Study On Indian Power Sector - Opportunities And Trend

A Study on Indian Power Sector

JASPAL SINGH SACHIN RANGRAO DESHMUKH CHANDRA MOHAN VERMA ANINDYA KUNDU PRAKASH POLLY MAZHUVANCHERRY

ROLL-47 ROLL-06 ROLL-56 ROLL -22 ROLL-26

Table of Contents EXECUTIVE SUMMARY......................................................................................................................... 5 INTRODUCTION ...................................................................................................................................... 7 GENERATION .......................................................................................................................................... 8 Capacity ................................................................................................................................................. 8 Power Generation ................................................................................................................................ 11 Emerging technologies.......................................................................................................................... 11 Coal-based ........................................................................................................................................ 11 Fluidized bed combustion ................................................................................................................. 11 Nuclear Power .................................................................................................................................. 12 Distributed generation ...................................................................................................................... 13 Resources ............................................................................................................................................. 15 Coal .................................................................................................................................................. 15 Natural Gas ....................................................................................................................................... 16 DEMAND - SUPPLY .............................................................................................................................. 17 Sectoral demand ................................................................................................................................... 17 ELECTRICITY DEMAND FORECAST .................................................................................................. 19 Elasticity of electricity consumption with respect to GDP growth.......................................................... 20 TRANSMISSION .................................................................................................................................... 22 Review ................................................................................................................................................. 22 Overview and Structure ........................................................................................................................ 23 National grid......................................................................................................................................... 25 Grid discipline ...................................................................................................................................... 27 Private investments in transmission ....................................................................................................... 28 Technology in transmission .................................................................................................................. 29 HVDC transmission .......................................................................................................................... 29 Transmission cost structure ................................................................................................................... 30 DISTRIBUTION ...................................................................................................................................... 31 Tariffs and financial performance of SEBs ............................................................................................ 32 T&D losses ........................................................................................................................................... 32 Measures to reduce losses ..................................................................................................................... 34 Technical losses ................................................................................................................................ 34

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Commercial losses ............................................................................................................................ 34 Privatization ..................................................................................................................................... 34 Distribution reforms.............................................................................................................................. 35 New R-APDRP .................................................................................................................................... 36 REFORMS IN THE POWER SECTOR.................................................................................................... 36 Pre Reform Stage.................................................................................................................................. 36 Electricity Act 2003 .............................................................................................................................. 40 Generation ............................................................................................................................................ 41 Rural Electrification/Generation/Distribution ........................................................................................ 41 Licensing .............................................................................................................................................. 42 Trading and Captive Generation ........................................................................................................... 42 Open Access ......................................................................................................................................... 43 Distribution .......................................................................................................................................... 43 Transmission ........................................................................................................................................ 44 Tariff .................................................................................................................................................... 44 Regulatory Commission........................................................................................................................ 45 Policy Issues ......................................................................................................................................... 45 Mega Power Policy ............................................................................................................................... 45 Ultra Mega Power Projects ................................................................................................................... 46 Consumer Interests ............................................................................................................................... 46 Enforcements........................................................................................................................................ 47 Dispute Resolution ............................................................................................................................... 47 Electricity (Amendment) Act, 2007....................................................................................................... 47 Demand Side Management ................................................................................................................... 48 Environmental Reform in the Electricity Sector: ................................................................................... 49 STUDY OF SELECTED COMPANIES ................................................................................................... 51 1. NTPC Ltd. ........................................................................................................................................ 51 2. RELIANCE INFRASTRUCTURE LTD ........................................................................................... 52 3. TATA POWER COMPANY LTD .................................................................................................... 53 4. POWER GRID CORPORATION OF INDIA LTD ........................................................................... 53 5. JP HYDROPOWER ......................................................................................................................... 53 MAJOR FINDINGS: ................................................................................................................................ 54

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IMPACT OF CERC REGULATIONS ON CENTRAL PLAYERS ........................................................... 55 Generation ........................................................................................................................................... 55 Transmission ........................................................................................................................................ 58 IMPACT OF CERC REGULATIONS ON TARIFF AND END CUSTOMERS .......................................................... 59 ADVANCED METERING INFRASTRUCTURE................................................................................................. 60 RENEWABLE ENERGY......................................................................................................................... 69 Renewable Energy Scenario in India ..................................................................................................... 69 Co-Generation ...................................................................................................................................... 70 Wind Power .......................................................................................................................................... 71 Solar power .......................................................................................................................................... 71 SPV Systems ........................................................................................................................................ 72 Small hydroelectric plants ..................................................................................................................... 72 Biomass Power ..................................................................................................................................... 72 Potential ........................................................................................................................................... 72 Different Technologies Used ................................................................................................................ 73 Gasification ...................................................................................................................................... 73 Geothermal Power ............................................................................................................................ 73 NUCLEAR POWER IN INDIA ....................................................................................................................... 75 REFERENCES......................................................................................................................................... 80

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EXECUTIVE SUMMARY Availability of power is one of the important ingredients for industrial growth. It is an important infrastructure facility without which no industrial activity can be thought of in modern times. Increasing automation of Indian industries has created huge demand of power in India. This huge demand has resulted into demand supply gap in India in recent times.

This report is based on the extensive study of the power sector in India. Both global and domestic perspectives of power sector focusing more on Indian players have been looked upon in this report. It includes the literature review by scholars which has analyzed the subject of power sector more extensively. The objective of this report is to get a comprehensive and apparent knowledge of the power sector, and to study the changes in power sector over a period of time there by analyzing various aspects of the power sector. In the report the power generation companies of the industry chosen, are the top five and bottom five companies of the power sector in India, based on the sales turnover. The trends in the demand, supply and generation in the power sector is discussed through the trend analysis. Before 2001, India‘s electricity-supply was mainly owned and operated by public sector. It was running under the risk of bankruptcy. This created a serious impediment to investments in the sector at the time when India desperately needed them. This led to the emergence of Private players in the power sector. The NTPC, Reliance Infra, Tata Power, Power Grid, & Torrent Power are the market leaders in the power sector and have high Cumulative Annual Growth Rate (CAGR). This is because of the government support, inflow of foreign investment, growing demand and use of latest technology for power generation and transmission. The best management policies are adopted by these companies. The small players GVK power, Indowind Energy, Energy Development, JP Hydro, and KSK energy are also imparting new technology, and management policies to survive the competition and meet the demand of power sector. The methodology used in report includes comparative analysis of the top 5 and bottom 5 companies of the sector. The Potter‘s five forces analysis, SWOT analysis, Trend analysis & Ratio

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analysis are used to analyze the industry of power sector. The various analysis shows that there has been a continuous growth in generation and consumption of power in India. Thermal, hydro and nuclear are three major source of power generation From the installed capacity of only 1,362mw in 1947, has increased to 97000 MW as on March 2000 which has since crossed 100,000 MW mark India has become sixth largest producer and consumer of electricity in the world equaling the capacities of UK and France combined. The number of consumers connected to the Indian power grid exceeds is 75 million. Rural electrification is one significant initiative of the industry to trigger economic development and generate employment by providing electricity as an input for productive uses in agriculture and rural industries, and improve the quality of life of the rural people. The International Energy Outlook 2006 (IEO2006) projects strong growth for worldwide energy demand over the 27-year projection period from 2003 to 2030. Much of the growth in energy demand is among the developing countries in Asia, which includes China and India; demand in the region nearly triples over the projection period. Total primary energy consumption in the developing countries grows at an average annual rate of 3.0 percent between 2003 and 2030. In contrast, for the developed countries—with its more mature energy-consuming nations—energy use grows at a much slower average rate of 1.0 percent per year over the same period. This huge increase in projected demand of energy in India and China makes analysis of energy sector of these countries very important.

World electricity generation rose at an average annual rate of 3.7% from 1971 to 2004, greater than the 2.1% growth in total primary energy supply. Total world consumption of marketed energy is projected to increase by 50 percent from 2005 to 2030.

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INTRODUCTION An economy‘s growth, development, ability to handle global competition is all dependent on the availability, reliability and quality of the power sector. As the Indian economy continues to surge ahead, electrification and electricity services have been expanding concurrently to support the growth rate. The demand for power is growing exponentially and the scope of growth of this sector is immense. Existing generation suffers from several recurrent problems. The efficiency and the availability of the coal power plants are low by international standards. A majority of the plants use low-heatcontent and high-ash unwashed coal. This leads to a high number of airborne pollutants per unit of power produced. Moreover, past investments have skewed generation toward coal-fired power plants at the expense of peak-load capacity. In the context of fast-growing demand, large T&D losses and poor pooling of loads at the national level exacerbate the lack of generating capacity. India is one of the main manufacturers and users of energy. Globally, India is presently positioned as the 11th largest manufacturers of energy. It is also the worlds‘ 6th largest energy users. In spite of its extensive yearly energy output, Indian power sector is a regular importer of energy because of huge disparity. Global and Indian economy have decelerated, but power is one of the few commodities in short supply in India. So, despite the sluggishness in production and demand for manufactured products, India remains power hungry, both in terms of normal and peak power demand. Power is derived from various sources in India. These include thermal power, hydropower or hydroelectricity, solar power, biogas energy, wind power etc. The distribution of the power generated is undertaken by Rural Electrification Corporation for electricity power supply.

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GENERATION Capacity The government has revised the capacity addition target to 78,700 MW from 78,577 for the Eleventh Plan. However, while in 2007-08 it added capacities of 9,263 MW, in 2008-09 only 3,453.70 MW capacities were added against the target of 11,061 MW - 69 per cent below the target. This was due to delays in the supply of critical components in thermal projects and nonavailability of fuel. The capacity addition target for the Tenth Plan (2002-2007) was estimated at 41,110 MW, out of which only 21,095 MW was achieved (2,872 MW was achieved in 2002-03, 3,952 MW in 200304, 3,950 MW in 2004-05 3,468.8 MW in 2005-06 and 6,852.8 MW in 2006-07). Major projects commissioned in the central sector in 2007-08 and 2008-09 include: Sipat STPS-II in Chhattisgarh (thermal based, 1,000 MW) • Ratnagiri CCPP-II (Block 3) in Maharashtra (thermal based, 740 MW) • Omkareshwar (block 1-8) in MP (hydel based, 65 MW each) • Kaiga APP (block 3) in Karnataka (nuclear based, 220 MW)

• Mejia TPS (block 6) in West Bengal (thermal based, 250 MW) • Teesta-V (unit 1, 2 and 3) in Sikkim (hydel based capacity of 170 MW each) •

Kahalgaon in Bihar (thermal based, 1,000 MW)

•

Bhilai TPP in Chhattisgarh (thermal based, 500 MW)

Major projects commissioned in the state sector in 2007-08 and 2008-09 include: Guru Har Govind (Lehra Mohabat) TPS-II project in Punjab (thermal based, 250 MW)

• Rayalaseema TPS-II (unit 4) in Andhra Pradesh (thermal based, 210 MW)

• Dholpur CCPP (ph 1) (unit GT 2 and ST) in Rajasthan (thermal based, 110MW each)

• Bellary TPP (unit 1) in Karnataka (thermal based, 500MW)

• Yamuna Nagar TPP in Haryana (thermal based, 300 MW)

• Priyadarshni Jurala in Andhra Pradesh (hydro based, 39 MW)

• Maneri Bhali-II (unit 1, 2,3 and 4) in Uttrakhand (hydro based, 76 MW each)

• Santadih unit 5 in West Bengal (thermal based, 250 MW)

• Korba East TPP (unit 1 and 2) in Chhattisgarh (thermal based, 250MW each)

• Sagardighi TPP unit 1 in West Bengal (thermal based, 300 MW)

• Dhuvaran CCPP Extn. (Unit ST) in Gujarat (thermal based 40 MW)

• Dugapur TPS Extn unit 7 in West Bengal (thermal based, 300 MW)

• Paras TPS Extension (unit 1) in Maharashtra (thermal based, 250MW)

• Bakreshwar TPS-II unit 4 in West Bengal (thermal based, 210 MW)

• Sanjay Gandhi (Birsinghpur) TPP Extension ST III (unit 5) in Madhya Pradesh (thermal based, 500 MW)

• Purulia PSS unit (1,2,3 and 4) in West Bengal (hydro based, 225 MW each)

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• Balimela-II Extn unit 7 and 8 in Orissa (hydro based, 75 MW each)

• Valuthur CCPP Extn unit GT in Tamil Nadu (thermal based, 59.8 MW)

• GHT (Lehra Mohabbat) TPS-II in Punjab (thermal based, 250 MW)

• Priyadarshini Jurala unit 2 in Andhra Pradesh (hydro based, 39 MW)

• Baglihar HEP unit 1,2 and 3 in Jammu and Kashmir (hydro based, 150 MW each)

• Varahi Extn unit 1 in Karnataka (hydro based, 115 MW)

• Amarkantak TPS Extn unit 5 in Madhya Pradesh (thermal based, 210 MW)

• Sagardighi TPP unit 2 in West Bengal (thermal based, 300 MW)

• Ghatghar PSS unit 1 and 2 in Maharashtra (hydro based, 125 MW each)

Major projects commissioned in the private sector in 2007-08 and 2008-09 include: OP Jindal (Raigarh) TPP phase I and II (unit 1, 2, 3 and 4) in Chhattisgarh (thermal based, 250 MW each) •

Torrent Power has synchronized Sugen CCPP block 1 in Gujarat of 376 MW

•

Tata power has synchronized Trombay TPS unit 8 in Maharashtra of 250 MW

The total installed capacity in India rose from 89,103 MW in 1997-98 to 147,965 MW by the end of 2008-09. In addition, around 19,509 MW of captive power capacity is connected to the grid (as on March 2007). Despite the rise in installed capacity, there has been a significant shortfall in capacity additions when compared to the targets set over the last 10 years. This shortfall is the result of the absence of significant capacity additions by the states and the private sector, which can be attributed to the poor financial health of SEBs and private generators unable to achieve financial closure owing to inadequate payment security mechanisms. Most of the projects in the private sector have been delayed owing to expensive fuel costs (leading to unviable tariffs), delay in obtaining clearance from the CEA and Ministry of Environment and Forest (MoE&F), signing of power purchase agreements (PPAs) and roadblocks in achieving fuel linkage. Over the past 11 years, there has been a marginal shift in the fuel mix. The thermal-hydel mix changed from 72:25 in 1997-98 to 63:25 in 2008-09. The share of thermal plants fell on the back of increase in the share of renewable energy-based plants over the past decade. The share of nuclear power plants in the overall installed capacity, though, continues to remain low.

