.41 1024.01 2225.00 93293.55

March 2000 23857 70493 1154.88 2680.00 98184.47

March 2001 25142.00 72355.00 1269.00 2860.00 101626.00

March 2002 (End of 9th Plan) 26269.00 74549.54 1507.46 2720.00 105046.00

March 2003 26910.23 76606.91 1735.66 2720.00 107972.80

March 2003 29500.23 77968.53 1869.66 2720.00 112058.42

July 2004 29625.23 78491.45 1869.66 2720.00 112706.34

March 2006 32135.05 82497.44 6158.32 3310.00 124100.81

March 2007 (End of 10th Plan) 34653.77 86014.84 7760.60 3900.00 132329.21

March 2008 35908.76 91906.84 11125.41 4120.00 143061.01

March 2009 36877.76 93725.24 13242.41 4120.00 147965.41

March 2010 36863.40 102453.98 15521.11 4560.00 159398.49

Despite hydroelectric projects being recognised as the most economic and preferred source of

electricity, share of hydro power has been declining steadily since 1963. The share of hydro power

has been continuously declining during the last three decades. The hydro share has declined from 44per cent in 1970 to 25 per cent in 1998. The ideal hydro thermal mix should be in the ratio of 40:60.

The present hydro power share is only 22.6%.

Source CEA

Fuel Mix (in %)

The generation capacity in India comprises of a mix of thermal, hydro, nuclear, and renewable

energy. Over the years thermal energy has become a dominant source of power generation. As of

Jan 2010, thermal energy contributed 64% (100,351.5 MW) of the countrys total power generating

capacity, while hydro energy contributed 24% (36,885.40 MW), renewable energy sources around

9.8% (15,427.10 MW), and nuclear energy contributed 3% (4,120 MW) to the total capacity.

Thermal fuel maintains a leading position among the fuel used for power generation. In spite of

efforts to reduce the countrys dependence on thermal base generation, the cost (relatively higher

for other sources of generation) or the unavailability of other sources of energy have remained a

constraint. During the Tenth 5-year Plan, the planned capacity addition had a greater focus on the


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thermal generation space and the same trend has been continuing during the Eleventh 5-year Plan.

Most of the power generation capacity will continue to be thermal as most upcoming projects are

coal-based.

Hydropower is an environment-friendly alternative for thermal power generation and the operating

cost for running a hydro plant is also very low; however, its share in generation has remained

constant and has not attracted much investment. The hydro-thermal mix has maintained a leading

position over the years, but the share of hydropower plants in total generation has fallen over theyears. In the mid-eighties, the share of hydropower in total generation was comparable to that of

thermal generation, but, since then, investments in hydropower generation have risen at a lower

rate than investments in thermal generation. Though the operating cost for hydropower plants is

lesser, the capital investment required in the initial stage is huge. Investors have shied away from

the sector because of delays in environment clearances that have made the sector an unfavourable

choice and have restricted capacity addition in the sector. Thermal energy, on the other hand, has

gained a greater share over the 5-year plan periods and its growth rate has also been much higher,

as investments from public as well as private sectors have continued to pour in. In the Eleventh Plan

also capacity addition focuses more on thermal power generation, which suggests that thermal

energy will remain the dominant source in the coming years.

Nuclear energy has had a very small share in the power generation pie, but its share in total power

generation is likely to raise post the Indo-US Nuclear Civilian Agreement. India has only one nuclear

power generation company, NPCIL, with a capacity of 4,120 MW.

The renewable sources of power generation include wind power, small hydro power, biomass

power, Urban & Industrial (U&I) waste to power, solar power etc. Among these sources, wind power

has a leading share of 70% in the RES, while small hydro has 7%, cogeneration-bagasse 7%, biomass

5% and solar & waste to energy constitute less than 1%.

India has an expansive coastline belt from Gujarat to Kerala and from Kerala to West Bengal that

provides ample scope for wind power generation. Indias wind power potential has been assessed at

45,000 MW. During the last 5 years, wind power generation projects received increased investments

from the government as well as from private players, which resulted in significant capacity additions.

Indias solar power capacity is around 2 MW and the share of solar power in the current fuel mix is

not very high. However, the trend is all set to change as large numbers of small and large-size solar

projects are coming up in the near future.

During the last 6 years (FY04-FY09), growth in power generation capacity based on different fuel

types was impressive. Among the sources, renewable energy sources grew at a CAGR of 39.71%, and

most of the growth in this segment came from wind power. The capacity addition in the segment

based on thermal energy grew at a CAGR of 3.7% (FY04-FY09), hydro energy at 4.6%, and nuclear

energy at 8.7% during the same period.

Future additions to power generation capacity are likely to be affected by a number of factors,

including signing of the Indo-US nuclear deal, which could lead to more generation capacity being set

up on nuclear fuels, the Ultra Mega Power Projects (UMPPs) and Merchant Power Plants (MPPs),

which would largely be based on coal, and the policy of basing 5% of generation capacity on RES.

Per capita power penetration in India, when compared to other developing countries like China and

Brazil is significantly low. The demand in 2017 would need to grow at a significant higher CAGR of ~17%, if India were to even achieve the per capita consumption, similar to the current levels in these

countries.


