Power Sector Reform

1. INTRODUCTION

Change is the lifeline of everything that is in existence in this universe.

Without change, all the things will loose their beauty gradually even if

they may be the most beautiful and flawless things of the world.

Electric energy occupies the top grade in the energy hierarchy. It finds

innumerable uses in home, industry, agriculture even in transport. The

per capita consumption of electricity in any country is an index of the

standard of living of the people in that country. In spite of a number of

uses of electricity & great efforts from all the Nations to increase its

production, it is a fact that almost one-third population of the world,

mainly developing/ undeveloped /undeveloped countries has no access

to electricity. Developing countries (mostly populous-nearly 80% global

population) have 6% to 7% annual rate of demand for electricity & in

future most of the world’s electricity is expected to be produced in

these countries. The main reason for lack of access to electricity as

well as energy shortages in developing countries is the capital

resource crunch.

Mostly developed countries as well as some developing countries are

restructuring their power sectors with more or less same objective &

achieved dramatically beneficial affects. In the Indian Electricity

Reforms, The accent is more on privatization than on introduction of

competition, which would not deliver improved results. The result

would be that public ownership will be replaced with private ownership,

but in terms of market structure, the monopoly feature will remain.

However, in the transition from the state to the market in power

sector, Government of India has given up both the virtues of central

planning & the flexibility of rigor of the market. As a result, search for

low cost power through hydel resources is not getting high priority.

Government of India has formulated a Common Minimum National

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Action Plan for power for overall economic development of the

country.

Today our country is certainly one of the fastest growing economies of

the world. Even through our economic transformation is overshadowed

by the neighboring dragon economy of china, Indian economy is

booming and we will say that we are definitely marching towards the

21st century. Many state run companies have been privatized since

the economy was opened up by the Narasimha Rao government. We

are face geopolitical and a social challenge our economy was still

continues to grow at a steady pace of around 8 percent. India's GDP

stands at a colossal 330 billion .there is a strong possibility that the

growth could slow down and if proper planning and more important

implementation is not done about investments in the power sector.

Electricity is an important basic infrastructural element, required for

industrial development. Inadequate supply of power will lead to idle

capacity, low production, and scarcity of essential goods, inflation, and

a steady decline in the future growth prospects of the Indian economy.

The benchmark is that the pace of modernization, setting up of new

and revival of sick unit and technological improvements depend on the

arability of power. Economy might grow but certainly, it cannot be

sustained without strengthening the power sector. Progress after all is

certainly not conceivable without power. The Indian situation can be

best described in one sentence as one of the most power starved

country brought to this situation by prodigally frittering away this

scarce national resource with steady decline of professionalism,

rampant corruption, and ever growing political interference. Despite

impressive growth in various sectors and the crucial importance of a

basic economic input such as electricity, nothing has been done to

introduce efficiency and accountability in this sector.

2. Pre-reform stage:

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The power sector in India has been regulated and owned for many years by various government agencies and organizations. The role and the participation of private industry in the Indian power sector has been limited and confined to specific areas of small jurisdiction and consumer base. The subject of electricity is covered under the concurrent list in the Constitution of India, implying that both the central and state governments have the power to legislate the sector. Confronted with unprecedented economic crisis in 1991, Government of India embarked upon a massive clean up exercise encompassing all policies having financial involvement of Governments- both at the level of Union and States.

Prior to Independence in 1947, most of the power was capacity was in the hands of licensees, private operators primarily focusing on urban areas. Some of these continue today, providing power to several major cities including Mumbai (Bombay), Ahmedabad, and Kolkata (Calcutta). These licensees operated under the aegis of the Indian Electricity Act of 1910, which was largely modeled on British rules. This act provided for non-discriminatory tariffs and a reasonable investment return for the Licensee.

Post Independence, the Electricity (Supply) Act of 1948 (modeled on the UK Electricity (Supply) Act of 1926 – (Choukroun 2001), provided for state-level utilities to be responsible for all new generation, transmission, and distribution, leading to the creation of the SEBs. Many existing assets were brought into the fold of the SEBs, often as the earlier licenses lapsed. These SEBs were established as extensions of the state governments, relying on them for financial support, management, and policies. Much of the financing came from state government budgets and loans, but the SEBs were expected to operate commercially. In fact, under the 1948 Act, SEBs were expected to have a Rate of Return (RoR) of not less than 3% on their asset base6, though in practice the returns have been dramatically lower (negative)

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The third period can be considered since 1991, when reforms were ushered in. This chapter studies this period in detail. While the different reforms all had the effect of ending the monopoly of the vertically integrated utilities (the SEBs), the initial reforms were geared towards drawing private investment into generation (Electricity Laws (Amendment) Act, 1991). Subsequently, reforms have focused on unbundling the vertically integrated utilities—with eventual privatization of the system—and the establishment of independent Electricity Regulatory Commissions (The Electricity Regulatory Commissions Act, 1998).

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Pre reform Growth of Indian power sector

Power development is the key to the economic development. The power Sector has been receiving adequate priority ever since the process of planned development began in 1950. The Power Sector has been getting 18-20% of the total Public Sector outlay in initial plan periods. Remarkable growth and progress have led to extensive use of electricity in all the sectors of economy in the successive five years plans. Over the years (since 1950) the installed capacity of Power Plants (Utilities) has increased to 89090 MW (31.3.98) from meagre 1713 MW in 1950, registering a 52d fold increase in 48 years. Similarly, the electricity generation increased from about 5.1 billion units to 420 Billion units – 82 fold increase. The per capita consumption of electricity in the country also increased from 15 kWh in 1950 to about 338 kWh in 1997-98, which is about 23 times. In the field of Rural Electrification and pump set energisation, country has made a tremendous progress. About 85% of the villages have been electrified except far-flung areas in North Eastern states, where it is difficult to extend the grid supply.