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Power

-

Installed

capacity

by

ownership

Source: CEA, CRISIL Research

Annual capacity additions Source: CEA, CRISIL Research

Plan-wise capacity additions Source: CEA, CRISIL Research

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Power Generation Power generation increased by 3 per cent, from 699.1 billion kWh in 2007-08 to 723.5 billion kWh in 2008-09. Between 1998-99 and 2008-09, it increased at a CAGR of 4.9 per cent, from 448 billion kWh to 724 billion kWh. The PLF of thermal power plants rose from 64.6 per cent in 1998-99 to 77.19 in 2008-09. The PLF of Indian plants

is

lower

than that of their international counterparts on account of old plants,

inadequate maintenance, poor quality, unsatisfactory transmission

infrastructure and no means of

assured fuel supply.

Average PLF Source: Planning Commission, CEA

Emerging technologies Coal-based Conventional coal-based plants have two major drawbacks - low overall efficiency levels and high pollution levels. As a result, technological research has focused on the development of non-polluting technologies using coal. The most popular of these technologies are fluidized bed combustion (FBC) and integrated gasification combined cycle (IGCC). Fluidized bed combustion In FBC, air is blown at high pressure through finely ground coal. The particles mix with the air and form a floating or fluidized bed. This bed acts like a fluid in which the constituent particles collide with one another. The bed contains around 5 per cent coal (or fuel) and 95 per cent of inert material (such as ash or sand).

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The temperature in a FBC is 800-900 C, compared with 1,300-1,500C in pulverized coal combustion (PCC). The lower temperature helps in minimizing the production of nitrous oxide. Furthermore, most of the sulphur dioxide formed can also be absorbed with the help of absorbents like limestone. The other advantages of FBC technology are its compact nature, ability to burn low calorific value coal (up to 1,800 kcal per kg) and produce less erosive ash. FBC-based plants also have lower capital costs (8-15 per cent lower) as compared to PCC-based plants. At present, the only constraint in using this technology is its small size. While the maximum size of a PCC-based power plant unit could be around 1,500 MW, FBC plants have a maximum unit size of only 250 MW.

Integrated gasification combined cycle IGCC technology is used to enhance the thermal efficiency of coal-based power plants and reduce emissions. In IGCC plants, the coal is gasified using a gasifier. The gaseous coal is purified to remove pollutants such as sulphur. The purified coal is subsequently burnt to generate hot gases, which are used to run a gas turbine. The exhaust gases, containing waste heat, are used to boil water and generate steam. The steam is used to run a steam turbine. IGCC technology can deliver thermal efficiency of up to 48-50 per cent. In addition, it can be used with other heavy fuels such as refinery residues and petroleum coke. IGCC technology is also environment friendly, as pollutants such as sulphur dioxide and oxides of nitrogen, are reduced to very low levels. However, the cost of IGCC plants is higher than conventional plants. Nuclear Power Nuclear power plants reduce carbon dioxide emissions. However, safety concerns abound, particularly those relating to exposure to harmful nuclear radiations. In addition, the cost of a nuclear plant is around three times higher than that of a gas-based plant. However, new technologies are being developed to address some of the safety issues associated with nuclear power plants.

Pebble bed modular reactor The pebble bed modular reactor (PBMR)differs from a conventional ‗light water‘ reactor as it utilizes no fuel rods and cooling water. The fuel comprises nearly 15,000 small carbon and ceramic-coated specks of uranium that are pressed into a small pebble. The pebble is coated with a layer of graphite. Inside the pebble, uranium undergoes fission and releases heat. However, the graphite layer traps the radioactivity. Around 300,000 pebbles are kept in a reactor, which is cooled by a flow of helium gas. The helium gas expands due to the heat and spins an electricity generating turbine. However, since helium is chemically and radiologically inert, it does not become radioactive as it circulates through the pebble bed.

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One of the main advantages of PBMR technology is that relatively small units producing 100-150 MW of power can use it. In addition, the core of the reactor does not melt even at high temperatures, as the operating temperature continues to remain below the melting point of the ceramic pebbles that contain the fuel. This helps prevent safety hazards. Distributed generation In distributed generation, small generators are located near the consumer site, within the distribution system. Distributed gencos are not directly connected to the transmission grid. Considering the technological improvements and reduction in the costs of small generators, the amount of power consumption through distributed generation is expected to rise in the future. Comparison of different modes of generation:

Type of Generation

Advantages

Disadvantages

Thermal Power Plants

Low cost of generation

Long gestation period

Abundant availability of coal.

Emissions of carbon dioxide and oxides of sulphur Lack of flexibility in operation.

Hydro Electric Plants

Low operating costs

Long gestation period

The absence of emissions

Economic and social costs associated with

Flexibility of operations

the rehabilitation and resettlement of the population affected by the submergence of land Submergence of forests and loss of marine life due to large water reservoirs Possibility of inducing earthquakes

Nuclear Power Plants

Do not emit gases or particulate matter

Maintenance of high safety standards for

Low cost of generation

eliminating the possibility of nuclear hazards High capital costs and long gestation period

Diesel Generation Sets

Short gestation period High

efficiency

in

varying

load

conditions Flexibility to use fuels such as HSD, LDO, LSHS and FO Modular installation (possible to add

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more units).

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Resources In India, power generation is largely dependent on coal, gas, nuclear and hydroelectric sources. Nonconventional sources of energy such as wind and solar energy, account for a small share of the total installed capacity. Fuel oil and diesel are largely used in captive power plants. Coal

In India, the proportion of coal-based capacity has increased significantly over the years. According to the Geological Survey of India, in January 2008, the total coal reserves in India were estimated at around 257 billion tonnes (including the non-recoverable reserves under riverbeds or urban areas). Out of this, proven reserves stood at 99 billion tonnes, while indicated reserves were 121 billion tonnes, the rest being accounted by inferred reserves. In India, the majority of coal reserves are concentrated in the eastern and south eastern regions. Jharkhand, Orissa, Madhya Pradesh, Chhattisgarh, West Bengal and Andhra Pradesh account for around 95 per cent of the country‘s total coal reserves. The power generation sector is the largest end-user of coal in India. In 2007-08, it made up for almost 71 per cent of total coal consumption. In February 1997, the Central government allowed private sector companies to mine coal for captive consumption; and for supply and distribution. In the past, only Coal India Ltd (CIL), a public sector company, could undertake commercial mining and supply of coal. CIL is organized into several regional subsidiaries, which mine coal in their respective regions. Till March 1996, prices of all grades of coal were regulated. However, in April 1996, the prices of A, B and C grades were deregulated. In February 1997, the price of D grade coal was also deregulated. During 1990-2000, the average pithead price of coal increased at a CAGR of 11 per cent. In June 2004, CIL increased the pithead price of coal by 14-16 per cent. Prices were revised again in December 2007 - there was a 10 per cent increase by CIL and its subsidiaries, and by 15 per cent increase by North Eastern Coal Fields Ltd. Even if prices rose further, it will not have any impact on the power sector, as all PPAs have a fuel cost passage clause. In view of high ash content of Indian coal, the MoE&F has stipulated that all future power plants (situated 1,000 kms away from the pit-head) should be based on washed coal. But, the existing washery capacity in India is not adequate to meet the requirements of the power sector. In

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addition, CIL does not have adequate funds to invest in coal washeries. However, the private sector has undertaken some initiatives for setting up coal washeries with foreign participation as well as in collaboration with CIL. Natural Gas

Natural gas-based power generation capacity (including naphtha-based capacity) accounted for around 10 per cent of the total installed capacity as of March 2009. Further, of the total natural gas produced in India, 35 per cent is sourced to generate electricity and 29 per cent to produce fertilizers. At the end of 2007, the proven and recoverable reserves of natural gas in India were estimated at 1,055 billion cubic meters (bcm). Around 40 per cent of the gas reserves are located off the western coast, in the Bombay High and the Hazira fields. In 2007-08, the gross production of natural gas was around 32.3 bcm. In the past, a large portion of gas production was flared or re-injected due to inadequate evacuation infrastructure. The Hazira-Vijaipur-Jagdishpur (HVJ) pipeline evacuates about 40 per cent of the gas produced in India. Most of the fertilizers, petrochemicals and power plants based on natural gas are located along this pipeline. The consumption of natural gas for power generation and other end uses (like fertilizers) is expected to increase significantly over the next 5-10 years, as natural gas is an environment friendly and economic fuel. In India, the consumption of natural gas was 114.2 mmscmd in 2007-08. However, the unmet demand continued to be around 20 mmscmd. At the current rate of production, the known and recoverable gas reserves of India are expected to last for around 30 years. In order to supplement domestic supply, India is expected to import natural gas, either through pipelines or as liquefied natural gas (LNG). Hence, substantial investments will be required in receiving terminals, regasification plants and cryogenic shipping vessels to import LNG. Additional investments are also required in pipelines for the inland distribution of natural gas. New domestic supply of natural gas has commenced from Reliance Industries Ltd (RIL)‘s KG Basin block. It is currently producing 40 mmscmd of gas, and is expected to ramp this up to 80 mmscmd of gas by December 2009. Also, discoveries of large natural gas reserves in Myanmar have prompted several multinational companies to propose construction of pipelines to transport the surplus natural gas to eastern and northern India. In addition, there are proposals to lay pipelines from West Asia to India

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(Afghanistan-Pakistan-India). The proposed pipelines include an onshore pipeline from Iran-PakistanIndia and a submarine pipeline from Oman. However, neither proposal has progressed due to unresolved political and economic issues.

DEMAND - SUPPLY Demand for power registered at a CAGR of around 6 per cent from 1998-99 to 2008-09. Further, there has been a sectoral shift in demand for electricity. The share of the industrial sector declined steadily till 2001-02, and then started rising at a flat rate. The share of industrial demand has increased from 25 per cent in 2002-03 to 37 per cent in 2006-07. The agricultural consumption, after peaking at 31 per cent in 1998-99, declined to 22 per cent in 2006-07. Conversely, domestic demand rose steadily, from 20 per cent in 1996-97 to 24 per cent in 2006-07. As per the forecast of the Seventeenth Electric Power Survey (EPS), energy demand will increase at a CAGR of 8.4 per cent to 969 billion kWh during the Eleventh Five-Year Plan period (2007-2012). Peak demand is projected to register a CAGR of 12.3 per cent to 167,054 MW. The government has revised the capacity addition target to 78,700 MW from 78,577 MW for the Eleventh Plan. However, in the first 2 years of the Eleventh Plan only 12,716.70 MW of capacity has been added as against the target of 27,396 MW. This is because only 9,263 MW against the target of 16,335 MW was added in 2007-08. In 2008-09, the target fell short by 69 per cent due to delays in the supply of critical components of thermal projects and non-availability of fuel. Therefore, in 2008-09, only 3,453.70 MW was added against the target of 11,061 MW. Taking these factors into account, CRISIL Research estimates that only around 44,846 MW of capacities will be added during the Eleventh Plan period. The central sector is expected to account for a major portion of the capacity additions (37 per cent), followed by the state sector (35 per cent) and the private sector (28 per cent), respectively.

Sectoral demand The pattern of electricity consumption in the various sectors has changed considerably over the years. During 1996-97 to 2006-07, electricity consumption in the agricultural, commercial, industrial and domestic sectors increased at a CAGR of 4.9 per cent.

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Agricultural sector: The agricultural sector had a very low share of power consumption during the early 1970s. However, stress on rural electrification led to an increase in power consumption from 10-15 per cent in 1970 to 31 per cent in 1998-99. But low tariffs and lack of proper metering resulted in underrecoveries and inefficient utilization of power in this sector, which led to the sector‘s share in power consumption declining to 22 per cent 2006-07. Industrial sector: Electricity consumption in the industrial sector increased at a CAGR of 5.1 per cent from 1996-97 to 2006-07. However, the share of the industrial sector in total electricity consumption fell from 37.2 per cent in 1996-97 to 30.2 per cent in 2001-02; but with the opening up of the power sector, it gradually rose to 37.6 per cent in 2006-07. In view of the continuous uptrend in industrial electricity tariffs, power-intensive industries find it economical to set up captive power plants, especially through co-generation. Further, irregular power supply and increasing shutdowns caused by power shortages, has forced players to rely on captive power facilities. Domestic sector: In the domestic sector, electricity consumption grew at a CAGR of 7.2 per cent from 1996-97 to 2006-07. The share of the domestic sector in total electricity consumption went up from 19.7 per cent in 1996-97 to 24.4 per cent in 2006-07, driven mainly by urbanization and the increasing usage of household appliances (geysers, air-conditioners, etc).