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Total Energy production and shortage

Energy

YearRequirement Availability Shortage

(MU) % Growth (MU) % Growth (MU) (%)

1991-92 2,88,974 2,66,432 22,542 7.8

8th Plan

1992-93 3,05,266 5.6 2,79,824 5.0 25,442 8.3

1993-94 3,23,252 5.9 2,99,494 7.0 23.758 7.3

1994-95 3,52.260 8.9 3.27,281 9.3 24,979 7.1

1995-96 3,89,721 10.6 3,54,045 8.2 35,676 9.2

1996-97 4,13,490 6.0 3,65,900 3.3 47,590 11.5

CAGR 7.43% 6.55%

9th Plan

1997-98 4,24,505 2.6 3,90,330 6.6 34,175 8.1

1998-99 4,46,584 5.2 4,20,235 7.6 26,349 5.9

1999-00 4,80,430 7.6 4,50,594 7.2 29,836 6.2

2000-01 5,07,216 5.7 4,67,400 3.7 39,816 7.8

2001-02 5,22,537 3.0 4,83,350 3.4 39,187 7.5

CAGR 4.79% 5.73%

10th Plan

2002-03 5,45,983 4.5 4,97,890 3.0 48,093 8.8

2003-04 5,59,264 2.4 5,19,398 4.3 39,866 7.1

2004-05 5,91,373 5.7 5,48,115 5.5 43,258 7.3

2005-06 6,31,554 6.8 5,78,819 5.6 52,735 8.4

2006-07 6,90,587 9.3 6,24,495 7.9 66,092 9.6

CAGR 5.74% 5.26%

11th Plan

2007-08 7,39,343 7.1 6,66,007 6.6 73,336 9.9

2008-09 7,77,039 5.1 691,038 3.8 86,001 11.1

2009-10 830,594 - 746,644 - 83,950 10.1

CAGR 3.96% 3.88%

CAGR = Compounded Annual Growth Rate


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Power Supply Position (Peak)

Peak

Demand Met Shortage

(MW) % Growth (MW) % Growth (MW) %

1991-92 48,055 3.9,027 9,028 18.8

8th Plan

1992-93 52,805 9.9 41,984 7.6 10,821 20.5

1993-94 54,875 3.9 44,830 6.8 10,045 18.3

1994-95 57,530 4.8 48,066 7.2 9,464 16.5

1995.-96 60,981 5.9 49,836 3.6 11,145 18.3

1996-97 63,853 4.7 52,376 5.0 11,477 18.0

CAGR 5.85% 6.06

9th Plan

1997-98 65,435 2.5 58.042 10.8 7,393 11.1

1998-99 67,905 3.8 58,445 0.7 9,460 13.9

1999-2000 72,669 7.0 63,691 3.6 8,978 12.4

2000-01 74.872 3.0 65,628 3.0 9.244 12.3

2001-02 78,441 4.7 69,1 89 5.4 9.252 11.8

CAGR 4.20% 5.73%

10th Plan

2002-03 81,492 3.9 71,547 3.4 9,945 12.2

2003-04 84,574 3.8 75,066 4.9 9,508 11.2

2004-05 87,906 3.9 77,652 3.4 10,254 11.7

2005-06 93,255 6.1 81,792 5.3 11,463 12.3

2006-07 100,715 8.0 86,818 6.1 13,897 13.8

CAGR 5.13% 4.64%

11th Plan

2007-08 108,866 8.1 90,793 4.6 18,073 16.6

2008-09 109,809 0.9 96,785 6.6 13,024 11.9

2009-10 119,166 8.5 104,009 7.4 15,157 12.7

CAGR

(2007-08 to 2008-09)

3.06% 4.63%

CAGR = Compounded Annual Growth Rate


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The peaking and energy shortage on all-India basis was 12.1% and 10.6 % respectively during the

period April 09 to March 10.

Rate of growth of generation in past

As can be seen rate of growth in generation has averaged around 5-6% in the past. As per estimates

it is expected that the growth in generation of electricity will continue to be around 6-7% in future

which leaves ample room for deficit in supply and will ensure that the demand for power exceeds

the supply.

In past the actual capacity addition has fallen drastically short of the plan. In keeping with the past

performance (last 2-3 years) it is expected that a likely capacity addition of about 50% in future will

take place.

Energy Deficit Situation

The energy shortage has increased from 7.5 % in 2001-02 to 11.1 % during 2008-09; the peaking

shortage has grown from 11.8 % in 2001-02 to 11.9 % in 2008-09 mainly due to increase in industrial

and commercial demand and shortage of coal and natural gas for power generation.

While, the energy shortage increased from about 8.8% in 2002-03 to about 10.1% during 2009-10,

there was increase in peaking shortage from 16.6% in 2007-08 to 12.7% in 2009-10. The peak

demand in 2007-08 was extra-ordinarily high at 16.6 %, such high deficit was faced during Eight Plan

when the shortages touched the figure of upto 20%.

The main reasons for shortage of power are-


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Growth in demand for power outstripping the growth in generation and capacity addition,

Shortage of peaking power in the grid.

Low Plant Load Factor of some of the thermal generating units, mostly in the State Sector

High Transmission & Distribution losses of about 28.44% as in 2008-09.

Inadequate sub-transmission and distribution network in some States.

Inadequate inter regional transmission capacity, for supplying power from surplus regions to

deficit regions. Poor financial position of State Utilities rendering it difficult for them to raise the resources

necessary for making required investments to create adequate generation, transmission and

distribution system.