Structure of power supply industry

In December 1950 about 63% of the installed capacity in the Utilities was in the private sector and about 37% was in the public sector. The Industrial Policy Resolution of 1956 envisaged the generation, transmission and distribution of power almost exclusively in the public sector. As a result of this Resolution and facilitated by the Electricity (Supply) Act, 1948, the electricity industry developed rapidly in the State Sector.

In the Constitution of India "Electricity" is a subject that falls within the concurrent jurisdiction of the Centre and the States. The Electricity (Supply) Act, 1948, provides an elaborate institutional frame work and financing norms of the performance of the electricity industry in the country. The Act envisaged creation of State Electricity Boards (SEBs) for planning and implementing the power development programmers in their respective States. The Act also provided for creation of central generation companies for setting up and operating generating facilities in the Central Sector. The Central Electricity Authority constituted under the Act is responsible for power planning at the national level. In addition the Electricity (Supply) Act also allowed from the beginning the private licensees to distribute and/or generate electricity in the specified areas designated by the concerned State Government/SEB.

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During the post independence period, the various States played a predominant role in the power development. Most of the States have established State Electricity Boards. In some of these States separate corporations have also been established to install and operate generation facilities. In the rest of the smaller States and UTs the power systems are managed and operated by the respective electricity departments. In a few States private licensees are also operating in certain urban areas.

From, the Fifth Plan onwards i.e. 1974-79, the Government of India got itself involved in a big way in the generation and bulk transmission of power to supplement the efforts at the State level and took upon itself the responsibility of setting up large power projects to develop the coal and hydroelectric resources in the country as a supplementary effort in meeting the country’s power requirements. The National thermal Power Corporation (NTPC) and National Hydro-electric Power Corporation (NHPC) were set up for these purposes in 1975. North-Eastern Electric Power Corporation (NEEPCO) was set up in 1976 to implement the regional power projects in the North-East. Subsequently two more power generation corporations were set up in 1988 viz. Tehri Hydro Development Corporation (THDC) and Nathpa Jhakri Power Corporation (NJPC). To construct, operate and maintain the inter-State and interregional transmission systems the National Power Transmission Corporation (NPTC) was set up in 1989. The corporation was renamed as POWER GRID in 1992.

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.

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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.

What ailed the Power sector, rather interestingly, is summarized in a communication sent from the Union Power Minister to stake holders:

“As you are all aware, India has always been short of power and our entire populace, including the industrial sector has faced power cuts adversely affecting our welfare and national productivity. …..The supply side constraints in the power sector have arrested our economic growth and crippled our industry to an extent where recovery in future would be a cumbersome process.

….Serious doubts have been raised whether the power sector will be able to support a national plan of achieving an eight to nine percent rate of growth for the economy. We have reached a stage where the State Electricity Boards (SEBs) are depleted of resources and are in no position to pay for the power they buy from the generating stations. The total outstanding dues of the SEBs have crossed Rs. 27,000 crore. This, in turn, has affected the liquidity of the Central Public Sector Undertakings (CPSUs) for investment purposes for future projects.

The problems of the power sector are many. While the liquidity crunch is one major problem, we also have other issues to tackle like : Unacceptably high levels of transmission and distribution losses An inadequate transmission and distribution system Lack of adequate metering Drop in the tempo of rural electrification Fast rate of obsolescence of existing generating capacity Declining share of hydro-thermal mix etc.

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The subject of Power is in the Concurrent list and the responsibility for distribution i.e. for supplying electricity to consumers lies exclusively with the State Governments. Due to weaknesses in distribution, the sector is facing financial bankruptcy. This is due to

Theft estimated to cost over Rs. 20,000 crores annually avoidable technical losses of about 10% of the total power generated due to poor distribution system. Tariffs which are even lower than the cost of generation for many categories of consumers."

Another presentation of the Union Ministry of Power concedes that endemic problems of the power sector in India had been because of:

1. Un-metered supply - only 50% supply metered 2. No comprehensive energy audit/accounting

3. Theft and pilferage - Theft roughly estimated over Rs. 20,000 crores (US$ 4000 mill.)

4. Cross Subsidy in favour of agriculture and domestic sectors thereby adversely affecting industrial competitiveness

How rotten the State Electricity Boards had become could be summarized in the findings of 'High Power Committee' constituted by Hon'ble Supreme Court to investigate the largest Board- the UPSEB. The findings are telling:

"Up to 1988, the selection and posting of Chairman, UPSEB appears to have been based on criteria of merit. Unfortunately, a trend started from 1988-89 of blatant political and high level interference in selection and posting of Chairman, UPSEB. Subsequently, with every political change of U.P. Chief Minister, the Chairman of UPSEB was changed; the post of chairman since became highly politicized. There has been change of Chairman of UPSEB with change of political leadership is evident from the fact the tenure of some of the Chairman during the last 10 years which has been as short as less than 4 months. A strange practice was adopted by Govt. of U.P. that some of the appointments were made not for any particular tenure. Taking full advantage of somewhat ambiguous provision in section 8 of Electricity Supply Act, 1948, which provides that "the Chairman and other Members of the Board shall hold office for such periods, as may be prescribed", the Govt. intentionally issued orders with the clause "appointed till further orders" in the case of many Chairman. (The government, presently in place is following this not only in policies of chairman but that of directors too.)"

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Political interference from this point onward made in-roads in the working of the Board in a big way. It was allowed to go unchecked. Corruption in transfers, postings, purchases, favors to influential consumers became the order of the day. Deterioration in moral fiber creeper-in in amongst officers and staff also, and the work culture changed fast. The Chairman adjusted and cooperated with the political interference not only in administrative but in technical matters also.

The report assessed the adverse effect of political interference as follows:

Autonomy of the board as provided in electricity (Supply) Act 1948 was on paper only but not in practice. Power (Minister) and Power (Secretary) Govt. of U.P. exercised real power in day to day working, treating Chairman as a tool.