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Power - Category-wise consumption Source: Central Electricity Authority (CEA)

Power - Demand and supply, Source: Ministry of Power, CEA

ELECTRICITY DEMAND FORECAST Electric power surveys: The CEA constitutes a committee every 4-5 years that carries out a comprehensive survey of various consumer segments for estimating the demand for power. The committee publishes the EPS, which provides state-wise demand forecasts, both in terms of energy and peak power requirements, for a 15-year period. It also provides a sector-wise estimate of energy demand for a 5-year period. The •

consumer Domestic

segments

taken

into

account •

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by

Commercial

the

EPS

are:

•

Agricultural

•

Industrial [low tension (LT) and high

tension (HT), separately] •

•

Public lighting

•

Public waterworks

•

Non-industrial bulk consumers

Railway traction

Power - Demand project ions Note: Figures are based on the 17th Electric Power Survey (EPS), published in February 2007. Source: CEA

Elasticity of electricity consumption with respect to GDP growth Electricity consumption is strongly related to the level of economic activity. However, over the past 25 years the elasticity of electricity consumption vis-à-vis the gross domestic product (GDP) has been gradually declining. This decline is likely to continue, owing to: •

An increase in the share of the services sector (about 56 per cent in 2007-08, compared to less than 30 per cent in 1990-91).

•

Efforts by industries to improve energy efficiency (to enhance competitiveness) through more efficient technologies and energy audits.

•

Greater reliance on captive power plants by power-intensive industries due to the high tariffs charged by SEBs and poor quality of grid power.

The average annual GDP growth rate (at constant prices) during the Eighth, Ninth and Tenth Plan periods was 5.9 per cent, 5.5 per cent and around 7.7 per cent, respectively. The annual growth in electricity generation during these periods was 7.2 per cent, 5.7 per cent, and 4.4 per cent, respectively.

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Elasticity of electricity generation with respect to GDP is the percentage change

in

generation

corresponding to a 1 per cent change in GDP. The elasticity of electricity generation (not including captive generation) with respect to GDP has fallen from around 1.47 during the Sixth Plan period to around 0.60 during the Tenth Plan period. This implies that energy usage in the economy has declined, partially due to a rise in the share of the services sector (which is less energy-intensive as compared with the industrial sector) in the GDP and partially due to an improvement in energy efficiency.

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TRANSMISSION Review The transmission segment plays a key role in transmitting power continuously to various distribution entities across the country. Further, the transmission sector needs concomitant capacity additions in line with the generation capacity additions to enable seamless flow of power. The government‘s focus on providing electricity to rural areas has led to the power T&D system being extended to remote villages. The total length of transmission lines in the country has increased from 2.50 million circuit kilometers (ckm) in 1980-81 to 6.94 million ckm in 2006-07.

Power-Transmission Lines The decline in 2003-04 is due to reconciliation in data done by the Data Supplying Organization in 33/22 kV, 15/11 kV and in distribution lines up to 500 volts. Source: CEA

Transmission line addition (April 2008 to March 2009) Source: CEA

Substation addition (April 2008 to March 2009) Source: CEA

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Overview and Structure A reliable T&D system is important for the proper and efficient transfer of power from generating stations to load centers. A T&D system comprises transmission lines, substations, switching stations, transformers and distribution lines. In order to ensure reliable supply of power and optimal utilization of generating capacity, a T&D system is organized in a grid, which interconnects various generating stations and load centers. This ensures uninterrupted power supply to a load centre, even if there is a failure at the local generating station or a maintenance shutdown. In addition, power can be transmitted through an alternate route if a particular section of the transmission line is unavailable. In India, the T&D system is a three-tier structure comprising distribution networks, state grids and regional grids. These distribution networks and state grids are primarily owned and operated by the respective SEBs or state governments (through state electricity departments). Most

inter-state

transmission links are owned and operated by PGCIL, with some jointly owned by the SEBs concerned. In addition, PGCIL owns and operates a number of inter-regional transmission lines (part of the national grid) to facilitate the transfer of power from a surplus region to one with deficit. The transmission capacity added, over the years, has been lower than the generation capacity addition. This is also seen by lower investments in T&D compared to generation. Globally, every rupee invested in generation has an equal amount invested in T&D, however in India, every rupee invested in generation has a corresponding 50 paisa invested in T&D. This has also resulted into excess loading of transmission lines at around 90 per cent. The transmission capacity added as a part of the national grid in the previous year has been at a brisk pace of 5,550 MW from December 2006 to December 2007. This has been in line with the target of 37,150 MW to be added by the end of Eleventh Plan. The current inter-regional capacity stands at 17,000 MW (as on December 2007).

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Transmission lines Source: Ministry of Power &CRISIL Research

The transmission system in India operates at several voltage levels: •

Extra high voltage (EHV): 765 kV, 400 kV and 220 kV

•

High voltage: 132 kV and 66 kV

•

Medium voltage: 33 kV, 11 kV, 6.6 kV and 3.3 kV

•

Low voltage: 1.1 kV, 220 volts and below

Transmission and sub-transmission systems supply power to the distribution system, which, in turn,

supply

power

to

end consumers.

In order to facilitate the transfer of power between

neighbouring states, state grids are inter-connected through high-voltage transmission links to form a regional grid. There are five regional grids: •Northern region: Delhi, Haryana, Himachal Pradesh, Jammu and Kashmir, Punjab, Rajasthan, Uttaranchal and Uttar Pradesh •Eastern region: Bihar, Jharkhand, Orissa, Sikkim and West Bengal •Western region: Dadra and Nagar Haveli, Daman and Diu, Chhattisgarh, Goa, Gujarat, Madhya Pradesh, and Maharashtra •Southern region: Andhra Pradesh, Karnataka, Kerala, Pondicherry and Tamil Nadu •North-eastern region: Arunachal Pradesh, Assam, Manipur, Meghalaya, Mizoram, Nagaland and Tripura

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As peak demand for power does not take place at the same time in all states, it results in a surplus in one state and deficit in another. Regional or inter-state grids facilitate the transfer of power from a surplus region to the one facing a deficit. These regional grids also facilitate the optimal scheduling of maintenance outages and better coordination between power plants. These regional grids will be gradually integrated to form a national grid, whereby power from a surplus region can be transferred to another, resulting in the optimal utilization of generating capacity. For instance, the eastern region has some surplus power, which is transferred to the western and northern regions as the two regions have deficit scenarios.

National grid In order to optimize the utilization of generation capacity through the exchange of power between the surplus and deficit regions, and exploit the uneven distribution of hydroelectric potential across various regions, the Central government in 1981 approved a plan for setting up a national grid. The plan envisaged setting up high-voltage transmission links across various regions in order to enable the transfer of power from surplus to deficit regions. The advantages of a national grid system are: A flatter demand curve (or a higher system load factor) on account of the exchange of power between regions, resulting in a better PLF and more economical operations; Lower investments required for new generation capacities (a full-scale national grid is expected to reduce the need for new capacities by up to 10,000 MW in the next 10 years.); Better scheduling of planned outages of power plants; and Improved stability of the grid, as the share of an individual generating station in the total capacity declines with greater integration of the power system. The process of setting up the national grid was initiated with the formation of the central sector power generating and transmission companies - National Thermal Power Corporation (NTPC), National Hydroelectric Power Corporation (NHPC) and PGCIL. PGCIL was given the responsibility for planning, constructing, operating and maintaining all inter-regional links and taking care of the integrated operations of the national and regional grids. A national grid would enable optimal utilization of energy resources by facilitating a uniform thermal-hydel mix among various regions. From a regional perspective, the exploitation of

~ 25 ~

thermal and hydroelectric resources may not be economically viable in some cases, although it may be so from a national perspective. For instance, Arunachal Pradesh had a hydroelectric potential of around 50,000 MW. (The hydro potential available in Arunachal Pradesh is the highest in the country.) However, of this, only 400 MW has been developed and a further 3,000 MW is under development by NHPC and NEEPCO. Another 23,000 MW of capacities are being planned by various central and private sector players. However, in terms of installed capacity, 95 per cent of the potential is yet to be developed. The hydroelectric potential of the north-eastern region and eastern region is around 60,000 MW and 10,000 MW, respectively. Hence, with the integration of the eastern and north-eastern regions, the hydroelectric potential of the north-eastern region can be used to meet the peak demand of the eastern region. Setting up a national grid requires the gradual strengthening and improvement of regional grids, and their progressive integration through extra high voltage (EHV) and HVDC transmission lines. Coordination among the states within a region and among the various regions is critical for the operation of the national grid. This would require an efficient and reliable communication system, comprising microwave links and dedicated data/voice transmission lines between the load dispatch centers and generating stations. In addition, synchronization of frequencies is required to integrate regional grids. In the case of a difference in frequencies, HVDC transmission would be effective in integrating the grids through an asynchronous link. Although some inter-regional links are operational, these do not have adequate capacity to transmit bulk power, and are often loaded to capacity. The national grid, when fully operational (likely by around 2012), is expected to have a total inter-regional transmission capacity of 37,150 MW. Major milestones in national grid Source: CRISIL Research

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Power - Inter-regional power capacity Source: PGCIL

Inter-regional capacity (till December 2007 17,000 MW) Source: Working Committee Report and CRISIL Research

Expected Inter-regional capacity by 2011-12 (37,150 MW) Source: Working Committee Report and CRISIL Research

Grid discipline Several problems related to the integrated operations of regional grids can be attributed to the lack of discipline among grid constituents. Grid discipline involves maintaining the grid frequency within

~ 27 ~

tolerance limits (49.2-50.3 Hz) and complying with the directions of the Regional Load Despatch Centers (RLDCs), with respect to load despatch and drawing of power. There have been several instances of grid collapse after constituent states drew excess power or because there were fluctuations in the grid frequency. Under the Electricity (Supply) Act, SEBs are expected to comply with the directions of RLDCs to ensure the integrated operation of regional grids. However, in the absence of adequate incentives and disincentives, RLDCs are unable to enforce the directives. Further, load management, through load shedding or backing down by each of the constituents, is an important aspect of the operation of a grid system. Inadequate load dispatch and communication facilities often result in lack of co-ordination with respect to the scheduling of load and generation between states. In 1999, the CERC drafted the Indian Grid Code, which, along with the incentives and disincentives notified under the Availability-Based Tariff (ABT) Order, is expected to induce better grid discipline among the various grid constituents.

Unscheduled interchange (UI) charges are levied on defaulting entities which overdraw/under draw from the grid and disturb the grid balance. Previously, the UI charges had been escalated up to Rs 10 per unit of excess capacity drawn. However, recently the CERC in order to improve the grid stability reduced the band (i.e. From 50.5-49.0 Hz to 50.3-49.2 Hz), and charges to Rs 7.3 per unit of excess units drawn.

Private investments in transmission In 1998, the Central government enacted the Electricity Laws (Amendment) Act, which recognized transmission as an independent activity (distinct from generation and distribution), and allowed private investments in the sector. According to the government policy, the STUs, SEBs or their successor entities and the central transmission utility (CTU) PGCIL will identify transmission projects for the intra-state and interstate/inter-regional transmission of power, respectively.

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The STUs and CTU will invite private companies to implement these projects through an independent private transmission company (IPTC) or on a JV basis. The IPTC would be selected through an international competitive bidding process. The primary criteria for selection would be the quoted transmission service charges (TSC) and the technical, managerial and financial capabilities of the bidders. In the case of JV companies, the CTU and STUs could own an equity stake of up to 26 per cent. JV partners could also be selected on the basis of an international

competitive

bidding

process. Further, the primary selection criteria would be the

technical and financial strength of the bidders. Transmission service charges would be determined on a cost plus basis under the supervision of the CERC or SERCs. The IPTC‘s role will be limited to the construction, ownership and maintenance of transmission lines. Operations of the grid, including load dispatch, scheduling and monitoring, will be undertaken by the STUs and the CTU at the intra-state and inter-state/inter-regional level, respectively. The CTU and STUs will be involved

in

the development phase for obtaining project approvals and various

regulatory and statutory clearances (such as environment and forest clearance and securing right-ofway), and will transfer the same to the selected private companies.

Technology in transmission HVDC transmission

One of the pre-requisites for integrating grids is to synchronies their frequencies. In India, synchronous integration of regional grids was not possible due to variations in frequencies and voltages. Therefore, the most viable alternative is the asynchronous transfer of power through HVDC transmission links. Advantages of HVDC transmission Cost consideration: DC conductors cost less than AC conductors, as DC transmission requires smaller conductors for carrying the same load of power. In addition, only two conductors are required for DC transmission, while AC transmission requires three. However, the cost of HVDC terminals is higher than that of AC substations. Hence, for a given load of power to be transferred, there is a break-even distance, beyond which, DC transmission would be more economical (approximately 600 km for 500 MW).

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Maintaining independence of the systems: Impact on a system (due to disturbances in the other) is eliminated due to asynchronous linking. Right of way: For an equivalent load of power transferred, HVDC transmission requires lesser right of way compared with AC lines, as each HVDC line can transmit a higher quantum of power.

Transmission cost structure Capital costs The capital costs of the transmission line network have a significant impact on transmission tariffs. Capital costs depend on: Configuration of the line :The configuration of the transmission line, in terms of voltage levels (220 kV, 400 kV, 765 kV etc), mode of transmission (AC or HVDC) and other parameters (single circuit or double circuit) have an impact on the overall capital cost per km. Although the capital cost of transmission projects can vary significantly, the average estimated costs per km for different configurations are: Transmission lines 220 kV double circuit: Rs 5.0-6.0 million per ckm 400 kV single circuit: Rs 7.5-8.0 million per ckm 400 kV double circuit: Rs 11.0-11.5 million per ckm 765 kV single circuit: Rs 15.0-16.0 million per ckm

Transmission system components

Source: CRISIL Research

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Cost of setting up a transmission line Source: Industry publication

DISTRIBUTION Distribution is the last and critical leg in the supply of electricity, reaching end consumers such as residential, commercial, agricultural and industrial segments. Distribution has several components such as pricing to various customers, cross subsidization etc. However, as this is a lucrative business, it has been held by the respective state entities, with private participation being marginal (only 5-7 per cent of the total). Further, issues is distribution vary from T&D losses to rural electrification etc. The government has begun a number of initiatives to improve the electricity supply to villages. As part of its initiatives, the power distribution system has been extended to reach remote villages. At the end of 2008-09, a total of 488,926 villages were electrified. However, T&D losses in the country remain high at around 28 per cent, compared to an average 10-15 per cent in developed countries. This is because of inadequate metering and theft of electricity. (The difference in the amount of electricity supplied and the amount actually metered is usually reported as T&D losses.) High T&D losses are also attributed to the T&D of a large amount of power at low voltage - the rise in rural electrification has resulted in the proliferation of low voltage (less than 11 kV) transmission lines. T&D losses rose from 22.27 per cent in 1995-96 to an estimated 26.91 per cent in 2007-08. The losses peaked at 33.98 per cent in 2001-02, but since have registered a declining trend.