Plant Load Factor

The Plant Load Factor (PLF) of a generating unit is the ratio of the actual energy generated during a

given period of time to the energy that could have been generated if the unit had operated

continuously at its maximum rated capacity during the period. The PLF which is expressed as a

percentage is an important indicator of the performance of the thermal power generating units. The

PLF has shown a steady improvement over the years as could be seen from the table below:-

Target Actual Sector-wise (Actual)

(%) (%) Central State Private

8th Plan

1992-93 57.2 57.1 62.7 54.1 58.8

1993-94 57.8 61.0 69.2 56.6 57.0

1994-95 62.0 60.0 69.2 55.0 65.9

1995-96 62.3 63.0 70.9 58.0 72.3

1996-97 63.6 64.4 71.0 60.3 71.2

9th Plan

1997-98 66.5 64.7 70.4 60.9 71.2

1998-99 65.7 64.6 71.1 60.7 68.0

1999-2000 63.8 67.3 73.6 63.7 68.9

2000-01 66.7 69.0 74.3 65.6 73.0

2001-02 69.9 69,9 74.3 67.0 74.7

10th Plan

2002-03 70.8 72.1 77.1 68.7 78.9

2003-04 72.0 72.7 78.7 68.4 80.4

2004-05 73.4 74.8 81.7 69.6 85.2

2005-06 74.7 73.6 82.1 67.0 85.4

2006-07 76.3 76.8 84.8 70.6 86.3

11th Plan

2007-08 81.12 83.13 90.61 76.85 95.03

2008-09 79.17 77.19 84.30 71.17 91.01

2009-10 78.68 81.41 85.48 70.89 82.38


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Generation Targets & AchievementsGeneration Target for 2009-10 was set as 789.51 BU by the CEA as against the achievement of

771.17 BU during the year. The electricity generation in the country programme vis-a-vis actual

achievement and growth in electricity generation since 8th Plan are as under:-

Plan/Year Target(BU)

Growth inTarget (%)

Achievement(BU)

Achievement vis-a-vis Target (%)

Growth inAchievement (%)

8th Plan

1992-93 302.70 301.10 99.5 5.0

1993-94 316.70 4.6 323.50 102.2 7.4

1994-95 352.00 11.1 351.03 99.7 8.5

1995-96 377.15 7.1 380.09 100.8 8.3

1996-97 400.00 6.1 394.50 98.6 3.8

9th Plan

1997-98 429.00 7.3 420.62 98.0 6.61998-99 450.00 4.9 448.37 99.6 6.6

1999-2000

469.00 4.2 480.68 102.3 7.1

2000-01 500.70 6.8 499.45 99.8 3.9

2001-02 539.50 7.7 515.27 95.5 3.1

10th Plan

2002-03 545.55 1.1 531.43 97.4 3.1

2003-04 572.90 5.0 558.34 97.5 5.02004-05 586.41 2.4 587.37 100.2 5.2

2005-06 621.50 6.0 617.382 99.3 5.1

2006-07 663 6.7 662.523 99.9 7.3

11th Plan

2007-08 710 7.1 704.45 99.2 6.3

2008-09 774.34 9.0 723.55 93.44 2.7

2009-10 789.95 2.0 771.17 97.67 6.58


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Capacity Addition Programme in Tenthand EleventhPlans10th Plan

A capacity addition of 41,110 MW has been set for the 10th

Plan. Out of this the share of Central

Sector is 22832 MW and that of the Private Sector is 7121 MW. The State Sector has a share of

11157 MW. The 10th

Plan target details are summarized in the Table presented below:-

Capacity Addition during 10th Plan (as per planning Commission Target)

(In MW)

Sector Hydro Thermal Nuclear Wind Total

Coal Gas Diesel Total

STATE 4481.2 5660.0 921.7 93.9 6675.6 0.0 0.0 11156.8

PRIVATE 1170.0 2103.0 3220.0 628.0 5951.0 0.0 0.0 7121.0

CENTRAL 8742.0 12290.0 500.0 0.0 12790.0 1300.0 0.0 22832.0

Total 14393.2 20053.0 4641.7 721.9 25416.6 1300.0 0.0 41109.8

However, once again the actual capacity addition in the power sector had been far below the target

set by the Ministry of Power. Capacity addition during this plan period was only 21180.2 MW an

achievement of paltry 51.6% of the target.


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Sector Hydro Thermal Nuclear Total % achievement

Central 4495 7330 1180 13005 56.9

State 2691 3553.6 0 6244.6 55.9

Private 700 1230.6 0 1930.6 27.1

Total 7886 12114.2 1180 21180.2 51.6% Achievement 54.8 47.6 90.8 51.6

Though shortfalls in all the 3 segments i.e. Central, State and Private Sector has been

reported, the shortfall in achieving the Private sector targets of capacity addition are

notable.

In terms of inter fuel mix comparison; nuclear sector was able to achieve 90.8% of the

modest target set for it.

In Hydro segment 54.8% of the target was achieved and X Plan is notable in the context of

clearing the backlog. There were number of hydro projects which were originally due for

commissioning in the Eight Plan or even before. But these projects due to associated

problems were brought into the Tenth Plan with a long history of time and cost overrun.