Chairman and Chief Engineers adopted policy of appeasement by surrendering power of discretion in transfers, postings, promotions and other personnel matters. Transfers became an industry. Nexus of politicians, Ministers, bureaucrats, influential consumers, industrialists and suppliers, exploited the Board. Dishonest officers received protection and managed postings on lucrative posts. Honest and conscientious officers could not fight vested interests and received harassment by their transfers to insignificant posts or by getting punishments.

Large & Heavy consumers managed favours at all levels under political pressure or on their own, even if it caused damage to the interests of the Board, technically or financially. Influential consumers managed violation of long standing Norms & Regulations of the Board in getting supply and other favours.

Persons of doubtful integrity, involved in cases of theft of electricity or other serious irregularities got promotions even to senior posts. Senior officers avoided decision making and kept

Status quo to pass on their time. Since the persons selected and appointed as Chairman, were not based on criteria of merit, they lacked vision, foresight, commitment, and therefore, were not bold and enterprising.

Chairman devoted their attention not to improve working of the Board but more on their survival. Since the Chairmen were more concerned with their survival, all the time, they avoided any controversy or confrontation by not taking measures of modernization, technological updating, computerization, mechanization or automation, or initiating new Projects or plans,

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or for that matter solving labor problems to motivate the employees and inculcate work culture.

Para 6.0 (2-3) of Vol. III of the report of the aforesaid committee records the root cause of the illness and are reproduced as under:-

"The survey does establish that high level political interference and also bureaucracy are formidable obstacles to the efficient functioning of the UPSEB. As told to us, the most disturbing area of concern, expressed unequivocally, borders on the quality of management at the top level, which, in turn, creates administrative slacks (and hence, lack of accountability) within the various divisions of the organization. Several Board Members, past and present, have said this - some bluntly commenting - as much as 70% of this is a managerial problem."

Owing to all these factors, the combined losses of State Electricity Boards reached to unmanageable proportions crossing 1% of the GDP. Even if political parties wished maintaining the status quo and dithered hard decisions, reforms became indispensable.

3. Need of reform

The essence of reform and restructuring has been to achieve the balance required to be maintained concerning competitiveness and efficiency on one part and the social objectives of ensuring that the consumer gets a fair deal on the other.

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The 70's and 80's have seen huge shortage of electric power in India. In states like Tamil Nadu, Punjab, Haryana, and Maharashtra, the power cuts were very severe. Some of the reasons of power shortage are as under:

Faulty Planning: The power projects have long gestation periods. The energy requirements have to be evaluated on a long-term basis and steps initiated to meet the requirements. Prospective planning has to be done for next 30 years or so. Instead of planning and building each of the power plants in isolation, studies must be made for optimal generating capacity expansion.

Sharp Increase in Demand: The70's saw a very sharp increase in electricity demand. Such a sharp increase has not been witnessed anywhere else in the world. This caught the planners unawares because of which the planning could not keep pace with the increase in demand.

Delay in Construction of Power Projects: The commissioning of many power projects has been delayed considerably. The main reason for the delay have been non-availability of funds in time, shortage of building material, delay in delivery of equipment, lack of co-ordination in construction activities, labour troubles, shortage of trained personnel etc. No attempt has been made to fix the responsibility of delay. Modern management techniques have not been applied to remove the bottlenecks and streamline the system.

Inter-state Disputes: The construction of many hydroelectric projects could not been taken up due to disputes between different state governments on sharing of project benefits and costs.

Erratic Monsoons: Many a time, the monsoons have been less than normal. The depletion of reservoirs caused a shortage in generation of hydro energy.

Plant Outages: The forced outage of power plant equipment has been rendering generating units idle for long periods. The plant outages have been due to poor quality of power plant equipment, improper operation, and maintenance.

Transmission Losses: The transmission losses in India are very high as compared to developed countries. About 30% of electric energy generated is lost in transmission and distribution systems.

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Shortage of Coal: The recent years have seen periodic closure of Thermal stations due to coal shortage. This shortage has been both due to difficulties at coalmines and in transportation.

Poor Utilization of Generating Equipments: The generating equipment is not fully utilized because of various reasons. In some plants, the generating equipments are utilized for around 3600 hours in a year.

The factors, which necessitate the government for reforms and restructuring, are:

Huge outstanding dues of SEBs to the central generating stations, coal companies, railway including equipment suppliers etc. they are not even able to earn 3% rate of return as mandated under the act.

Interference from state governments/politicians in the field of tariff formulation, recruitment of staff and interference in day-to-day administration like awarding of contracts and transfer of staff etc.

High price of fuel for power generation is another factor of higher cost of generation causing uneconomic operation of SEBs.

Monolithic and large structure of state electricity board (SEB).

The country needs more than 100,000 MW additional capacities during the coming decade requiring finances of the order of Rs. 300,000 cores for keeping a balance between demand and supply.

It would not be possible for government and public sector alone to make enough investment in energy sector. Due to financial crisis and desperate for funds, SEBs have been under pressure from World Bank to reform and restructuring the power sector. Therefore, Government of India announced a major policy decision on June 20, 1990 to through power sector to private sector.

4. Pre Reform Indian Power Sector

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Since independence, India has increased its power generating capacity by 55 fold: from 1,362 MW in 1947 to 76,718 MW of utility generation in 1994. Over this period, 75% of India's 550,000 villages have been electrified. With this major capacity expansion, per capita electricity consumption has increased from 15.6 kWh in 1950 to 270 kWh in 1994. Despite these achievements, India’s per capita electricity consumption is still among the lowest in the world, major power shortages remain, and thousands of villages still have not been electrified. Electric energy shortages in 1994 are estimated to be about 8% and peak capacity shortages around 19%. Major capacity expansions will be required to address the shortages and to spur India's rapid economic growth. The Central Electricity Authority (CEA) estimates that for the 8th Plan (1992-97) alone, capacity additions of 48,000 MW are needed. This figure has had to be scaled back to 30,538 MW due to limited resources. This reduced level of capacity additions will only meet the needs of the expanding economy (at a real GDP growth in 1994 of 5.0%) and will not appreciably reduce the level of power shortages in 1997. The bulk of the government-sponsored power construction program has been financed by central government transfers to the states and by multilateral banks and equipment vendors. An exception to this trend is the recent public issues by the National Thermal Corporation. Domestic capital markets have been efficiently tapped by India's private electric companies, in part due to their superior organizational and production management skills.