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Power: T&D losses P: Projected; E: Estimate Source: CEA

Tariffs and financial performance of SEBs In India, average electricity tariffs are lower than the average cost of supply (cost of generation plus T&D costs). The gap between average tariff and average cost of supply has increased from 36 paisa per kWh in 2005-06 to 49 paisa per kWh in 2006-07. The main reason for this has been the annual losses of all SEBs which have been increasing continuously - the commercial losses of all SEBs have gone up from over Rs 40 billion in 1991-92 to Rs 257 billion in 2006-07.

Power: Costs and tariffs Source: Planning Commission

T&D losses T&D losses can be classified into two main categories: Technical losses

~ 32 ~

The technical component of T&D losses has an inverse relationship with the voltage configuration of the T&D system. Transmission of bulk power of high voltage (400 kV, 220 KV, 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 unauthorized connections. On account of inadequate metering arrangement, it is difficult to estimate the extent of the loss and attribute it to a specific reason. Some of these losses are reported as ‗agricultural consumption‘ since most rural connections are unmetered. In addition, a large proportion of the losses can be attributed to theft through unauthorized connections in both rural and urban areas. Though commercial losses are not completely avoidable, they can be reduced substantially through investments. Reasons for high T&D losses A weak and inadequate T&D system. Large-scale rural electrification programme (due to low voltage distribution lines). Numerous transformation stages: This results in a high component of transformation losses. There are 5-6 transformation stages in the Indian T&D network due to the proliferation of low-voltage consumption. The use of low capacity and inefficient transformers results in higher losses and dis-economies of scale. Improper load management: This overloads transmission lines. Transmission lines should be loaded up to 50-60 per cent of their capacity. However, in India, transmission lines are generally loaded to 90 per cent of their capacity, and often operate on ‗alert condition'. As a result, a small disturbance in a section can cause a cascading grid failure. Pilferage and theft of energy. A reduction in T&D losses by one percentage point is equivalent to the power generated from a 600-700 MW plant. Although the cost of achieving the reduction is difficult to estimate, it would be a fraction of the investment required for setting up a new capacity (around Rs 25 billion).

~ 33 ~

Measures to reduce losses Technical losses Technical losses can be reduced by adopting the following measures: Reducing the length of LT lines by relocating distribution substations, installing additional substations and converting LT lines into HT lines. Installing capacitors at suitable locations. Reducing the number of transformation stages and using high-efficiency transformers. Installing time-of-day meters with incentives to promote the usage of off-peak energy, in order to reduce over-loading of T&D lines. Using better equipment such as all aluminum alloy conductors (AAACs); this can reduce heat losses by 8-12 per cent and eliminate magnetic losses. Although AAACs are priced around 10 per cent higher than aluminum conductor steel reinforced (ACSR), their average life is 60-80 years, as compared with around 30 years for ACSR. Installing high-quality energy meters at the premises of all consumers and substations.

Commercial losses Commercial losses can be reduced by adopting the following measures: Supplying metered energy to all consumers. Prompt calibration, replacement of faulty meters and using tamper-proof meters. Preventing pilferage through stronger legislation and better enforcement.

Privatization Privatization of distribution is generally accepted as the first phase in the reforms and restructuring of the power sector. With private participation in power distribution, significant benefits are expected to accrue, such as: Reduction in T&D losses. Improvement in metering and billing practices. Improvement in revenue collection.

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Distribution reforms To improve distribution, the government formulated the Accelerated Power Development Reform Programme (APDRP).This programme aims to improve the financial viability of state power utilities, reduce aggregate technical and commercial losses to around 10 per cent, improve customer satisfaction, and increase reliability and quality of power supply. The APDRP has two components -investment and incentive components. Under the investment component, the government provides assistance worth 50 per cent of the project cost, of which 25 per cent is a grant and 25 per cent is a loan. The balance 50 per cent has to be arranged by the utilities either through internal resource generation or from financial institutions or from other sources of funds (such as state government, the Rural Electrification Corporation, Life Insurance Corporation, ICICI, SIDBI and market bonds). Special category states such as Jammu and Kashmir, Himachal Pradesh, Uttaranchal and Sikkim receive full assistance from the Central government, out of which 90 per cent is grant and the remaining 10 per cent is loan. Priority is given to projects from those states that have committed to a time-bound programme of reforms as elaborated in the Memorandum

of

Understanding (MoU) and Memorandum of Agreement (MoA), and are progressing on those commitments.

Conditions of the MoU are: •

Setting up SERC

Filling and implementation of tariff orders

•

Securitization of CPSUs dues

Energy audit at 11 kV level

•

Metering of all consumers

Maintenance of grid discipline

Metering of 11 kV feeder Conditions of the MoA are: •

Constitution of Distribution Reform Committee at the state level

•

Identification of nodal officer

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As part of the incentive component, the utilities are rewarded for actual cash loss reductions by waiving half of the cash losses reduced by way of free grant. The cash losses are calculated as the net of subsidy and receivables. Up to March 31, 2008, the funds released under this component were Rs 28.8 billion. The disbursement for 2006-07 and 2007-08 was Rs 10.2 billion and Rs 14.0 billion, respectively. (This includes both the investment and incentive components.)

New R-APDRP Till December 2008, the Government of India had sanctioned 571 projects, amounting to Rs 170.33 billion to strengthen and upgrade sub-transmission and distribution systems of the various states. The states have so far utilized Rs 126.07 billion. An amount of Rs 28.79 billion has also been released to nine states for achieving reduction in cash losses under the incentive component of the programme. As per the new APDRP policy, projects under the scheme shall be taken up in two parts: Part-A includes the projects for establishing baseline data and IT applications for energy accounting/auditing and IT-based consumer service centers. Part-B includes the regular distribution strengthening projects

REFORMS IN THE POWER SECTOR Pre Reform Stage Confronted with unprecedented economic crisis in 1991, Government of India embarked upon a massive cleanup exercise encompassing all policies having financial involvement of Governments- both at the level of Union and States. Since after Electricity (supply) Act 1948, the power sector was mainly under the government control which owned 95 % of distribution and around 98% of generation through states' and central government utilities, the power sector was chiefly funded by support from government budgets in the form of long term, concessional interest loans. These utilities were made to carry forward the political agenda of the ruling parties of the day and the cross- subsidization i.e. charging industrial and commercial consumers above the cost of supply and to charge agricultural and domestic consumers below cost of supply was an integral part of the functioning of the utilities.

~ 36 ~

POWER SECTOR REFORMS YEAR 1991

MAJOR DEVELOPMENTS The Electricity Laws (Amendment) Act, 1991--Notification. Amends the Indian Electricity Act, 1910 and the Electricity (Supply) Act, 1948 by Private Sector allowed to establish generation projects of all types (except nuclear) 100% foreign investment & ownership allowed New pricing structure for sales to SEBs. 5 Year Tax holiday; import duties slashed on power projects

1992

Intensive wooing of foreign investors in US, Europe & Japan

1992-97

8 projects given "fast-track" status. Sovereign guarantees from Central Government. Seven reached financial closure Dabhol (Enron), Bhadravati (Ispat), Jegurupadu (GVK), Vishakhapatnam (Hinduja), Ib Valley (AES), Neyveli (CMS),Mangalore (Cogentrix)

1995-96

World Bank Reform Model - First Test Case Orissa Orissa Electricity Reform Act passed Establishment of Orissa Electricity Regulatory Commission SEB unbundled into Orissa Power Generating Company (OPGC), Hydel Power Corporation (OHPC) and Grid Corporation of

Orissa

Orissa (GRIDCO)

Distribution privatized 1996

Chief Ministers Conference: Common Minimum Action Plan for Power: Recommend policy to create CERC and SERCs Licensing, planning and other related functions to be delegated to

SERCs.

Appeals against orders of SERCs to be in respective High Courts SERC to determine retail tariffs, including wheeling charges etc.,

which

will ensure a minimum overall 3% rate of return. Cross -subsidization between categories of consumers may be SERCs, but no sector to pay less than 50% of the

~ 37 ~

allowed by

average cost of supply (cost

of generation plus transmission and

distribution). Tariffs for agricultural

sector not to be less than Rs.0.50 Kwh and to be brought to 50% of the average costing not

more than three years.

Recommendations of SERCs to be mandatory, but financial any deviations made by State/UT Government, to be

implications

provide for the explicitly

in the State budget. Fuel Adjustment Charges (FCA) to be automatically incorporated in

the

tariff. Package of incentives and disincentives to encourage and

facilitate the

implementation of tariff rationalization by the States. States to allow maximum possible autonomy to the SEBs, which restructured and corporatized and run on commercial

are to be

basis. SEBs to

professionalize their technical inventory manpower and project management practices. 1997

CEA Clearance exempted for projects under 1000MW but State Government environment clearance required up to 250-500 MW Liquid fuel policy -- naphtha allocations to IPPs

1998

Mega-Power Policy: special incentives for the construction and operation of hydro-electric power plants of at least 500 MW and thermal plants of at least 1,000 MW. - The Electricity Laws (Amendment) Act, 1998 and Electricity Regulatory Commissions Ordinance -- Notification. Creation of Central Transmission Utility STUs to be set up with government companies Establishment of CERC and SERCs Rationalization of electricity tariffs, Policies regarding subsidies Promotion of efficient and environmentally benign policies - Power Grid notified as Central Transmission Utility - Haryana Electricity Reforms Act: HSEB unbundled into Haryana Vidyut Prasaran Nigam Ltd., a Trans Co.

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(HVPNL) and Haryana Power Corporation Ltd. Creation of HERC Two Government owned distribution companies viz. Uttar Haryana Bijli Vitaran Nigam Ltd. (UHBVNL) and Dakshin Haryana Bijli Vitaran Nigam (DHBVNL) have been established. DFID's technical co-operation grant of 15 million pounds available for reforms. 1999

Andhra Pradesh Electricity Reforms Act APSEB unbundled into Andhra Pradesh Generation Company Ltd. (APGENCO) and Andhra Pradesh Transmission Company Ltd. (APTRANSCO for transmission & distribution) Creation of APERC Other Developments: World Bank loan of US $ 210 million under the APL DFID's 28 million pounds as technical co-operation grant. CIDA technical assistance of Canadian $ 4 million. - Karnataka Electricity Reforms Act KEB and KPCL transformed into new companies: Karnataka Power Transmission Corporation Ltd. (KPTCL) and Visvesvaraya Vidyut Nigama Ltd., a GENCO, (VVNL) Creation of KERC Other Developments: KPTCL has carved out five Regional Business Centers (RBC) for five identified zones.

2000

Power Ministers' Conference and Electricity Bill 2000 (draft): Functional disaggregation of generation, transmission and distribution with a view to creating independent profit centres and accountability; Re organization and restructuring of the State Electricity Boards in accordance with the model, phasing and sequencing to be determined by the respective State Governments States to determine the extent, nature and pace of privatization.

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(public sector entities may continue if the States find them sustainable); Transmission to be separated as an independent function for creation of transmission highways that would enable viable public and private investments; Amendments to the Indian Electricity Act, 1910 made in 1998 for facilitating private investment in transmission have been broadly retained except that the private transmission companies would be regulated by the Regulatory Commissions and Transmission Centres inst under the direction, supervision and control of the Central/State Transmission Utilities; Present entitlements of States to cheaper power from existing generating stations to remain undisturbed; Provision of compulsory metering for enhancing accountability and viability; Central and State Electricity Regulatory Commissions to continue broadly on the lines of the Electricity Regulatory Commissions Act, 1998; State Regulatory Commissions enjoined to recognize in their functioning the need for equitable supply of electricity to rural areas and to weaker sections; Stringent provisions to minimize theft and misuse. Source: www.cea.nic.in/power_sec_reports/general_review/0405/index.pdf

Electricity Act 2003 An Act to consolidate the laws relating to generation, transmission, distribution, trading and use of electricity and generally for taking measures conducive to development

of electricity

industry, promoting competition therein, protecting interest of consumers and supply of electricity to all areas, rationalization of electricity tariff, ensuring transparent policies regarding subsidies, promotion of efficient and environmentally benign policies constitution of Central Electricity Authority, Regulatory Commissions and establishment of Appellate Tribunal and for matters connected therewith or incidental thereto.

~ 40 ~

Enabled Market Model under EA 2003

Generation Any Company, association or body of individuals (even unincorporated) can generate electricity without requirement of techno-economic clearance of CEA, or approval of State Government or regulator, except in case of hydropower station for which written consent of Central Electricity Authority is required. A Generating Company can supply electricity directly to more than one consumer and is vested with the duty to establish, operate and maintain sub-stations, tie lines etc. Any entity, (company, co-operative society or association of persons) can establish a Captive Generation Plant (CGP) primarily for its own use without any entry barriers. Open access is to be provided to all CGPs. No cross-subsidy surcharge would be levied on the persons who have established CGP for carrying electricity to destination of his own use.