These projects included Naptha Jhakhri HEP (1500 MW), Tehri HEP (1000 MW), Dulhasti HEP

(390 MW) and Sardar Sarovar (1450 MW). In the Tenth Plan we have the satisfaction of

bringing these projects on track and all of them have been commissioned in the X Plan.

The dismal performance of Thermal segment at 47.6% of the target is mainly due to most of

the coal based backup projects could not fructify due to supply constraint on part of

equipment manufacturers especially BHEL.

11th Plan

Capacity Augmentation of 78 GW has been planned in the generation sector in 11th 5 yr. Plan.

Electricity Generation Programme and Achievement during 2009-10

Actual generation during 2009-10 vis-a-vis target and the actual generation during corresponding

period of last year are as under:


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TypeProgramme

(BU)

Actual

(BU)

% of

Programme

Actual same

period(2008-09)

Electricity

Generation as

% of Last Year

Thermal 648.47 640.52 98.77 589.91 108.57

Nuclear 19.00 18.65 98.18 14.71 126.78

Hydro 115.46 106.65 92.37 113.02 94.36

Bhutan

Import6.56 5.34 81.37 5.89 90.66

Total 789.51 771.17 97.68 658.51 106.41

Generation Capacity Under execution for likely benefits during 11th Plan:

Year Commissioned

2007-08 9263

2008-09 3454

2009-10 9585

2010-11 3368*

Total 25670

* (upto July 31, 2010)

Present Sectoral PerformanceIndia has installed power generation capacity of 163669.80 MW as on July 31, 2010, which is about

120 times the installed capacity in 1947 (1362 MW). Electricity generation growth has been steadilyimproving year after year, and during April 2009 - March 2010, the total electricity generation was

about 771.551 billion units of energy. The Region-wise and Category-wise break-up of installed

capacity is given below:

Composition of Installed Capacity: source wise (as on 31.03.2010)


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Anticipated Power Supply Position in the Country during 2010-11 (state wise data)

There would be surplus energy in states of Northern Region having predominantly hydro systems

during the monsoon months while shortage conditions would prevail during winter season.

ACTUAL POWER SUPPLY POSITION DURING 2009-10All India

During the year 2009-10, though the total ex-bus energy availability increased by

8.0% over the previous year and the peak met increased by 7.5%, the shortage conditions prevailed

in the Country both in terms of energy and peaking availability as given below:

The energy requirement registered a growth of 6.9% during the year against the projected growth of8.2% and Peak demand registered a growth of 8.5% against the projected growth of 8.2%.


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Region wise Energy requirement and deficit

All the Regions in the Country namely Northern, Western, Southern, Eastern and North-Eastern

Regions continued to experience energy as well as peak power shortage of varying magnitude on an

overall basis, although there were short-term surpluses depending on the season or time of day. The

surplus power was sold to deficit states or consumers either through bilateral contracts, Power

Exchanges or traders. The energy shortage varied from 4.4% in the Eastern Region to 13.7% in the

Western Region.

State-Wise total Energy requirement and deficit


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State Wise Peak Energy requirement and deficit

It may be seen that in the Northern Region Delhi faced negligible energy shortage. Rajasthan,

Himachal Pradesh, Chandigarh, Haryana and Uttarakhand experienced energy shortages in the range

of 2-7% whereas the shortages in Punjab and Uttar

Pradesh were in the range of 13-22%. The maximum energy shortage in Northern

Region was in Jammu & Kashmir and was 24.8%.

In the Western Region, Goa, Dadra & Nagar Haveli and Chhattisgarh faced energy shortage in the

range of 2-4%. Gujarat and Daman & Diu faced energy shortages in the range of 47% and

Maharashtra faced energy shortage of 18.7% whereas the maximum energy shortage in Western

Region was in Madhya Pradesh and was 19.0%.

In the Southern Region, Kerala, Tamil Nadu, Andhra Pradesh and Pondicherry faced energy shortages

in the range of 2-7%. The maximum energy shortage in Southern Region was in Karnataka and was

7.7%.


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In Eastern Region, Orissa faced negligible energy shortage. DVC, Jharkhand, West

Bengal and Sikkim faced energy shortages in the range of 2-12%. The maximum shortage of 14.4%

was faced by Bihar.

In the North-Eastern Region, Assam, Tripura and Nagaland faced energy shortages in the range of 8-

13%. The energy shortages witnessed in Meghalaya, Manipur,

Mizoram and Arunachal Pradesh were in the range of 14-18.2%. The maximum energy shortage in

North-Eastern Region was in Arunachal Pradesh at 18.5%. The shortages witnessed were partly onaccount of constraints in transmission, sub-transmission & distribution system and/ or financial

constraints.

It may be seen that the hydro rich States having run of river schemes on the Himalayan rivers viz.

Himachal Pradesh, Jammu & Kashmir, and Uttarakhand are surplus in energy during monsoon

period, while they would face severe shortage conditions during the winter low inflow months when

the generation from hydro schemes dwindles to the minimum. The constituent system/ states of

Sikkim, Delhi, Himachal Pradesh, Jharkhand and DVC shall have both peaking and energy surplus on

annual basis.The State of West Bengal would have surplus in terms of energy whereas Orissa will be in

comfortable position in terms of peak on annual basis. All other States in the country would have

shortages both in term of energy and peaking availability.