The Role of the States India’s major capacity addition requirements are placing an overwhelming burden on the ability of the Government of India (GOI) and the individual State Electricity Boards (SEBs) to provide the necessary financing. The typical international sources of power sector financing from such multilateral development banks as The World Bank and the Asian Development Bank are limited, and these banks are making their lending contingent upon power sector reforms. The GOI acknowledges that the poor creditworthiness and financial losses of many SEBs (caused by artificially low power tariffs, poor management, and overstaffing) are a major factor in forcing the imposition of these financing constraints. As shown in Exhibit 1-1, the profit/loss of SEBs varies from state to state, with more prosperous states such as Maharashtra and Andhra Pradesh indicating positive revenues, and states such as Bihar and West Bengal showing losses (it is important to note that these profit/loss figures were collected by the GOI and have not been audited by an independent entity). A major contributing factor to their limited creditworthiness is the tendency for political parties to see the supply of subsidized power,

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particularly to the farming sector, as a way of gaining political support. Reforming the power sector to bring it up to a commercial basis will require political, tariff, technical efficiency, and management improvements that will take years to implement.

The Role of the Private Sector The performance of most private utility companies in India is a reflection of the traditional financing methods of Indian industry. These utilities display characteristics that are similar to the large Indian industrial companies: they have created low-priced assets, have a small equity base (as compared to U.S. utilities), and have created large depreciation funds. For example, the Bombay Suburban Electric Supply Company (BSES), a private licensee that serves the greater Bombay area, has a market capitalization of around $280 million. The company is guaranteed a return of 5% over the Reserve Bank of India’s prime lending rate (currently around 12%): this translates into a 17% return on BSES's capital base. Old capital bases continue to receive the earlier lower decreed rates of return. Due to the differential treatment allotted to the capital base, licensees are engaged in aggressive construction programs of their own. The Tata Electric Company is building the 180 MW Bhira Pumped Storage project, BSES has recently commissioned the 500 MW coal-fired Dahanu power plant, and Calcutta Electric is nearing completion on the 500 MW coal-fired Budge-Budge project. All of these projects share equipment vendor financing and participation by the multilateral development banks. For example, for the Dahanu project, BSES obtained Rs 8.60 billion in debt (Rs 7.5 billion from the International Finance Corporation and Rs 1.10 billion from Indian financial institutions) and Rs 5.80 billion in equity (Rs 4.65 billion from Indian capital markets and Rs 1.15 billion from internal cash reserves). Exhibit 1-2 shows the ownership structure and principal financing sources.

5. INDIA'S POWER SECTOR: ON THE WAY OF REFORM

Electricity as a subject is in the concurrent list of constitution of India. It means that both the Union and the State Governments can formulate policies and laws on the subject but the responsibility of implementation rests with the states. Distribution of electricity in

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particular comes in the domain of the states.

Chiefly led by the Center, the reforms began 1991 although at the wrong end of generation instead of distribution of power. Perhaps this was due to the fact that opening generation for private sector was considered to be politically easy. In October 1991, Union Power Ministry began to publish a series of notifications seeking to encourage the entry of privately owned generating companies into the electricity sector. These government orders, some of which were later enacted in Parliament to become the Electricity Laws (Amendment) Act of 1991, radically revised prevailing legislation by permitting private entities to establish, operate and maintain generating power plants of virtually any size and to enter into long-term power purchase agreements with SEBs. The initial government notification also provided generous incentives to these independent power producers (IPPs), the most noteworthy of which was a guaranteed minimum 16 percent (repairable) return on equity for plants that operated at their rated capacity for at least 6000 hours in a year, with additional bonuses for improved capacity utilization. Other attractions for potential investors included a five year tax holiday, a two-part tariff (the first part covering fixed costs including the assured return, the second covering variable costs), equity requirements that were as low as 20 percent of project costs, and selective counter-guarantees from the central government to cover payment default by SEBs. The rules were clearly intended to attract foreign private capital into the sector, because they allowed 100 percent foreign equity but insisted that Indian financial institutions not provide more than 60 percent of the total debt component of any given project.

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From both domestic and international investors the response to the incentives offered was overwhelming. By mid-1995, there were about 189 offers to increase capacity by over 75GW, involving a total investment of over US$100 billion. Of these, 95 projects for a total installed capacity of 48,137 MW had reached the stage of Memoranda of Understanding (MOUs) or Letters of Intent (LOIs) with state governments. But meanwhile, since none of the projects had yet reached financial closure, the central government introduced another set of carrots, granting "fast-track" status to eight of the most promising projects and agreeing to offer those counter-guarantees.