Rural Electrification/Generation/Distribution Government of India will have to formulate a National Policy after consulting State Governments & CEA, to govern (i) rural electrification and local distribution through local

~ 41 ~

bodies5, and (ii) rural off-grid supply including those based on renewable/nonconventional energy resources. No license is required for generating or distributing in rural areas notified by the State Govt.

Licensing Trading has been recognized as a separate licensed activity along with transmission and distribution. However, a license is not required in respect of (i) trading by a distribution licensee, (ii) transmission, distribution or trading by any Govt., as the Govt. would be deemed a licensee. Electricity Regulatory Commission (ERC), on the recommendation of Government, in accordance with the national electricity policy and public interest can exempt any of the local bodies6 from requiring license.

Trading and Captive Generation Trading, i.e., purchase of electricity for resale, is a separate licensed activity, except for distribution licensees who do not require a separate trading license. Traders can enter into direct contracts with the consumers and determine its terms and conditions (including tariff). The Appropriate Commission may specify The entry barriers for traders – technical requirements, capital adequacy requirement, and credit-worthiness; Duties re. supply and trading in electricity to be discharged by a trader; and Fix trading margin in intra-state trading if considered necessary. ERCs have to develop trading market and have to be guided by National Tariff Policy.

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Open Access Open access means non-discriminatory use of transmission lines, distribution system and associated facilities by any licensee/consumer/Genco in accordance with ERC regulations. The licensees, consumers and Gencos have to pay transmission/wheeling charges for open access. Consumers has to also pay a surcharge (to be utilized to meet cross subsidy) determined by ERC, for open access. ERC may order any licensee owning intervening transmission facilities to provide use of facilities to any other licensee, to the extent of surplus capacity. A State Transmission Utility is obliged to provide non-discriminatory open access to its transmission system for use by a licensee or Genco forthwith, or by any consumer once distribution level open access has been provided. There is no statutory time limit for introduction of open access. ERC has to determine by June 10, 2004 the phases and conditions, subject to which open access would be introduced.

Distribution The distribution licensee has a mandatory duty to supply on request of consumer in a time bound manner if the consumer agrees to pay the applicable tariff. ERC is empowered to suspend or revoke license of a Discom for failure to maintain Uninterrupted supply. Distribution licensee is empowered to recover charges/expenses/security and disconnect supply for non-payment of dues. Discoms can enter into direct contracts with consumers. Discoms can engage in other businesses but have to share revenue to reduce wheeling charges, and maintains separate accounts for the same. ERCs may grant more than one distribution licenses can be issued in a given area, permitting them to supply electricity through their own distribution system. To get a subsequent distribution license any person will have to comply with additional requirements prescribed by GoI regarding capital adequacy, creditworthiness, or Code of Conduct etc. If an applicant meets such requirements, he shall not be denied grant of the license.

~ 43 ~

ERCs may permit by regulations a consumer/class to receive supply of electricity from anyone other than the distribution licensee of the area of supply – against payment of wheeling charge & surcharge in lieu of cross subsidy. Distribution licensee is free to undertake distribution for a specified area within his area of supply without need for a separate license. Provided that the distribution licensee shall remain liable for the supply.

Transmission To secure non-discriminatory open access, transmission has been segregated as a wires function without any trading (buying and selling). Central transmission utility (CTU) and all State transmission utilities (STUs) are deemed licensee. CTU and STUs functions are (i) Transmission; (ii) planning & co-ordination of transmission system; (iii) development of efficient and economical transmission lines from generating stations to load centers; (iv) providing non-discriminatory open access to the system. RLDCs and SLDCs are empowered to issue directions, and exercise supervision & control to ensure stability, efficiency & economy of grid operation in the region and the State respectively. Licensees, generating companies and other persons connected with operation of power system shall comply. SLDC shall ensure compliance with RLDC directions. Pending creation of separate RLDCs & SLDCs, the CTU and the STU shall perform the role.

Tariff Government has been distanced from determination of tariff. This power has been vested in the CERC/SERC. In determination of tariff CERC/SERC shall be guided by factors including National Electricity Policy, tariff policy (formulated by Central Government), CERC‘s principles and methodologies for setting tariff and principles rewarding efficiency and multiyear tariff. In case tariff is determined through transparent bidding as per Government of India guidelines, the same shall be adopted by the ERCs. To promote competition among distribution licensees, where there are 2 or more distribution licensees supplying in an area, the ERC may fix only maximum ceiling of tariff for retail sale. The PPAs/BSAs entered into before 10th June, 2003 have not been explicitly saved or granted a protection from regulatory intervention.

~ 44 ~

Regulatory Commission It is mandatory to establish SERCs within 6 months from 10th June, 2003. Joint Commission can be constituted for two or more States or Union territories or both by mutual agreement. The new functions to be performed by CERC/ SERC include specifying Grid Code, Supply Code (only SERC), levy fees, fix trading margins in interstate trading. In exercise of their functions, ERCs shall be guided by – National Electricity Policy, National Electricity Plan & Tariff Policy; directions of GoI/State Government concerned, in matters of policy involving public interest – where such Government‘s decision shall be final as to whether the directions relates to a policy involving public interest. There is no express provision enabling ERCs to depart from such directions. Provision for separate ERC funds (not consolidated funds) for finance of ERC expenditures.

Policy Issues Central Government shall prepare, publish and revise National Electricity Policy and Tariff policy in consultation with State Governments and CEA9. The implementation of the Act is largely dependent on the nature and scope of the diverse policy instruments to be issued by Government, and institutions like Special Courts, Appellate Electricity Tribunal, NLDC, RLDC, SLDC, SERCs and SEB successors to be constituted by Government‘s. It is noteworthy that these instruments will have a bearing are:

Role and functioning of ERCs,



Role and functioning of CEA,



Market development,



Governance of the sector – regulation, grid operations, safety issues, and



Enforcement.

Mega Power Policy Eligibility: Inter-state projects of 700 MW (thermal) and 350 MW (hydro) for Jammu & Kashmir and North Eastern states; 1,000 MW (thermal) and 500 MW (hydro) for others. • Exemption from custom duties, excise & central levies.

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• Increased ECB capital limits. • State Implementation support. • Decreased import duty on fuel i.e. coal & liquid fuel • Deemed export benefits to domestic bidders • Price preference to PSU bidders • Preconditions: Purchasing state must have ERC; Must agree in principle to privatize distribution in cities of >10 million population

Ultra Mega Power Projects • Nine sites identified; each project size about 4,000 MW; Total estimated investment of Rs 160 billion. • Projects to be completed on built-own-operate (BOO) basis. • Successful bidder finalized on tariff based competitive bidding; takes over SPV from PFC. • PFC is the nodal agency for setting up the special purpose vehicle (SPV) for project (100 per cent subsidiary) • Projects to use supercritical technology based on pithead (captive block) or imported coal (coastal). • Full exemption of central excise duty on goods procured under supercritical technology. • Five coastal sites identified including Mundra in Gujarat awarded to Tata Power.

Consumer Interests Creation of a Consumer redressal forum (CRF) by Distribution licensee in a time bound manner. The consumers aggrieved from CRF can approach to an ‗ombudsman‘10. Distribution licensee has to supply electricity within 1 month from the date of request for supply, except where capital works are required for connectivity. Failure of distribution licensee to supply within said time period would attract penalty.

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Enforcements Suitable provisions for provisional assessments and recovery of compensatory fines may be able to address a long-standing vacuum in law. Special Courts are to be established by Government‘s for speedy disposal of cases relating to theft of electricity. The scope of offences has been expanded and enhanced punishments have been prescribed for subsequent or continuing offences. Stronger powers (accompanied with better safeguards) have been provided for conducting inspections/search/seizure.

Dispute Resolution The appeal against all orders of ERC/adjudication officer would lie to an expert Appellate Tribunal (an expert body), which shall dispose appeals within prescribed time. Appeal from appellate tribunal lies to Supreme Court. The appeal to Supreme Court is limited to substantial question of law.

Electricity (Amendment) Act, 2007. The Electricity (Amendment) Act, 2007, amending certain provisions of the Electricity Act, 2003, has been enacted on 29th May, 2007 and brought into force w.e.f. 15.06.2007. The main features of the amendment Act are:  Central Government, jointly with State Governments, to endeavor to provide access to electricity to all areas including villages and hamlets through rural electricity infrastructure and electrification of households.  No License required for sale from captive units.  Deletions of the provisions for elimination of cross subsidies. The provisions for reduction of cross subsidies would continue.  Definition of theft expanded to cover use of tampered meters and use for unauthorized purpose. Theft made explicitly cognizable and non-bail able.

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Demand Side Management Demand-side management is used to describe the actions of a utility, beyond the customer's meter, with the objective of altering the end-use of electricity - whether it be to increase demand, decrease it, shift it between high and low peak periods, or manage it when there are intermittent load demands - in the overall interests of reducing utility costs. In other words DSM is the implementation of those measures that help the customers to use electricity more efficiency and it doing so reduce the customers to use the utility costs. DSM can be achieved through. 

Improving the efficiency of various end-uses through better housekeeping correcting

energy leakages, system conversion losses, etc ; 

Developing and promoting energy efficient technologies, and



Demand management through adopting soft options like higher prices during peak hours,

concessional rates during off-peak hours seasonal tariffs, interruptible tariffs, etc. DSM, in a wider definition, also includes options such as renewable energy systems, combined heat and power systems, independent power purchase, etc, that utility to meet the customer's

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demand at the lowest possible cost. Often the terms energy efficiency and DSM are used interchangeably. However, it is important to point out that DSM explicitly refers to all those activities that involve deliberate intervention by the utility in the marketplace so as to alter the consumer's load profile. Energy efficiency issued in an all encompassing sense and includes any activity that would directly or indirectly lead to an increase in energy efficiency. To make this distinction precise, a program that encourages customers to install energy efficient lighting systems through a rebate program would fall under DSM. On the other hand, customer purchases of energy efficient lighting as a reaction to the perceived need for conservation is not DSM but energy efficiency gains. There has been growing recognition of the importance of energy efficiency in India's electricity sectors. The Ministry of Power (MoP) is the nodal agency for energy conservation in the country. The Bureau of Energy Efficiency (BEE), an autonomous body under the MoP, was set up in 1989 to coordinate initiatives and activities on energy conservation. Several state electricity boards (SEBs) have also set up Energy Conservation Cells, some of which have been assisting industries in conducting energy audits. Several reports have been attempted to estimate the potential for energy conservation in various consuming sectors and have also identified various Energy Efficiency technologies (EETs) for important end-uses. The National Energy Efficiency Program (NEEP) of the Government of India (GOI) has targeted savings of about 5000 MW to be realized by the end of the Eighth plan through both demand (2750 MW) and supply side (2250 MW) efficiency improvements. In terms of Government policies, there are special equipment in the first year, subsidies for energy audits, reduced customs duty for selected control equipment for managing energy use, and so on.

Environmental Reform in the Electricity Sector: Enhanced economic activity and population growth have led to increasing energy demand that in turn has spurred electricity generation. But large-scale electricity generation and distribution have adverse environmental impacts, varying by the technologies employed and their locations. These need to be addressed so that energy services can be enhanced in harmony with the environment, within our ecological footprints. Due to the ―externalities‖ of electricity generation, that is, the negative impacts not directly affecting or being restricted to those involved, the costs

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of impact mitigation are typically not included in electricity prices. Consideration for the environment has therefore to be forced into the reckoning, or preferably integrated into the system, hence the importance of environment policy in the context of the power sector. Focusing on environmental issues and policies applicable to the power sector in China and India. These countries generate 68% of the electricity generated in developing Asia, but with a total population of about 2.4 billion, have large unmet needs. In approaching the problem of environmental protection in the power sector in rapidly developing country, our analytical framework consists of identification of those state environmental policies and regulations that pertain to the power sector, both directly and indirectly, assessment of the barriers encountered, and finally recommendations of likely solutions to circumvent these problems. Let us consider the impacts of electricity generation on the environment. The focus is on to list the national environmental policies that affect these impacts, beginning with general direction, proceeding to specific rules and standards and then to alternatives to conventional electricity generation. This leads to the problems that beset effective policy implementation.

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STUDY OF SELECTED COMPANIES To study and analyze the power sector better, the comparative and analytical study of the firms of power sector in India is done. The firms are chosen based on their sales turnover. The below are the firms selected by us for the study,    

NTPC Energy Develop Tata Power Power Grid

   

Torrent Power JP Hydro Reliance Infra KSK Energy

 GVK Power  Indowind Energy

The study of few selected major companies is as follows:

1. NTPC Ltd. NTPC Limited is the largest power generating and Navratna status company of India; it was incorporated in the year 1975 as National Thermal Power Corporation Private Limited to accelerate power development in the country. As a wholly owned company of the Government of India, NTPC has emerged as a truly national power company, with power generating facilities in all the major regions of the country. NTPC's core business is engineering, construction and operation of power generating plants. NTPC as an integrated Power Major with presence in Hydro Power, Coal mining, Oil & Gas exploration, Power Distribution & Trading and also enter into Nuclear Power Development. It provides consultancy also in the area of power plant constructions and power generation to companies in India and abroad. It is providing power at the cheapest average tariff in the country. With its experience and expertise in the power sector, also NTPC is extending consultancy services to various organizations in the power business. The consulting Wing of NTPC is an ISO 9001:2000 accreditation. In the year of 1982, the company commissioned the first Singrauli unit. Developing and operating world-class power stations is NTPC's core competence. Its scale of operation, financial strength and large experience serve to provide an advantage over competitors. To meet the objective of making available reliable and quality power at competitive prices, NTPC would continue to speedily implement projects and introduce state-of-art technologies.