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Energy requirements (total and peak): month wise dataDemand vs. Availability

All India

Northern Region


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Western Region

Southern Region


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Eastern Region

North Eastern Region


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Pattern of Peak Demand & Energy Requirement

All India

Northern Region


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Western Region

Southern Region


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Eastern Region

North-East Region


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Power Consumption Pattern in India (Sector Wise)

Growth of Energy Consumption in different sectors of the Economy

The percentage of power consumption in Agriculture, Industrial and Domestic Sector duringthe years 2003-04, 2004-05 and 2005-06 are as under:

Sector 2003-04 2004-05 2005-06

(%) (%) (%)

Domestic 24.86 24.77 24.30

Industrial 34.51 35.63 35.87

Agriculture 24.13 22.93 21.86


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Demand Analysis

Characteristics of Demand

Demand for Electricity Traces Trend in GDP Growth

Overall economic growth determines the extent of electricity demanded because of the all-pervasive

use of electricity. Generally, the demand for electricity traces the GDP growth trend; for instance,

economic growth and the associated increase in economic activities, particularly in industries like

cement, steel, mining, food processing and many other manufacturing industries, increases the

demand for electricity.

Growth in GDP and Electricity Sales (in %)Source: CMIE

Variation in Demand

Power requirement varies among consumers in terms of voltage and phases; for instance, in

industries, electricity is required in three different types: three-phase small-scale 400V; three-

phase large-scale 11 KV, and three-phase very large-scale 33 KV. Domestic consumers, on

the other hand, require 230 V single-phase or 400 V three-phase to use it forlighting, air-

conditioning, water heating, cooking, etc. Agricultural consumers use 230 V single-phase and

400 V threephase for running tube wells and pump sets. Commercial consumers use 230 V

single-phase and 400 V three-phase for using equipment and appliances. The Railways get

supply through 11 KV and 33 KV whereas public services, which include public lighting and

public water, get supply at different voltages, including 230 V.

Seasonality in Demand

Demand for electricity also varies according to seasons. Demand from the domestic sector

generally peaks during summer and subsides during monsoon. Indias seasonality in demand

can be captured in power-deficit numbers as it is a powerdeficit country. Generally, the

power deficit in India ranges between 6-8% during monsoon (July to September), and climbs

up to around 10-14% during winter and summer. During monsoon, the demand for power

from the agriculture and domestic/residential sector is lower, while during the summer andwinter, demand from the domestic/residential sector is higher as power demand is higher for

cooling and heating purposes.


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Average Power deficit (in %)

Source CMIE

Consumption Pattern/Consumer Profile

Electricity is consumed by almost every sector in its day-to-day functioning but on the basis of end-

use, consumers of electricity can be categorised into the following seven categories:

Industrial

Domestic

Agricultural

Commercial

Public services

Railways

Others

Industrial consumers are the largest consumers of electricity in India. In FY09, industrial consumers

accounted for 38% of the total electricity sold by utilities; however, their share in actual

consumption was much higher as many industries met their power requirement through captive

generation. Domestic and agriculture sectors are the other major consumers who have respective

shares of 24% and 22% in total power consumption. While the public services account for 4% of

sales, the Railways and other consumers account for a share of 2% each in overall sales.


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Consumer Profile FY09 (in %)

Source CMIE

Over the years there has been a significant shift in the sector-wise consumption patterns, as there

has been a decrease in the share of agriculture and industrial sectors and an increase in the share of

the domestic and commercial sectors. In FY90, the industrial consumers accounted for 46.0% of total

sales by utilities, while the domestic and agriculture sectors accounted for 16.9% and 25.1%,

respectively. The industrial segments share in overall consumption has come down due to improved

consumption norms after adoption of energy-efficient technologies, and also due to the industrial

sectors use of captive power. The domestic segment has overtaken the agriculture sector and has

emerged as the second-largest consumer segment of power largely due to increased urbanisation,

rise in disposable incomes, and the consequent increase in use of domestic electrical appliances.

Consumption of power by commercial establishments has increased with the rise in the servicesector in India.

Demand Drivers for Electricity

The driving forces for demand of power are all those factors that influence the demand profile over

the course of the year and over the course of the day or week. As almost all industries use electricity

in their day-to-day functioning, the overall economic growth is a key determinant of electricity

demand. Demand for electricity generally traces the trend in GDP growth. The growth in GDP helps

to track the growth in economic activity due to increased industrial activity, income from services

sector and increased consumption by the household segment and the agriculture sector.

The major factors that drive the Demand for Electricity are as follows:

Latent DemandThe power outages/scheduled power cuts and inconsistent quality of power have restrained

power consumption and have left consumers without electricity for several hours in a day.

The situation is worse in the rural areas. Consumers in the domestic sector and to a certain

extent, the commercial sector, also face power shortages. The industrial sector meets a large

share of its requirement for power through captive power generation. Thus, there is huge

latent potential demand for power that lies untapped.

Manufacturing Sector Growth

The demand for electricity will remain higher in the future with the rise in growth of themanufacturing sector. The sector has been dependent on captive power consumption to a

major extent. In 2008, the cost of captive power consumption went up with the surge in


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crude oil prices; however, as oil prices have come down fromthese peak levels, the cost ofcaptive power consumption is expected to recede too but the demand for power will

continue to rise.