Overall, though, for all the excitement with which it was launched, the reform program turned out to be a dud: against a target of over 40,000 MW in the period 1992-97, less than 17,000 MW were added, but that was hardly its most controversial aspect. As we shall see below, like the institutional impacts of lowered agriculture tariffs and de-metering in the 1970s and 1980s, the IPP policy of 1991 created new forms of lock-in with serious implications for all subsequent reform

Slowly and rather painfully, the policy makers realized that the problem lies with States and that without comprehensive reforms in Transmission and Distribution reforms in power sector would remain a pipe dream. Though, reforming the transmission and distribution segments, have been under discussion at least since 1993 when a committee of the National Development Council (NDC) comprising six chief ministers was set up, nothing worthwhile was achieved. Conferences of chief ministers/power ministers were held in 1996, 1998, 2000 and 2001 and some of the important recommendations / resolutions of the conferences/committees included:

Rationalization of tariffs through independent regulatory commissions

Adoption of transparent policies on subsidies, acceptance of a minimum all-India agricultural tariff

Benchmarking of tariff at the minimum of 50 per cent of cost of supply and agricultural tariff not to be less than 50 paisa per unit

100 per cent metering and energy audit, reduction of T and D losses through elimination of theft and strengthening/upgradation of sub-transmission and distribution system

Privatization of distribution in major / medium sized urban and semi-urban areas

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Decentralized distribution management in rural areas.

In spite of the ritual of holding conferences of chief ministers and power ministers each year, the resolutions passed at these meetings remained wish list.

6.Electricity Bill 2001

There is a major revamping of India’s power sector planned via the Electricity Bill 2001, which is in Parliament but has not yet been passed. This pending legislation was originally planned for 2000, and was renamed for 2001, but is expected to come into force only some point in 2003.Main features of the Bill include (Govt. of India 2001):

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Generation free from licensing except for hydro units Requirement of techno-economic approval done away with Captive generation free from controls Open access to transmission lines Setting up of State Electricity Regulatory Commission (SERC)

mandatory Open access in distribution to be allowed by SERC in phases Retail tariff to be determined by regulatory commission Trading a distinct activity permitted with licensing Formulation of a National Electricity Policy by the Govt. of India Strengthening anti-theft laws Establishment of Appellate Tribunal

This would be a major bill, revamping the 1910 and 1948 Laws, and extending reforms further. Fundamentally, it moves the country towards power markets, but it provides very little detail on the operations of such a system, e.g., the role of any independent system operator (ISO). It states that Regional Load Dispatch Centers will be responsible for grid operations, and failing their abilities or powers, the Central Transmission Unit (i.e., Power Grid) will take over this role. The Electricity Grid Code referred to in the bill, as formulated today (Power Grid 2002), states that these entities will not trade power, but only facilitate power transactions. The Power Trading Corporation, though designed to trade power, is not set up as an ISO. Both the Bill and the Code indicate Regional as well as State Load Dispatch Centers. This appears to be a poor design, as the synchronous grid should not operate with such granularity.The Electricity Bill 2001 has a strong focus on bulk (High Tension) consumers, who can get open access to generators (captive or IPPs). However, it doesn’t indicate how much surcharge the utilities can pose, for the losses they incur (loss of paying customer) (Mahalingam 2002). This tension, over paying customers that sustain the cross-subsidies of today, is one of the major issues facing the Indian power system.

7.The Electricity Act 2003

Contents:1. National Electricity Policy and Plan2. Generation of Electricity3. Licensing4. Transmission of Electricity5. Distribution of Electricity6. Tariff

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NATIONAL ELECTRICITY POLICY AND PLAN

1. The Central Government shall, from time to time, prepare the National Electricity Policy and tariff policy, in consultation with the State Governments and the Authority for development of the power system based on optimal utilization of resources such as coal, natural gas, nuclear substances or materials, hydro and renewable sources of energy.

2. The Central Government shall publish National Electricity Policy and tariff policy from time to time.

3. The Central Government may, from time to time, in consultation with the State Governments and the Authority, review or revise, the National Electricity Policy and tariff policy.

4. The Authority shall prepare a National Electricity Plan in accordance with the National Electricity Policy and notify such plan once in five years:

Provided that the Authority in preparing the National Electricity Plan shall publish the draft National Electricity Plan and invite suggestions and objections thereon from licensees, generating companies and the public within such time as may be prescribed: Provided further that the Authority shall -

a) notify the plan after obtaining the approval of the Central Government;

b) Revise the plan incorporating therein the directions, if any, given by the Central Government while granting approval under clause (a).

5. The Authority may review or revise the National Electricity Plan in accordance with the national electricity policy.

6. The Central Government shall, after consultation with the State Governments, prepare and notify a national policy, permitting stand alone systems (including those based on renewable sources of energy and non-conventional sources of energy) for rural areas.

7. The Central Government shall also formulate a national policy, in consultation with the State Governments and the State Commissions, for rural

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electrification and for bulk purchase of power and management of local distribution in rural areas through Panchayat Institutions, users’ associations, co-operative societies, non-Governmental organizations or franchisees.

8. The Appropriate Government shall endeavor to supply electricity to all areas including villages and hamlets.

GNERATION OF ELECTRICITY

1. Any generating company may establish, operate and maintain a generating station without obtaining a license under this Act if it complies with the technical standards relating to connectivity with the grid.

2. Every person who has constructed a captive generating plant and maintain and operates such plant, shall have the right open access for the purpose of carrying electricity from his captive generating plant to the destination of his use.

3. Generating company may supply electricity to any licensee under this act.

LICENSING

1. No person shall

(a) transmit electricity; or

(b) distribute electricity; or

(c) undertake trading in electricity,

Unless he is authorized to do so by a license issued under

section 14.

But this is not applicable on local authority,

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nongovernmental organization, franchise, co-operative

societies, user’s association, Panchayat institution. A

person who is already licensed for a particular time will be

deemed as eligible for obtaining license for a particular

span of time by the approval of appropriate commission.

TRANSMISSION OF ELECTRICITY

For this purposes, the Central Government may, make region- wise

demarcation of the country, and, from time to time, make such

modifications therein as it may consider necessary for the efficient,

economical and integrated transmission and supply of electricity, and

in particular to facilitate voluntary inter-connections and co-ordination

of facilities for the inter-State, regional and inter-regional generation

and transmission of electricity.

The Central Government may establish a centre at the national level,

to be known as the National Load Despatch Centre for optimum

scheduling and despatch of electricity among the Regional Load

Despatch Centres.