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Growth of NTPC

NTPC PERFORMANCE

2. RELIANCE INFRASTRUCTURE LTD Reliance Energy Limited (REL), with its corporate lineage going back to 1929. At the time of incorporation REL was called as Bombay Suburban Electric Supply Limited (BSES). The company has been in the field of power distribution for nearly eight decades and with its emphasis on continuous improvements. REL is a fully integrated utility engaged in the generation, transmission and distribution of electricity. It ranks among India's top listed private companies on all major financial parameters, including assets, sales, profits and market capitalization. REL (BSES) has several group companies - ST-BSES Coal Washery (Joint

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Venture), BSES Infrastructure Finance, Utility Powertech (Joint Venture), Ticapco, BSES Telecom, BSES Kerala Power, BSES Andhra Power and three new companies of Orissa. The company has a strategy of adding value by strategic alliances within the group.

3. TATA POWER COMPANY LTD Tata Power Company Limited (TPC), India's largest integrated Electric Power Utility in private sector with a reputation for reliability, incorporated in the year 1919 at Mumbai. TPC pioneered the generation of electricity in India nine decades ago. The core business of Tata Power Company is to generate, transmit and distribute electricity. The Company operates in two business segments: Power and Other. The Power segment is engaged in generation, transmission and distribution of electricity. The other segment deals with electronic equipment, project consultancy.

4. POWER GRID CORPORATION OF INDIA LTD The Company was incorporated in October 23rd of the year 1989 as the National Power Transmission Corporation Limited with the responsibility of planning, executing, owning, operating and maintaining the high voltage transmission systems in the country. Subsequently, the company name was changed to the present name Power Grid Corporation of India Limited (PGCIL) with effect from October 23rd of the year 1992. The company's operational area includes Development of Inter-State transmission Systems and Grid Management. Development of Inter-State transmission Systems consists of Planning & Design, Construction, Quality Assurance & Inspection and Operation & Maintenance. Grid Management includes Establishment of modern Load Despatch Centers, Real-time Grid Operation, Optimum scheduling & dispatch and Energy accounting including settlements. The Diversification consists of Broadband Telecom Services, Sub-transmission, Distribution and Rural Electrification. The company has certified as PAS 99:2006, which integrates the requirements of ISO 9001:2000 for quality, ISO 14001:2004 for environment management and OHSAS 18000:1999 for health and safety management systems.

5. JP HYDROPOWER The Company was incorporated on December 21, 1994 with the object, interalia, to set up hydroelectric or Thermal power projects and for the supply of general electric power. The Certificate of Commencement of Business was granted on January 9, 1995. Our registered office is in New Delhi. Jaiprakash Hydro-Power Limited (JHPL), a part of the Jaypee Group owns and operates the 300 MW Baspa-II Hydroelectric Project at District Kinnaur in Himachal Pradesh. JPVL plan to implement a 2400MW hydroelectric project (the Lower Siang project), expected to commence operations in 2014 and a 500 MW hydroelectric project (the Hirong project), expected to commence operations in 2015, in the state of Arunachal Pradesh (collectively the Arunachal projects). These projects were initially awarded to JAL and were transferred to us

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through a tripartite agreement dated December 13, 2007. The memoranda of agreement for these projects provide for the Government of Arunachal Pradesh to own 11% of the equity capital in the special purpose vehicle that are to be incorporated to implement each of these projects. JPVL proposes to subscribe 55.36% of the equity capital of Jaypee Karcham Hydro Corporation Limited (JKHCL), which is implementing a 1000 MW ( 4*250 MW units) run-of-the-river hydroelectric power projects on the river Sutlej, in Kinnaur district of the state of Himachal Pradesh , expected to commence operations in 2011 (the Karcham –Wangtoo project).

MAJOR FINDINGS:  Most of the SEBs though are supported by state government, are running under loss. This is because of power theft, transmission losses, use of conventional methods for power generation and transmission and out dated management policies.  Indian power sector has been witnessing a wide demand – supply gap. Although electricity generation has increased substantially, it has not been able to meet the demand.  India is going to build an additional capacity of 1 lakh MW by 2012 including private sector contribution.  In a bid to bring structural transformations, necessary reform programs should be carried out in distribution and transmission process. India possesses a vast opportunity to grow in the field of power generation, transmission, and distribution. The target of over 150,000 MW of hydel power germination is yet to be achieved. By the year 2012, India requires an additional 100,000 MW of generation capacity. A huge capital investment is required to meet this target. This has welcomed numerous power generation, transmission, and distribution companies across the globe to establish their operations in the country under the famous PPP (public-private partnership) programmes. The power sector is still experiencing a large demand-supply gap. This has called for an effective consideration of some of strategic initiatives. There are strong opportunities in transmission network ventures - additional 60,000 circuit kilometers of transmission network is expected by 2012 with a total investment opportunity of about US$ 200 billion.

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IMPACT OF CERC REGULATIONS ON CENTRAL PLAYERS The impact analysis of CERC regulations is described below for different modes of operation

Generation CERC regulations in this area are: Return on equity to be higher at 15.5 per cent Impact: Positive The return on equity would increase from 14.0 per cent to 15.5 per cent for existing plants from 2009-10 onwards. In case of projects commissioned on or after April 1, 2009, an additional return of 0.5 per cent shall be allowed if such projects are completed within the time specified. This is expected s to be a positive for the players in the central sector as from 2009-10 onwards these players would start earning a higher return on equity –15.5 per cent post tax (from the previous 14 per cent) –on the existing capacities. This when added with the tax at normal rate is expected to give a pre-tax rate of 23.5 per cent [tax at Minimum Alternative Tax (MAT)] rate would earn a pre-tax rate of 17.5 per cent). The completion of new projects within the stipulated time would result in an incremental benefit of 0.5 per cent (coal-based 500 MW green-field plants need to be commissioned within 44 months to achieve the extra 0.5 per cent return on equity), thus new projects stand to gain a return on equity of 16 per cent. 1. Depreciation rate increased to 5.28 per cent, AAD done away with Impact: Neutral The Central Electricity Regulatory Commission (CERC) has done away with the advance against depreciation (AAD) norm stated in the CERC Regulation Policy 2004-09 and has increased the depreciation rate to 5.28 per cent for a period of 12 years. CRISIL Research expects this norm to have a neutral impact. Earlier AAD was provided in the CERC Regulation 2004-09 in order to balance the mismatch between tenure of loans (to be paid in 10 years) and asset life (spread over 25 years). The new CERC regulation however discontinues the benefit of AAD. In order to compensate for the

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same, depreciation rates have been increased to 5.28 per cent for a period of 12 years and the balance depreciation is spread equally over the life of the asset. 2.

Long term loans Impact: Positive The generation company or the transmission licensee, as the case may be, shall make every effort to re-finance the loan as long as it results in net savings on interest and in that event the costs associated with such re-financing shall be borne by the beneficiaries. Also, the net savings shall be shared between the beneficiaries and the generation company or the transmission licensee, as the case may be, in the ratio of 2:1. This is expected to be a positive for players. In the past, net savings from any restructuring activity had to be completely passed on to the beneficiaries. However, as per the new regulation, the generation company would be allowed to retain one-third of the net savings.

3. Operation and maintenance (O&M) expenses Impact: Neutral As per the revised norm (for a 500 MW coal-based power plant) the incremental O&M expense is increased to 5.72 per cent annually, from the earlier 4 per cent. The O&M expense increased from Rs 9.3 lakh/MW in 2004-05 to Rs 10.5 lakh/MW in 2008-09 and will now rise from Rs 13 lakh/MW in 2009-10 to Rs 16.2 lakh/MW in 2013-14. An incremental compensation has been permitted after the completion of 10 years, 15 years and 20 years of the useful life of the plant, which translates into Rs 0.15 lakh / MW – 0.65 lakh / MW. This move is positive but the impact is neutral for players as the O&M expense forms a small proportion of the total costs.

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4. Working capital norms Impact: Neutral CERC has proposed that henceforth maintenance spares would be calculated at 20 per cent of the O&M expenses as compared to the previous norm of calculating at 1 per cent of the historical costs. 5. Gross station heat-rate Impact: Negative CERC norms have tightened the gross station heat-rate. Typically a 500 MW coalbased power plant had a normative station heat rate of 2,450 kcal/kwh as per the old norms; this has been changed to 2,425 kcal/kwh with the new regulations. We expect this norm to have a negative impact as the tightening of the gross station heat rate norms would result in efficient players retaining lower savings/earnings. 6. Incentives Impact: Positive The new CERC regulation states that the incentive would be based on Plant Availability Factor (PAF) rather than the Plant Load Factor (PLF), which was the criterion under the previous regulation. CRISIL Research expects this to be a positive. In the past, players have suffered due to inadequate fuel supply leading to low PLFs. Calculation, now based on PAF will provide adequate incentive to players. The incentive calculation for plants with less than 10 years of commercial operation would be calculated as follows: Annual fixed charges * (30/365) * (0.5 * 0.5 Actual monthly PAF/ Normative PAF) For plants above 10 years of commercial operation, the calculation would be as follows: Annual fixed charges * (30/365) * (Actual monthly PAF/ Normative PAF)

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Transmission The CERC regulations for the transmission segment are broadly similar to the generation segment. However, the following are the cases which differ from generation segment: Operation and maintenance (O&M) expenses In the CERC Regulation 2004-09, the O&M expenses were at Rs 0.23 lakh / km and around Rs 28.12 lakh/ bay for the overall lines and sub-stations, respectively. However, the O&M expenses as per CERC Regulation 2009-14 have segregated the line costs in single, double circuit etc and sub-station costs by bay division viz, 765 kV, 400 KV etc. The norm for AC and HVDC lines in case of a single circuit would increase from Rs 0.5 lakh/ km to Rs 0.67 lakh/ km and for a sub-station (220Kv) from Rs 36.68 lakh/bay to Rs 45.82/bay. Working capital norms Henceforth, maintenance spares would be calculated at 15 per cent of the O&M expenses as compared to the previous norm where it was calculated at 1 per cent of the historical costs.

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IMPACT OF CERC REGULATIONS ON TARIFF AND END CUSTOMERS As per CRISIL Research there is expected to be a 5-8 per cent increase in tariff rate

The benefit from the increase of return on equity (14.0 per cent to 15.5 per cent) has not been completely off-set by the tightening of other norms and hence we expect an increment of 5-8 per cent in the tariff rates, based on the assumptions below: Assumptions Old 500

Plant size (MW) Gross station heat rate

2,450

Secondary fuel oil consumption (ml/kwh)

2

New 500 2,425

1 O&M expenses (lakh/MW) 9-10 13-16 Cost of fuel (Coal at linkage cost) Rs 1,790 Rs 1,790 Source: CERC regulations and CRISIL Research

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ADVANCED METERING INFRASTRUCTURE WHAT IS AMI? AMI is not a single technology implementation, but rather a fully configured infrastructure that must be integrated into existing and new utility processes and applications. This infrastructure includes home network systems, including communicating thermostats and other in-home controls, smart meters, communication networks from the meters to local data concentrators, back-haul communications networks to corporate data centers, meter data management systems (MDMS) and, finally, data integration into existing and new software application platforms. Additionally, AMI provides a very ―intelligent‖ step toward modernizing the entire power system. At the consumer level, smart meters communicate consumption data to both the user and the service provider. Smart meters communicate with in home displays to make consumers more aware of their energy usage. Going further, electric pricing information supplied by the service provider enables load control devices like smart thermostats to modulate electric demand, based on pre-established consumer price preferences. More advanced customers deploy distributed energy resources (DER) based on these economic signals. And consumer portals process the AMI data in ways that enable more intelligent energy consumption decisions, even providing interactive services like prepayment.

The service provider (utility) employs existing, enhanced or new back office systems that collect and analyze AMI data to help optimize operations, economics and consumer service. For example, AMI provides immediate feedback on consumer outages and power quality, enabling the service provider to rapidly address grid deficiencies. And AMI‘s bidirectional communications infrastructure also supports grid automation at the station and circuit level. The vast amount of new data flowing from AMI allows improved management of utility assets as

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well as better planning of asset maintenance, additions and replacements. The resulting more efficient and reliable grid is one of AMI‘s many benefits.

WHAT ARE THE TECHNOLOGY OPTIONS FOR AMI? An AMI system is comprised of a number of technologies and applications that have been integrated to perform as one: • Smart meters • Wide-area communications infrastructure • Home (local) area networks (HANs) • Meter Data Management Systems (MDMS) • Operational Gateways

SMART METERS Conventional electromechanical meters served as the utility cash register for most of its history. At the residential level, these meters simply recorded the total energy consumed over a period of time – typically a month. Smart meters are solid state programmable devices that perform many more functions, including most or all of the following: • Time-based pricing • Consumption data for consumer and utility • Net metering • Loss of power (and restoration) notification • Remote turns on / turns off operations • Load limiting for ―bad pay‖ or demand response purposes • Energy prepayment • Power quality monitoring • Tamper and energy theft detection • Communications with other intelligent devices in the home And a smart meter is a green meter because it enables the demand response that can lead to emissions and carbon reductions. It facilitates greater energy efficiency since information feedback alone has been shown to cause consumers to reduce usage.

COMMUNICATIONS INFRASTRUCTURE

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The AMI communications infrastructure supports continuous interaction between the utility, the consumer and the controllable electrical load. It must employ open bi-directional communication standards, yet be highly secure. It has the potential to also serve as the foundation for a multitude of modern grid functions beyond AMI. Various architectures can be employed, with one of the most common being local concentrators that collect data from groups of meters and transmit that data to a central server via a backhaul channel. Various media can be considered to provide part or all of this architecture: • Power Line Carrier (PLC) • Broadband over power lines (BPL) • Copper or optical fiber • Wireless (Radio frequency), either centralized or a distributed mesh • Internet • Combinations of the above Future inclusion of smart grid applications and potential consumer services should be considered when determining communication bandwidth requirements.