Domestic SectorThe overall economic growth, higher disposable incomes will continue to drive demand for

electricity in the domestic sector both rural and urban. Likewise, the rural electrification

programme will increase demand for power in the rural areas, which will be used for bothresidential consumption and for agriculture-related usage.

Prices of Household AppliancesPrices of household appliances are also one of the drivers of electricity demand because the

decrease in the prices of appliances leads to an increase in the usage of appliances, which

finally increases the demand for electricity.

Demand and Supply Scenario

Power shortage continues to be a major cause for concern. The overall energy deficit was 11.0% in

FY09, while the peak-hour power deficit touched 12.0% during FY09. During FY07 to FY09, the

energy requirement increased from 693.1 BU to 774.3 BU while the energy availability increasedfrom 624.7 BU to 689.0 BU. As a result, energy deficit increased from 68.3 BU kWh to 85.3 BU during

the period under review. The deficit is largely due to T&D losses, poor transmission, and distribution

infrastructure, unaccountability in metering and billing, cross subsidies, etc.

The peak demand for electricity increased from 100.7 GW in FY07 to 109.8 GW in FY09 while the

peak demand met increased from 87.1 GW in FY07 to 96.7 GW in FY09. The peak shortage was

mainly due to unavailability of plants and load shedding during peak hours.

Region-wise Power Demand and Supply Position

Northern Region

The Northern region has an energy deficit of around 24.3 BU and a peak deficit of around 3.5 GW.

The situation varies throughout the year and the worst situation is seen in the summer. Uttar

Pradesh is the largest deficit state in the Northern region, and a large part of this deficit can be

attributed to the lack of political will and the demographic profile of the consumers. Uttar Pradesh

has the highest AT&C losses among all states of the Northern region, which explains the financial

sickness of the state electricity boards. A similar situation exists in Punjab and many other states of

the region but the intensity in these states is a tad lower whereas in J&K the turmoil has made the

situation more critical. Delhi, Rajasthan, and Haryana have largely benefited from the reform process

of their respective state governments; as a result, these states losses have also come down, and the

power deficit has decreased over the years. The region has states like Himachal Pradesh and

Uttarakhand, which have enormous hydro potential, and can be tapped to meet the regions

demand for power.


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Northern Region energy and peak deficit (FY 09)

Source CEA

Western region

The Western region faces the worst shortage in both percentage terms as well as in units. The state

with the highest demand in the region is Maharashtra, which houses the financial capital of the

country and is home to a large number of industrial units. The region also witnesses high demand

from the agricultural sector. The demographic mix of consumers in the state makes the financial

viability of the power sector difficult. Different problems plague other states like Gujarat and

Madhya Pradesh; Gujarat has a lack of generating capacity and Madhya Pradesh faces AT&C losses

as high as 50%. However, there is a potential for change, and therefore, investment in Madhya

Pradesh state, though availability of fuel remains a problem. Maharashtra is getting an UMPP at a

coastal location so that it has easy access to imported coal. Rural electrification in Madhya Pradesh

and huge capacity expansion and addition plans in Gujarat also make it an attractive investment

opportunity.

Western Region energy and peak deficit (FY 09)

Source CEA


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Eastern region

In the Eastern region, the growth of installed capacity has been around 1.5% in the past 5 years;

however, industrial development and consumer demand have been gradually increasing in the

region. The region imports power from Bhutan to meet its power requirement. There are many

projects proposed in the area, which are expected to increase the demand for power. The capacity

expansion plans by various industries in the sector as well as regular growth in demand translatesinto a healthy potential for investment. However, there are concerns that need to be addressed at

first, the least of which are monetary in nature. Besides, the area has had problems in acquiring

environmental clearances for its ambitious capacity expansion plans as well.

Eastern Region energy and peak deficit (FY 09)

Source CEA

North-Eastern region

The North-Eastern region has huge potential in terms of fuel availability (coal for thermal and water

systems for hydro power), as well as potential demand, as the region has the lowest per capita

power consumption. The major reasons for this are the terrain and climatic conditions that are not

suitable for power projects. The region also has abundant supply of gas that is as good as fuel for

thermal power generation as is coal, and is cleaner too. In terms of potential, the region is very

attractive. It has proven reserves of fuel, it has potential for growth in demand from residential and

small users; however, the demand and potential need to be assessed by keeping the geographical

constraints in mind.

North-Eastern Region energy and peak deficit (FY 09)

Source CEA


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Southern region

In the past many reforms have been undertaken in this region, such as the implementation of SERCs

(State Electricity Regulatory Commissions) and the rationalisation of tariff structures, which have

made capacity addition an easier task. The results of these reforms are visible from the peak load

deficit (that has come down) as well as the requirement and availability in the region. However, the

demand in the Southern region has been increasing as both Karnataka and Andhra are adding hugecapacities. Tamil Nadu too has signed MOUs with the Indian government for various projects to

increase the transmission and distribution capacities. The demand from both industrial units as well

as residential consumers is driving the capacity addition potential in this region. Moreover, the real

estate expansion plans in the region will not only require an increase in the generation capacity but

also in the capacity to provide continuous supply of power at a reasonable voltage, which makes the

opportunity to invest in the region more attractive.