The Regional Load Despatch Centre shall be operated by a

Government Company or any authority or corporation established

or constituted by or under any Central Act, as may be notified by the

Central Government.

FUNCTIONS OF REGIONAL LOAD DISPATCH CENTRE

1. Responsible for optimum scheduling and despatch of electricity within the region, in accordance with the contracts entered into with the licensees or the generating companies operating in the region.

2. Monitors grid operations.

3. Keeps accounts of the quantity of electricity transmitted through the regional grid.

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4. Exercise supervision and control over the inter-State transmission system.

5. The Regional Load Despatch Centre may levy and collect such

fee and charges from the generating companies or licensees engaged in inter-State transmission of electricity as may be specified by the Central Commission.

Distribution of electricity

It shall be the duty of a distribution licensee to develop and maintain an efficient, co-ordinated and economical distribution system in his area of supply and to supply electricity in accordance with the provisions contained in this Act.

1. Where any person, whose premises are situated within the area of supply of a distribution licensee, (not being a local authority engaged in the business of distribution of electricity before the appointed date) requires a supply of electricity from a generating company or any licensee other than such distribution licensee, such person may, by notice, require the distribution licensee for wheeling such electricity in accordance with regulations made by the State Commission and the duties of the distribution licensee with respect to such supply shall be of a common carrier providing non-discriminatory open access .

2. Where the State Commission permits a consumer or class of consumers to receive supply of electricity from a person other than the distribution licensee of his area of supply, such consumer shall be liable to pay an additional surcharge on the charges of wheeling, as may be specified by the State Commission, to meet the fixed cost of such distribution licensee arising out of his obligation to supply.

3. Every distribution licensee shall, within six months from the appointed date or date of grant of licence, whichever is earlier, establish a forum for redressal of grievances of the consumers in accordance with the guidelines as may be specified by the State Commission.

TARIFF

The Appropriate Commission shall determine the tariff in accordance with the provisions for this act.

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supply of electricity by a generating company to a distribution licensee:

transmission of electricity ; wheeling of electricity; retail sale of electricity.

1. The Appropriate Commission may require a licensee or a generating company to furnish separate details, as may be specified in respect of generation, transmission and distribution for determination of tariff.

2. The Appropriate Commission shall not show undue preference to any consumer of electricity but may differentiate according to the consumer's load factor, power factor, voltage, total consumption of electricity during any specified period or the time at which the supply is required or the geographical position of any area, the nature of supply and the purpose for which the supply is required.

3. No tariff or part of any tariff may ordinarily be amended more frequently than once in any financial year

4. The Commission may require a licensee or a generating company to comply with such procedures as may be specified for calculating the expected revenues from the tariff and charges which he or it is permitted to recover

5. If any licensee or a generating company recovers a price or charge exceeding the tariff determined under this section, the excess amount shall be recoverable by the person who has paid such price or charge along with interest equivalent to the bank rate without prejudice to any other liability incurred by the licensee.

Summary Of Electricity Act 2003

1. Delicensing of generation2. Non discciminatory open access in transmission3. Power trading4. Rural electrification5. Compulsory metering among others

8. Shanker Committee Recommendation

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Model 1

unbundled generation, transmission and distribution multiple players in generation and distribution

a single transmission company

set up a regulatory commission (RC) with power to license and arbitrate

Model 2

SEB continues as a vertically integrated entity SEB will be corporative and a significant portion of its equity

disinvested gradually.

An independent regulatory commission is set-up by new legislation and government would transfer all its power to the commission.

Tariffs are decided on the principle of cost of service and subsidies (if any) are paid directly by government.

Model 3

Unbundled generation and transmission and distribution, but make the SEB the grid operating company owning all the transmission system with multiple players in generation and distribution.

Power for new generation capacity should be sold directly to the distribution company.

An independent regulatory commission is set up to regulate the transmission and fix the consumer tariffs.

Model 4

SEB give up distribution to a number of small companies, retain all existing generation and transmission.

A regulatory commission is set up with all power to regulate and fix tariffs.

All new generation is done by IIPs on the basis of competitive bidding. Bid will be invited from one or a group of distribution companies.

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All new transmission lines to be constructed by a single new company.

Model 5

Separate transmission into an independent corporation and divide the SEB into a several zonal SEBs.

Corporatist the SEB as a holding company owning the transmission and all the zonal SEBs.

IIPs are invited to set up generating stations in the regional company areas and hold part of their equity.

Soon all the regional companies would have their own generation plant(s).

Over time, each regional companies would become and independent private utility.

A regulatory commission is set up even at outset and all powers to government are transferred to it.

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9. Setting reform on track

27

The policy of liberalization the Government of India announced in 1991 and consequent amendments in Electricity (Supply) Act have opened new vistas to involve private efforts and investments in electricity industry. Considerable emphasis has been placed on attracting private investment and the major policy changes have been announced by the Government in this regard which are enumerated below:

The Electricity (Supply) Act, 1948 was amended in 1991 to provide for creation of private generating companies for setting up power generating facilities and selling the power in bulk to the grid or other persons.

Financial Environment for private sector units modified to allow liberal capital structuring and an attractive return on investment. Up to hundred percent (100%) foreign equity participation can be permitted for projects set up by foreign private investors in the Indian Electricity Sector.

Administrative & Legal environment modified to simplify the procedures for clearances of the projects.

Policy guidelines for private sector participation in the renovation & modernisation of power plants issued in 1995.

In 1995, the policy for Mega power projects of capacity 1000 MW or more and supplying power to more than one state introduced. The Mega projects to be set up in the regions having coal and hydel potential or in the coastal regions based on imported fuel. The Mega policy has since been refined and Power Trading Corporation (PTC) incorporated recently to promote and monitor the Mega Power Projects. PTC would purchase power from the Mega Private Projects and sell it to the identified SEBs.