HOME AREA NETWORKS (HAN) A HAN interfaces with a consumer portal to link smart meters to controllable electrical devices. Its energy management functions may include: • In-home displays so the consumer always knows what energy is being used and what it is costing • Responsiveness to price signals based on consumer-entered preferences • Set points that limit utility or local control actions to a consumer specified band • Control of loads without continuing consumer involvement • Consumer over-ride capability The HAN/consumer portal provides a smart interface to the market by acting as the consumer‘s ―agent.‖ It can also support new value added services such as security monitoring. A HAN may be implemented in a number of ways, with the consumer portal located in any of several possible devices including the meter itself, the neighborhood collector, a stand-alone utility-supplied gateway or even within customer-supplied equipment.

METER DATA MANAGEMENT SYSTEM (MDMS)

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A MDMS is a database with analytical tools that enable interaction with other information systems (see Operational Gateways below) such as the following: • Consumer Information System (CIS), billing systems, and the utility web site • Outage Management System (OMS) • Enterprise Resource Planning (ERP) power quality management and load forecasting systems • Mobile Workforce Management (MWM) • Geographic Information System (GIS) • Transformer Load Management (TLM) One of the primary functions of an MDMS is to perform validation, editing and estimation (VEE) on the AMI data to ensure that despite disruptions in the communications network or at customer premises, the data flowing to the systems described above is complete and accurate.

OPERATIONAL GATEWAYS AMI interfaces with many system-side applications (see MDMS above) to support Advanced Distribution Operations (ADO), Advanced Transmission Operations (ATO) and Advanced Asset Management (AAM).

WHAT ARE SOME DEPLOYMENT APPROACHES? Deployment approaches will depend upon the utility’s starting point, geography, regulatory situation and long-term vision. For those utilities that already have deployed an AMR system, the question will be whether they can build on that system or need to start afresh. If the system includes a two-way communications infrastructure, it should be possible to upgrade the metering to accommodate a range of AMI applications. Where the communications infrastructure is unidirectional (i.e. outgoing only), it may be possible to overlay a return channel using a complementary technology. This option would have to be compared to the cost and benefits of installing a new integrated two-way communications infrastructure. The speed, reliability and security of the communications infrastructure will determine the range of applications it can support. For utilities with widespread and diverse territories, it may be that multiple communications solutions will be needed. Pilot programs that explore the performance of various solutions can be useful as the first phase of an AMI deployment.

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The choice of an AMI communications infrastructure is also influenced by the utility’s long-term vision for AMI. If AMI is seen as the foundation for overall grid modernization, the communications system will need to accommodate anticipated future needs and have the flexibility to handle applications that are not even currently on the utility‘s radar screen. Experience has shown that these evolving grid modernization applications often produce major benefits.

The deployment of AMI is a strategic initiative that must be endorsed by the utility regulator. The benefits of AMI, and ultimately of overall grid modernization, flow to not just the utility, but also to the consumer and society in general. Hence regulators need to consider the possibility that traditional utility economic analysis may not capture the true value of an AMI strategic initiative and that an expanded framework may be more appropriate, as discussed later in this document. Some regulators may see AMI and grid modernization as very desirable and they will encourage their utilities to move aggressively. Others may be less proactive and will expect their utilities to broach AMI and bring with them a compelling argument on its merits. In either case, recognition of the wide-ranging societal benefits of AMI must be addressed.

Together, the utility and its regulators should communicate the full benefits of an AMI initiative to consumers and society at large. There is a general lack of understanding among the public regarding how electricity is produced and delivered, how it affects their quality of life and how it can meet their needs in the 21st century. In particular, the value of consumers‘ increased involvement in electricity markets, and the potential benefits for consumers involved in such programs needs to be explained.

WHAT ARE THE BENEFITS OF AMI? AMI provides benefits to consumers, utilities and society as a whole.

CONSUMER BENEFITS For the consumer, this means more choices about price and service, less intrusion and more information with which to manage consumption, cost and other decisions. It also means higher reliability, better power quality, and more prompt, more accurate billing. In addition, AMI will

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help keep down utility costs, and therefore electricity prices. And, as members of society, consumers also reap all the benefits that accrue to society in general, as described below.

UTILITY BENEFITS Utility benefits fall into two major categories, billing and operations. AMI helps the utility avoid estimated readings, provide accurate and timely bills, operate more efficiently and reliably, and offer significantly better consumer service. AMI eliminates the vehicle, training, health insurance, and other overhead expenses of manual meter reading, while the shorter read-to-pay time advances the utility‘s cash flow, creating a one-time benefit. And consumer concerns about meter readers on their premises are eliminated. Operationally, with AMI the utility knows immediately when and where an outage occurs so it can dispatch repair crews in a more timely and efficient way. Meter-level outage and restoration information accelerates the outage restoration process, which includes notifying consumers about when power is likely to return. Using AMI, the utility can receive significant benefits from being able to manage customer accounts more promptly and efficiently, starting with the ability to remotely connect and disconnect service without having to send personnel to the customer site. Similarly, many maintenance and customer service issues can be resolved more quickly and cost-effectively through the use of remote diagnostics. And AMI enables new programs and methods for creating and recovering revenue such as distributed generation and prepayment programs. AMI also provides vast amounts of energy usage and grid status information that can be used by consumers to make more informed consumption decisions and by utilities to make better decisions about system improvements and service offerings. Instead of relying on rough estimates, engineers armed with AMI‘s detailed knowledge of distribution loads and electrical quality can accurately size equipment and protection devices, and better understand distribution system behavior. This huge increase in valuable information helps the utility: • Assess equipment health • Maximize asset utilization and life • Optimize maintenance, capital and O&M spending • Pinpoint grid problems • Improve grid planning • Locate/ identify power quality issues • Detect/reduce energy theft

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SOCIETAL BENEFITS Society, in general, benefits from AMI in many ways. One way is through improved efficiency in energy delivery and use, producing a favorable environmental impact. It can accelerate the use of distributed generation, which can in turn encourage the use of green energy sources. And it is likely that emissions trading will be enabled by AMI‘s detailed measurement and recording capabilities. A major benefit of AMI is its facilitation of demand response and innovative energy tariffs. During periods of high energy demand, a small reduction in demand produces a relatively large reduction in the market price of electricity. And reduced demand can avoid rolling blackouts. According to Edison Electric Institute (EEI), the direct costs (e.g. power costs) of rolling blackouts in California have been estimated at tens of millions of dollars. Business and consumer losses may be many times higher. Hence, a modest demand response capability could produce a societal benefit worth billions of dollars. The benefits accrued may vary depending on the type of demand response programs initiated. For instance, demand response distributed to the individual premise in forms like thermostat and pool pump control allows load to be reduced without sacrificing consumer satisfaction. However, even just shifting demand away from peak hours through time-of-use tariffs can have major benefits, including the reduced cost to both utilities and consumers by deferring building new, expensive peak generation facilities. There is also a societal fairness issue that AMI addresses. Full deployment of AMI results in the elimination of old and obsolete electromechanical meters that tend to slow down as they age. Modern AMI meters maintain their accuracy over time, resulting in a more equitable situation for all consumers. In addition, modern meters are self monitoring, making it easier to identify inaccurate measurements, incorrect installations and, especially, electric energy theft. As reported by Edison Electric Institute (EEI), price and demand reductions during high-demand periods lead to: Reduced peak capacity requirements congestion costs T&D costs electrical losses generation costs market influence by any one supplier

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Improved electric system efficiency (lower operating costs) electric system reliability (lower maintenance costs) settlement data management

WHAT BARRIERS IMPACT SUCCESSFUL DEPLOYMENT OF AMI? The transition to AMI and ultimately to a modern grid is not without obstacles. •

Business Case Limitations: Limiting the assessment of AMI benefits to just those associated with utility operations biases the business case against deployment. A more complete societal business case often produces a different conclusion. If one includes such items as the avoided societal costs and consequences of rolling and regional blackouts, AMI benefits can be many times the utility operating benefits. While some of these benefits accrue to constituents outside the utility, they are nonetheless direct consequences of AMI and should be addressed in the business case.

•

Depreciation Rules: The accounting treatment of the value of in-service meters is another important element in any AMI decision. In most cases it will be necessary to replace obsolete meters before they have been fully depreciated; creating a write-down (i.e. an expense that reduces utility earnings) that can affect regulated income.

•

Standards: While AMI technology is moving at a rapid pace, standards are needed to ensure interoperability among the many AMI offerings. Open standards are the best way to drive down the costs of AMI deployments and to give utilities the assurance that a large AMI investment will not become stranded if the selected vendor fails.

•

Rate Designs: Innovative rate designs that reflect actual market conditions are needed to complement the capabilities of AMI technology and realize the potential of demand response. Current ratemaking structures make it difficult to roll out new technologies. Utilities that install energy-saving systems can see their sales drop without any offsetting benefit

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•

Education: Consumer education is needed regarding the merits of AMI, DR and the societal benefits from grid modernization. Consumers also need to understand and demand a modern electric grid that will improve their overall quality of life and enhance US competitiveness in a global economy.

•

Technical Resources: Utility and vendor technical staffs have been cut back over the past decade. Rebuilding these staffs and attracting the needed technical talent is a barrier to the full realization of AMI‘s potential.

•

Regulatory Barriers: Overlapping federal, regional, state and municipal agencies create an impediment. The industry is neither fully regulated nor completely deregulated.

•

Financial Constraints: The grid is capital intensive and faces problems imposed by utilities‘ constrained balance sheets.

•

Technology Hurdles: It is a challenge to ―fix a moving train.‖ Utilities cannot turn off the power for a year or two while they install upgrades.

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RENEWABLE ENERGY Renewable energy is energy generated from natural resources — such as sunlight, wind, rain, tides, and geothermal heat —which are renewable (naturally replenished). In 2006, about 18% of global final energy consumption came from renewables, with 13% coming from traditional biomass, such as wood-burning. Hydroelectricity was the next largest renewable source, providing 3% of global energy consumption and 15% of global electricity generation.

Renewable Energy Scenario in India Conventional sources of energy such as coal and petroleum products have several drawbacks, especially with respect to the impact on the environment and the depletion of natural resources. However, significant technological improvements in the design and operation of coal-based power plants, aimed at lowering emissions, have led to higher capital costs. World fossil fuel reserves have been depleting rapidly. It has been estimated that at the current rate of production, natural gas reserves are expected to last for 31-34 years while coal reserves in India are expected to last for 118 years.

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Hence, the government has been focusing on exploiting non-conventional and renewable sources of power. At present, non-conventional sources of energy account for a negligible proportion of the total energy consumed in India. At the end of 2008-09, non-conventional energy sources, largely wind and co-generation power, accounted for around 9 per cent of the total capacity. India is blessed with an abundance of sunlight, water and biomass. Vigorous efforts during the past two decades are now bearing fruit as people in all walks of life are more aware of the benefits of renewable energy, especially decentralized energy where required in villages and in urban or semi-urban centers. India has the world‘s largest programme for renewable energy. Government created the Department of Non-conventional Energy Sources (DNES) in 1982. In 1992 a full fledged Ministry of Non-conventional Energy Sources was established under the overall charge of the Prime Minister. The range of its activities cover Promotion of renewable energy technologies Create an conducive environment to promote renewable energy technologies Create an conducive environment for their commercialization, Renewable energy resource assessment, research and development and its demonstration Production of biogas units, solar thermal devices, solar photovoltaic, wind energy and small hydropower units.

Co-Generation In some industries like chemicals, the manufacturing process generates considerable amounts of heat, which can be used to produce steam. This steam, in turn, can be used to run a turbine generator. In a co-generation plant the turbine runs on low-pressure steam, as compared with the high-pressure steam used in conventional thermal plants. The capital required to set up a co-generation plant is much lower, as compared with a coalbased plant, as the need for a boiler is eliminated (due to the availability of process steam). Typically, co-generation plants cost Rs 20-30 million per MW of capacity, while coal-based power plants cost Rs 40-50 million per MW of capacity. The main factors that determine the cost of a co-generation plant are the quantity and the quality of steam generated in the manufacturing process.

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In addition, as the cost of fuel is nil, the cost of the electricity generated through co-generation is marginal, as compared with the cost of purchased power. The surplus power (after meeting the requirement of the manufacturing process) can be sold to the grid.

Wind Power In India, wind power potential is largely concentrated in the coastal regions, and is estimated at around 48,500 MW. As on November 30, 2008, the installed capacity of wind power in India was around 9,587 MW. Tamil Nadu has the highest installed capacity of wind power at around 4,116 MW. The functioning of a wind power generation starts when the wind turbine converts the kinetic energy of wind into rotary motion, which can be used, either directly to run a machine (wind mills or wind pumps), or to run an electric generator, that is, a wind turbine generator (WTG). WTGs are available in capacities ranging from 250-750 kW. The velocity and density of wind and the size (diameter) of the rotor determine, at a particular site, the output of a WTG.

Solar power Electricity from solar energy can be generated by two methods - solar photo-voltaic (SPV) cells and solar thermal power. SPV devices generate power by directly converting light energy to electricity. SPV modules are composed of semi-conductor material (silicon) and when sunlight falls on them, it frees electrons, which produces electricity. SPV modules are made of several inter-connected solar cells, in order to provide power on a large scale. Modules can be further inter-connected to form solar arrays. In solar thermal power systems, heat energy from the sun is concentrated, using parabolic reflectors, to heat a fluid like water to a high temperature. The cost of generating solar power has been estimated at Rs 15 per kWh. The Centre and state governments have tied up to give incentives of Rs 12 per unit for generating power from solar energy. Cost of generation from conventional sources is Rs 2.5-3.5 per kWh. Generation of solar power is more expensive owing to the higher capital costs of solar power plants. A solar power plant of 1 MW could require an investment of up to Rs 200 million, compared to Rs 40 million for a conventional thermal power plant and Rs 60 million for hydro power plant.