Northern Region energy and peak deficit (FY 09)

Source CEA

Outlook for FY 2010-11

Demand from the rural sector is expected to rise; following waiver of farm loans, modest agricultural

income in FY11 on account of a good monsoon and access to electricity for more villages under the

governments rural electrification programmes. With the Growth in the industrial sector picking up

in second half of FY11 industrial activity will also see an improvement resulting in higher demand for

power from the sector. The service sector, on the other hand, is expected to see healthy growth,

which will keep the demand for power robust. Railways, public services are expected to report

higher demand for power, while in the commercial sector, entertainment complexes and the

hospitality sector are likely to report marginal decline in demand for power.


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FutureAs per the CEA estimates, power demand in India will grow at ~ 7.5% CAGR during 2009-17, to

increase from ~775 BU currently to ~1400 BU by 2017

Demand Forecast [17th EPS]

The demand projections on all India bases for the year 2011-12, 2016-17 and 2021-22 are givenbelow:

YearElectrical Energy Requirement at PowerStation Bus Bars (MU)

Annual Peak Electric Load at PowerStation Bus Bars (MW)

2011-12 968659 1,52,746

2016-17 1392066 2,18,209

2021-22 1914508 2,98,253

At base case demand scenario, Indias per capita consumption would be ~ 1100 kwh in 2017, muchlower than even the current consumption level of developing economies like China (2150 kwh),

clearly indicating a latent/unmet demand, which can be tapped by the industry.


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There are two scenarios regarding the energy demand in India in the times to come.

Scenario 1:

Base Case- If the demand continues to grow at the rate that it is growing deficit of electricity is

expected to be hugely compensated by the power projects in the pipeline, leaving deficit to the

tune of 1-2%.

Scenario 2:

Optimistic Scenario- As electricity becomes more and more consistent and power outages become

rare people will find more and more uses of electricity. e.g. - In areas where power outages are

common people tend to avoid purchase of consumer durables such as washing machines,

refrigerators etc. due to unreliability of electricity which clearly makes for a case of latent demand

which will be unleashed once power outages become a thing of the past, quality of electricity

improves and the electrification penetration reaches developed countries level.

There have been a lot of announcements for starting of power projects amounting to a total ofa 100 GW. Many analysts have been predicting a capacity addition to the tune of 80-85 GW.Despite this scenario of optimism in the market keeping in mind previous targets and

achievements (78 GW of capacity was to be added in 11

th

plan of which only 20 GW hasbecome operational in 2years,) such a huge capacity addition remains an unlikely possibility.Even after taking into account major improvements in project execution ability in the country alikely scenario of capacity addition of 60-65 GW emerges.


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Power Trading

Historical Trading on power exchanges

Volume of Electricity Transacted through Traders and Power Exchanges

Year Electricity

Transacted

through Traders

Electricity Transacted

through Power Exchanges

Volume of Traders and Power

Exchanges

Total

Electricity

Generation

(Billion

Units)

Volume of

Traders and

Power Exchanges

to Total

Electricity

Generation

Volume

(Billion

Units)

Annual

Increase

(%)

Volume

(Billion

Units)

Annual

Increase

(%)

Volume

(Billion

Units)

Annual

Increase

(%)

2004-05 11.85 - - 11.85 - 548.12 2%

2005-06 14.19 20% - 14.19 20% 578.82 2%

2006-07 15.02 6% - 15.02 6% 624.50 2%

2007-08 20.96 40% - 20.96 40% 666.01 3%

2008-09 21.92 5% 2.77 24.69 18% 691.04 4%

2009-10 26.82 22% 7.09 156% 33.91 37% 764.03 4%

2009-10

(Apr-Sep)

13.39 2.79 16.18 380.28 4%

2010-11

(Apr-Sep)

16.13 20% 5.89 111% 22.02 36% 396.89 6%

Of the total power generated in the country power trading accounts for about 3.0-4.0% of the totalgeneration (excluding generation based on renewable and captive power plants). The volume of

electricity transacted through inter-state trading licensees and power exchanges has been increased

0

100000

200000

300000

400000

500000

600000

700000

800000

2002-03 2003-04 2004-05 2005-06 2006-07 2007-08

Traded Power(MUs)

Total Generation(MUs)


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from 20.18 BUs in 2007 to 30.60 BUs in 2009. The share of electricity transacted through trading

licensees and power exchanges in volume terms as a percentage of total electricity generation too

increased from 2.93% to 4.08% during the period.

Trading market expected to increase multi-fold

Trading market or transactions through traders and exchanges is expected to increase by 3-4 times

in the next 5-6 years. New products (including structured derivatives) are expected to be introduced

in the exchange, which will increase the potential options for generators. Even as the courts debate

whether to allow power futures trading in the country introduction of power derivatives on

exchanges seems inevitable.

As the current persisting deficit in power supply begins to decrease merchant power prices will

continue their downward spiral as they have done in the past. It is expected that the long term PPA

prices will continue to be at current levels (or even decline) in nominal terms over the next few

years. The average trading prices are expected to peak over next two years and thereafter decline by

40-50%.