In 1995 GOI came out with liquid fuel policy permitting liquid fuel based power plants to achieve the quick capacity addition so as to avert a severe power crisis. Liquid fuel linkages (Naphtha) were approved for about 12000 MW Power plant capacities. The non-traditional fuels like condensate and orimulsion have also been permitted for power generation.

GOI has promulgated Electricity Regulatory Commission Act, 1998 for setting up of Independent Regulatory bodies both at the Central level and at the State level viz. The Central Electricity Regulatory Commission (CERC) and the State Electricity Regulatory Commission (SERCs) at the Central and the State levels respectively. The main function of the CERC

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are to regulate the tariff of generating companies owned or controlled by the Central Government, to regulate the tariff of generating companies, other than those owned or controlled by the Central Government, if such generating companies enter into or otherwise have a composite scheme for generation and sale of electricity in more than one State to regulate the inter-state transmission of energy including tariff of the transmission utilities, to regulate inter-state bulk sale of power and to aid & advise the Central Government in formulation of tariff policy. The CERC has been constituted on 24.7.1998.

The main functions of the SERC would be to determine the tariff for electricity wholesale bulk, grid or retail, to determine the tariff payable for use by the transmission facilities to regulate power purchase and procurement process of transmission utilities and distribution utilities, to promote competition, efficiency and economy in the activities of the electricity industries etc. Subsequently, as and when each State Government notifies, other regulatory functions would also be assigned to SERCs.

The Electricity Laws (Amendment) Act, 1998 passed with a view to make transmission as a separate activity for inviting greater participation in investment from public and private sectors. The participation by private sector in the area of transmission is proposed to be limited to construction and maintenance of transmission lines for operation under the supervision and control of Central Transmission Utility (CTU)/State Transmission Utility (STU). On selection of the private company, the CTU/STU would recommend to the CERC/SERC for issue of transmission licence to the private company.

The Electricity Laws (Amendment) Act, 1998 provides for creation of Central and State Transmission utilities. The function of the Central Transmission Utility shall be to undertake transmission of energy through inter-state transmission system and discharge all functions of planning and coordination relating to inter-state transmission system with State Transmission Utilities, Central Government, State Governments, generating companies etc. Power Grid Corporation of India Limited will be Central Transmission Utility.

The function of the State Transmission Utility shall be to undertake transmission of energy through intra-state transmission system and discharge all functions of planning and

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coordination relating to intra-state transmission system with Central Transmission Utility, State Governments, generating companies etc.

Generation mix The share of hydel generation in the total generating capacity of the country has declined from 34 per cent at the end of the Sixth Plan to 29 per cent at the end of the Seventh Plan and further to 25.5 per cent at the end of Eighth Plan. The share is likely to decline even further unless suitable corrective measures are initiated immediately. Hydel power projects, with storage facilities, provide peak time support to the power system. Inadequate hydel support in some of the regions is adversely affecting the performance of the thermal power plants. In Western and Eastern regions, peaking power is being provided by thermal plants, some of which have to back down during off peak hours.

Emergence of regional power systems In order to optimally utilise the dispersed sources for power generation it was decided right at the beginning of the 1960’s that the country would be divided into 5 regions and the planning process would aim at achieving regional self sufficiency. The planning was so far based on a Region as a unit for planning and accordingly the power systems have been developed and operated on regional basis. Today, strong integrated grids exist in all the five regions of the country and the energy resources developed are widely utilised within the regional grids. Presently, the Eastern & North-

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Eastern Regions are operating in parallel. With the proposed inter-regional links being developed it is envisaged that it would be possible for power to flow any where in the country with the concept of National Grid becoming a reality during 12th Plan Period.

Utilization of installed generating capacity The size of the generating unit that has been used in the country in coal based power stations has progressively increased from about 15 MW prior to the era of planned development to 500 MW at present. With the introduction of new design of generating units, certain difficulties arose in their efficient operation and maintenance. The availability of coal in the country is such that the higher grades of coal, which have higher calorific value, have been exhausted and progressively lower grades of coal are being made available for electricity generation in the power stations. This had resulted into operational problems with the boilers designed for higher grades of coal and also put more pressure on coal handling plants etc. As a result of these technical and managerial problems, the utilization level of coal based power stations in the country declined in the late 1970s and early 1980s. The all India Thermal PLF which was as low as 27% at the beginning of First Plan progressively increased to 47.%% by the year 1963-64 and than declined to around 42% by early seventies. During one year in the seventies i.e. during 1976-77, the PLF touched 55.4% but this could not be sustained during subsequent years. Several factors such as inadequate maintenance of generating units, the teething troubles faced in the operation of the newly introduced 200/210 MW units and the deterioration in the quality of coal supplied to power stations led to a gradual erosion in the PLF of the thermal power plants during 5th plan period. During the 6th Plan, Department of Power and Central Electricity Authority undertook a comprehensive programmed to renovate and modernize old units located in different States. The performance of 200/210 MW units also begin to stabilize. Concerted efforts were made by Ministry of Coal to monitor quality of coal supplies to power plants. As a result of all these measures the PLF of thermal plants registered a gradual improvement during the 7th plan period. The plant load factor of thermal power stations in the country, which was only 44.2% in 1980-81, increased to 56.5% by the end of the 7th Plan. The all India Average PLF of the Thermal Power Plants has further increased to 64.4% by the end of eighth plan.

Private sector the initial response of the domestic and foreign investors to the policy of private participation in power sector has been extremely encouraging. However, many projects have encountered unforeseen delays. There have been delays relating to finalization of power purchase agreements, guarantees and counter-guarantees, environmental clearances, matching transmission networks and legally

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enforceable contracts for fuel supplies. The shortfall in the private sector was due to the emergence of a number of constraints, which were not anticipated at the time the policy was formulated. The most important is that lenders are not willing to finance large independent power projects, selling power to a monopoly buyer such as SEB, which is not financially sound because of the payment risk involved if SEBs do not pay for electricity generated by the IPP. Uncertainties about fuel supply arrangements and the difficulty in negotiating arrangements with public sector fuel suppliers, which concern penalties for non-performance, is another area of potential difficulty. It is important to resolve these difficulties and evolve a framework of policy which can ensure a reasonable distribution of risks which make power sector projects financially attractive.