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SPV Systems More than 700000 PV systems of capacity over 44MW for different applications are installed all over India. The market segment and usage is mainly for home lighting, street lighting, solar lanterns and water pumping for irrigation. Over 17 grid interactive solar photovoltaic generating more than 1400 KW are in operation in 8 states of India. As the demand for power grows exponentially and conventional fuel based power generating capacity grows arithmetically, SPV based power generation can be a source to meet the expected shortfall. Especially in rural, farflung where the likelihood of conventional electric lines is remote, SPV power generation is the best alternative.

Small hydroelectric plants Taking into account the problems associated with large hydel plants, small hydroelectric power plants (up to 25 MW) are considered to be economical and environment friendly. They are suitable for remote and inaccessible areas, as a decentralized source of power. Over 4,000 prospective sites, with a total potential of over 15,000 MW, have been identified to set up small hydel plants (up to 25 MW). The highest potential is found in Himachal Pradesh, Uttaranchal, Jammu and Kashmir and Arunachal Pradesh.

Biomass Power The Biomass power/cogeneration programme is implemented with the main objective of promoting technologies for optimum use of country‘s biomass resources for grid and off grid power generation. Biomass materials successfully used for power generation include bagasse, rice husk, straw, cotton stalk, coconut shells, soya husk, de-oiled cakes, coffee waste, jute wastes, and groundnut shells, saw dust etc. The technologies being promoted include combustion/ cogeneration and gasification either for power in captive or grid connected modes or for heat applications. Potential

The current availability of biomass in India is estimated at about 500 million metric tons per year. Studies sponsored by the Ministry has estimated surplus biomass availability at about 120 – 150 million metric tons per annum covering agricultural and forestry residues corresponding to a potential of about 16,000 MW. This apart, about 5,000 MW additional power could be generated through bagasse based cogeneration in the country‘s 550 Sugar mills, if these sugar

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mills were to adopt technically and economically optimal levels of cogeneration for extracting power from the bagasse produced by them.

Different Technologies Used

Combustion The thermo chemical processes for conversion of biomass to useful products involve combustion, gasification or pyrolysis. The most commonly used route is combustion. The advantage is that the technology used is similar to that of a thermal plant based on coal, except for the boiler. The cycle used is the conventional ranking cycle with biomass being burnt in high pressure boiler to generate steam and operating a turbine with generated steam. The net power cycle efficiencies that can be achieved are about 23-25%. The exhaust of the steam turbine can either be fully condensed to produce power, or used partly or fully for another useful heating activity. The latter mode is called cogeneration. In India, cogeneration route finds application mainly in industries. Gasification Instead of combustion, it is possible to convert the biomass into producer gas by gasification (partial combustion). Thermo-chemical gasification involves burning the biomass with insufficient air so that complete combustion doesn‘t occur, but a gaseous product is obtained. The producer gas is a mixture of carbon monoxide and hydrogen. Gasifiers are classified as updraft or downdraft depending on the direction of flow of the biomass and producer gas. India has significant experience in atmospheric gasifiers. Geothermal Power

Geothermal energy can be produced in two ways: by using the steam coming out of hot water springs or by pumping water into the hot earth crust and then using the resulting steam to generate power. The state is looking at the second option for generating power as the area has no hot springs. ―The geothermal power technology is a proven technology and effectively used in countries like Iceland, New Zealand, etc. At Rs 4.5-5 crore per mega watt, it is also cost-efficient, which is

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similar to the conventional thermal power plants The Maharashtra government has identified Jalgaon district as the country‘s first geothermal power hub. Analysis of geological data by experts at the Indian Institute of Technology, Bombay, indicated that there is a potential for geothermal power generation in the Jalgaon district, which is adjacent to Madhya Pradesh. According to preliminary estimates the area may have the potential of generating around 2,000 mega watts of power

Type

Potential

Small hydro Waste to energy Ocean thermal power Sea wave power Tidal power Wind energy Solar photovoltaic power Solar thermal power Bio-energy Co-generation

15000 5000 50000 20000 9000 48500 20 MW / sq km 35 MW/ sq km 52,000 16000

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NUCLEAR POWER IN INDIA India has a flourishing and largely indigenous nuclear power program and expects to have 20,000 MW nuclear capacity on line by 2020 and 63,000 MW by 2032. It aims to supply 25% of electricity from nuclear power by 2050. Because India is outside the Nuclear Non-Proliferation Treaty due to its weapons program, it has been for 34 years largely excluded from trade in nuclear plant or materials, which has hampered its development of civil nuclear energy until 2009. Due to these trade bans and lack of indigenous uranium, India has uniquely been developing a nuclear fuel cycle to exploit its reserves of thorium. Now, foreign technology and fuel are expected to boost India's nuclear power plans considerably. All plants will have high indigenous engineering content. India has a vision of becoming a world leader in nuclear technology due to its expertise in fast reactors and thorium fuel cycle.

Electricity demand in India has been increasing rapidly, and the 534 billion kilowatt hours produced in 2002 was almost double the 1990 output, though still represented only 505 kWh per capita for the year. In 2006, 744 billion kWh gross was produced, but with huge transmission losses this resulted in only 505 billion kWh consumption. The per capita figure is expected to almost triple by 2020, with 6.3% annual growth. Coal provides 68% of the electricity at present, but reserves are limited. Gas provides 8%, hydro 15%. Nuclear power supplied 15.8 billion kWh (2.5%) of India's electricity in 2007 from 3.7 GW (of 110 GW total) capacity and this will increase steadily as imported uranium becomes available and new plants come on line. India's fuel situation, with shortage of fossil fuels, is driving the nuclear investment for electricity, and 25% nuclear contribution is foreseen by 2050, from one hundred times the 2002 capacity. Almost as much investment in the grid system as in power plants is necessary. In 2006 almost US$ 9 billion was committed for power projects, including 9354 MW of new generating capacity, taking forward projects to 43.6 GW and US$ 51 billion. The target since about 2004 has been for nuclear power is to provide 20 GW by 2020. However, it is evident that on the basis of indigenous fuel supply only, the 20 GW target is not attainable, or at least not sustainable without uranium imports, which implies that even the 20 GW target

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will require uranium imports The Atomic Energy Commission however envisages some 500 GW on line by 2060. Nuclear Power industry development in India:

India's operating nuclear power reactors:

State

Tarpaper 1 & 2

Maharashtra BWR 150

1969

Kaiga 1 & 2

Karnataka

PHWR 202

1999-2000

Kaiga 3

Karnataka

PHWR 202

2007

Kakrapar 1 & 2

Gujarat

PHWR 202

1993-95

Tamil Nadu PHWR 202

1984-86

Kalpakkam 1 & 2 (MAPS)

Narora 1 & 2

Uttar Pradesh

Type

MW net, Commercial

Reactor

each

operation

PHWR 202

1991-92

Safeguards status

item-specific

by 2012 under new agreement

by 2014 under new agreement

Rawatbhata 1

Rajasthan

PHWR 90

1973

item-specific

Rawatbhata 2

Rajasthan

PHWR 187

1981

item-specific

Rawatbhata 3 & 4

Rajasthan

PHWR 202

1999-2000

Tarapur 3 & 4

Maharashtra PHWR 490

Total (17)

3779 MW

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2006, 05

by 2010 under new agreement

More recent reactor developments The new series of 540 MW (gross, 490 MW net) nuclear reactors are developed indigenously from the 220 MW (gross) model PHWR. The Tarapur 3&4 units were built by NPCIL. The first - Tarapur 4 - started up in March 2005, was connected to the grid in June and started commercial operation in September. Russia is supplying the country's first large nuclear power plant, comprising two VVER-1000 (V-392) reactors, under a Russian-financed US$ 3 billion contract. The AES-92 units at Kudankulam in Tamil Nadu state are being built by NPCIL and will be commissioned and operated by NPCIL under IAEA safeguards. Unlike other Atomstroyexport projects such as in Iran there has been only about 80 Russian supervisory staff on the job. Russia will supply all the enriched fuel, though India will reprocess it and keep the plutonium. The first unit was due to start supplying power in March 2008 and go into commercial operation late in 2008, but this schedule has slipped by about two years. The second unit is about 6-8 months behind it. Under plans for the India-specific safeguards to be administered by the IAEA in relation to the civil-military separation plan, eight further reactors will be safeguarded (beyond Tarapur 1&2, Rawatbhata 1&2, and Kudankulam 1&2): Rawatbhata 3&4 by 2010, Rawatbhata 5&6 by 2008, Kakrapar 1&2 by 2012 and Narora 1&2 by 2014. India's nuclear power reactors under construction: MW net, Project

Commercial

each

control

operation

PHWR

202 MW

NPCIL

12/2009

PHWR

202 MW

NPCIL

7/2009, 10/2009

950 MW

NPCIL

6/2010, 12/2010

item-specific

470 MW

Bhavini

2011

-

Reactor

Type

Kaiga 4 Rawatbhata &6

5

Kudankulam 1 PWR &2 Kalpakkam PFBR

(VVER)

FBR

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Safeguards status

by 2008 under new agreement

Reactor

Total (6)

Type

MW net, Project

Commercial

each

operation

control

Safeguards status

2976 MW

Rawatbhata also known as Rajasthan/RAPS; dates are for start of commercial operation.

Nuclear industry developments beyond the trade restrictions Following the Nuclear Suppliers' Group agreement which was achieved in September 2008, the scope for supply of both reactors and fuel from suppliers in other countries opened up. The Russian PWR types were apart from India's three-stage plan for nuclear power and were simply to increase generating capacity more rapidly. Now there are plans for eight 1000 MW units at the Kudankulam site, and in January 2007 a memorandum of understanding was signed for Russia to build four more there, as well as others elsewhere in India. The new units will be the larger 1200 MW AES-2006 versions of the first two. Between 2010 and 2020, further construction is expected to take total gross capacity to 21,180 MW. The nuclear capacity target is part of national energy policy. This planned increment includes those set out in the Table below including the initial 300 MW Advanced Heavy Water Reactor (AHWR). In 2005 four sites were approved for eight new reactors. Two of the sites - Kakrapar and Rawatbhata, would have 700 MW indigenous PHWR units, Kudankulam would have imported 1000 or 1200 MW light water reactors alongside the two being built there by Russia, and the fourth site was greenfield for two 1000 MW LWR units - Jaitapur (Jaithalpur) in the Ratnagiri district of Maharashtra state, on the west coast. The plan has since expanded to six 1600 MW EPR units here. NPCIL had exploratory meetings and technical discussions with three major reactor suppliers Areva of France, GE-Hitachi and Westinghouse Electric Corporation of the USA for supply of reactors for these projects and for new units at Kaiga. These resulted in more formal agreements with each reactor supplier early in 2009, as mentioned below.

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In April 2007 the government gave approval for the first four of these eight units (below), using indigenous technology, probably starting construction in 2009. In late 2008 NPCIL announced that as part of the Eleventh Five Year Plan (2007-12), it would start site work for 12 reactors including the rest of the eight PHWRs of 700 MW each, three or four fast breeder reactors and one 300 MW advanced heavy water reactor in 2009. NPCIL said that "India is now focusing on capacity addition through indigenization" with progressively higher local content for imported designs, up to 80%. Looking further ahead its augmentation plan included construction of 25-30 light water reactors of at least 1000 MW by 2030.

Non-proliferation, US-India agreement and Nuclear Suppliers' Group India's nuclear industry has been largely without IAEA safeguards, though four nuclear power plants have been under facility-specific arrangements related to India's INFCIRC/66 safeguards agreement with IAEA. India's situation as a nuclear-armed country excluded it from the Nuclear Non-Proliferation Treaty (NPT) so this and the related lack of full-scope IAEA safeguards meant that India was isolated from world trade by the Nuclear Suppliers' Group. A clean waiver to the trade embargo was agreed in September 2008 in recognition of the country's impeccable non-proliferation credentials. In July 2007 a nuclear cooperation agreement with India was finalized, opening the way for India's participation in international commerce in nuclear fuel and equipment and requiring India to put most of the country's nuclear power reactors under IAEA safeguards and close down the Cirus research reactor by 2010. It would allow India to reprocess US-origin and other foreign-sourced nuclear fuel at a new national plant under IAEA safeguards. This would be used for fuel arising from those 14 reactors designated as unambiguously civilian and under full IAEA safeguards. One of the important results of it will be bilateral trade agreement with USA, Russia and France.

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REFERENCES DATABASE: Capital line plus CEA Central Electricity Authority India Indiaenergyportal.org Ministry of Power

Yahoo.com

WEBSITES: www.Ibef.org www.india.gov.in www.teriin.org www.coreinternational.com www.energywatch.org.in www.hansuttam.com www.elsevier.com www.sciencedirect.com

SEARCH ENGINES Google.com Askjeeves.com Soople.com

www.crisilresearch.com

WEB PAGES: http://www.indexmundi.com/India/electricity_consumption.html http://www.indexmundi.com/India/electricity_production.html http://www.cea.nic.in http://www.topnews.in/business-news/power-sector.html http://www.energywatch.org.in http://www.bharatbook.com/Market-Research-Reports/Indian-power-sectordatabase.html http://www.marketresearch.com/product/display.asp?productid=1695991

ARTICLES & MAGAZINES http://recindia.nic.in/download/T_D_Overw.pdf www.wwf.org.uk/filelibrary/pdf/ipareport.pdf www.ibef.org/Attachment/Investment%20opportunities%20in%20Power%20Sector.pdf http://www.adb.org/Documents/Studies/Timor-Power-Sector-Dev/default.asp www.appanet.org/files/PDFs/RestructuringStudyKwoka1.pdf www.saneinetwork.net/pdf/SANEI_II/Reforms_and_PowerSector_in_SouthAsia.pdf www.ebrd.com/projects/eval/showcase/psr.pdf

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