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Conclusion

Demand Side

i. Per capita power penetration in India, when compared to other developing countrieslike China and Brazil is significantly low. The demand in 2017 would need to grow at a

significant higher CAGR of ~ 17%, if India were to even achieve the per capitaconsumption, similar to the current levels in these countries.

ii. At base case demand scenario, Indias per capita consumption would be ~ 1100 kwh in

2017, much lower than even the current consumption level of developing economies

like China (2150 kwh), clearly indicating a latent/unmet demand, which can be tapped

by the industry.

iii. As per the CEA estimates, power demand in India will grow at ~ 7.5% CAGR during 2009-

17, to increase from ~775 BU currently to ~1400 BU by 2017

iv. Constrained fuel supplies present a major threat to sector Growth: India, in spite ofsubstantial reserves, is expected to confront a supply deficit of ~25% (250 MTPA) of

domestic coal by 2014. Similarly, India will require 2000-2,500 tpa of Uranium to meet

its nuclear energy aspirations by 2020, against a current supply/mining capacity of ~300

tpa.

Supply Side

i. At least 80-85 GW of new capacity (90% of them thermal units targeting high PLF of 80-

95%) will be commissioned by 2014. This will reduce the base load deficit, in the current

scenario, to a low of 1-2%.

ii. Private sector will account for over 25% of the installed capacity over next 5-6 years.

Over forty to fifty players, many of whom with interests in smaller capacities and/or in

1-2 projects are expected to emerge in the industry resulting pricing pressures &

fragmented industry due to the high competition.

iii. The supply deficit, for the base load could potentially reduce to 1-2% over the next 5-6

years in the base case. Even in an optimistic scenario (increased realization of latent

demand); the deficit could be around 4%-5%

.

iv. New fuel opportunities are expected to emerge in the generation space, in addition to

coal. Improved domestic gas supply & strengthening of commensurate pipeline

infrastructure will facilitate increased gas based generation. Governments thrust on

Hydro projects (50,000 MW initiatives) will provide attractive opportunities, especially

for peaking power. Nuclear energy will also witness strong growth at the back of Indo-US

agreement (target 20 GW by 2020).

v. Most of the new thermal plants (accounting for ~90% of incremental capacity addition)

are basing their production at high PLF (80-90%). Accordingly, the average PLF of the

generation capacity will increase from ~56% currently to ~61-63% by 2014-15. Similarly,

the adoption of higher voltage lines & strengthening of the grids will help reduce the

T&D losses in the system. All these will improve the power supply position to customers.


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vi. The peak deficit will however continue to exist in the future. Peaking stations (hydro,

gas, solar, etc) would therefore have a large role in addressing this deficit. Hence

renewable will strengthen its role in the sector.

vii. As regards distribution losses, most of the power at the end user level is purchased and

distributed by SEBs. The inability of SEBs to keep up with the pace of liberalisation of

other power sector utilities will ultimately hurt the sector. It may come to be thatdespite a lot of capacity addition SEBs would not be able to distribute that power

because of lack of a adequate capacity addition at their level, forcing the generating

units to operate at less than their capacity levels.

viii. As regards distribution losses, most of the power at the end user level is purchased and

distributed by SEBs. The inability of SEBs to keep up with the pace of liberalisation of

other power sector utilities will ultimately hurt the sector in the last mile. It may come to

be that despite a lot of capacity addition SEBs would not be able to distribute that

power because of lack of adequate capacity addition at their level, forcing the

generating units to operate at less than their capacity levels. With HDTV and 800v

transmission lines installation AT&C losses are set to come down (expected to be 25% by

FY14E) but as discussed earlier full impact of such improvement will not be visible unless

SEBs are modernised.

The above factors point to an increased supply rate, which in turn will produce pressure on

merchant prices to correct and go down.

Most of the small players will look to exit their projects through either IPO or PE deals. Since IPOs

in the sector have not been very successful in past and given the grim outlook of power projects in

the market, most of them will look to PE investment in their project as a viable option to exit or

divest.

Price

i. Average merchant power prices expected to decline The short term prices are expected

to peak over the next 1-2 years and then decline steadily (in response to the market

supply situation). The generators accordingly need to evaluate the profitability of their

plans focused on merchant power, and also define sales portfolio that balances long

term sales and short term trading.

ii. It is widely expected that pricing pressures in the generation space, with long term

prices at-best maintaining their current levels in nominal terms. The average short

term/merchant prices may decline by 40-50% by 2014-15.

iii. Large capacity additions lined up by private and public sector players are expected to

reduce the power deficit, lowering Merchant power tariffs in turn. The recent

competitive bidding for supply of power at Rs2.7-3.2/unit can form the base for

merchant tariffs.

A clear implication of the above will be on price realizations. Unless the latent demand condition is

going to evolve in future the huge increase in supply is inadvertently going to affect the merchant

power prices. What this translates into is that, though the price of Rs. 4-5 per unit is expected to be

maintained at nominal rates the exorbitant rates of Rs. 16-17 are going to become a thing of the

past.


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In light of these market trends, generators would need to develop suitable sales strategies

i. Balance the portfolio between long term and short term allocations (depending on the

size and commissioning timelines): Long term PPAs will continue to be the dominant

sales option for generators, with secured market but controlled returns. Merchant

power provide upsides but present high variability

ii. Define a customer mix plan: Evaluate various customer options viz. SEBs, traders andbulk buyers (based on quantum of purchase, financial stability, cost of delivery etc) anddefine a plan accordingly.

iii. Explore alternative market facing models: Evaluate opportunities for alternative modelslike peaking power capacity, power tolling, distributed generation & supplies as part of

the overall strategy

power sector scenario

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