The capacity addition programme for the 9th Plan envisaged around 17,588 MW to be added by private generating companies. In order to achieve the targeted private sector capacity addition during the Ninth Plan, the following additional facilitating measures have recently been suggested by the promoters. Most of these have been accepted while some of them are under the consideration of the Government.

Speedy environmental clearance

The Ministry of Environment and Forests has agreed to delegate the powers to States for environmental clearance of:

all co-generation plants and captive plants up to 250 MW; Coal based plants up to 500 MW using fluidized technology

subject to sensitive areas restrictions;

Power stations up to 250 MW on conventional technology.

Gas/Naphtha based stations up to 500 MW.

Viability of SEBs

The financial health of the SEBs will be improved through rationalization of tariff, restructuring and reforms to make them economically viable and their projects bankable to generate energy on economic rate, to provide quality services to the consumers and to ensure a fair return to the investors. This can be best achieved by unbundling single entity (SEBs) and corporatising the same for the above activities. In this context, some of the States have taken initiative by unbundling their respective SEBs into separate companies for Generation & Transmission & Distribution.

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Regulatory bodies The Government of India has promulgated Electricity Regulatory Commission Act, 1998 for setting up of Independent regulatory bodies both at the Central level and at the State level viz. The Central Electricity Regulatory Commission (CERC) and the State Electricity Regulatory Commissions (SERCs) at the Central and the State Levels respectively. These regulatory bodies would primarily look into all aspects of tariff fixation and matters incidental thereto.

Current problem of power sector

The most important cause of the problems being faced in the power sector is the irrational and unremunerative tariff structure. Although the tariff is fixed and realized by SEBs, the State Governments have constantly interfered in tariff setting without subsidizing SEBs for the losses arising out of State Governments desire to provide power at confessional rates to certain sectors, especially agriculture. Power Supply to agriculture and domestic consumers is heavily subsidized. Only a part of this subsidy is recovered by SEBs through cross subsidization of tariff from commercial and industrial consumers. The SEBs, in the process, have been incurring heavy losses. If the SEBs were to continue to operate on the same lines, their internal resources generation during the next ten years will be negative, being of the order of Rs.(-) 77,000 crore. This raises serious doubts about the ability of the States to contribute their share to capacity addition during the Ninth Plan and thereafter. This highlights the importance of initiating power sector reforms at the earliest and the need for tariff rationalization.

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Power sector reforms The Orissa Government was the first to introduce major reforms in power sector through enactment of Orissa Reforms Act, 1995. Under this Act, Orissa Generating Company, Orissa Grid Company and Orissa Electricity Regulatory Commission have been formed. Similarly, the Haryana Government has also initiated reform programme by unbundling the State Electricity Board into separate companies and Haryana Electricity Regulatory Commission has already been constituted.

With a view to improve the functioning of State Electricity Boards, the Government promulgated the State Electricity Regulatory Commission Act for establishment of Central Electricity Regulatory Commission at the national level and State Electricity Regulatory Commission in the States for rationalisation of tariff and the matters related thereto. Subsequent to the enactment of ERC Act, 1998 more and more States are coming up with an action plan to undertake the reform programmes. In this respect, Governments of Uttar Pradesh, Rajasthan, Madhya Pradesh, Goa, Karnataka and Maharashtra have referred their proposals for setting up independent regulatory mechanism in their States.

The Electricity (Amendment) Act 1998 was passed with a view to make transmission as a separate activity for inviting greater participation in investment from public and private sectors. The participation by private sector in the area of transmission is proposed to be limited to construction and maintenance of transmission lines for operation under the supervision and control of Central Transmission Utility (CTU)/State Transmission Utility (STU). On selection of the private company, the CTU/STU would recommend to the CERC/SERC for issue of transmission license to the private company. In this regard, the Government of Karnataka is the first to invite private sector participation in transmission by setting up joint-venture Company. Other States are also in the process of introducing the reforms in the transmission sector. In view of the urgent need to reduce transmission and

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distribution losses and to ensure availability of reliable power supply to the consumers reforms in the distribution sectors are also been considered by establishing distribution companies in different regions of the State. The entry of private investors will be encouraged wherever feasible and it is proposed to carry out these reforms in a phased manner. The Governments of Orissa and Haryana have already initiated reforms in the distribution sector by setting up distribution companies for each zone within their States. With these efforts, it is expected that the performance of power sector will improve because of rationalisation of tariff structures of SEBs and adequate investment for transmission and distribution sector

Capacity addition during 9th plan

Power supply position at the beginning of 9th plan The total installed capacity at the beginning of 9th Plan i.e. 1.4.97 was 85,795 MW comprising 21,658 MW Hydro, 61,012 MW Thermal including gas and diesel, 2,225 MW Nuclear and 900 MW Wind based power plants. The actual power supply position at the beginning of the 9th Plan indicates peak shortage of 11,477 MW (18%) and energy shortage of 47,590 MU (11.5%) on All India basis. To meet the growing demand and shortages encountered, sufficient capacity would need to be added in subsequent plan periods.

Ninth plan capacity addition programme The Working Group on Power, constituted by Planning Commission, in its report of December 1996 had formulated, a need based capacity addition programme of 57,735 MW for the Ninth Plan which would by and large meet the power requirements projected in 15th Electric Power Survey Report. However, it was felt that this capacity addition of 57,735 MW is not feasible and a target for capacity addition of 40245 MW was fixed for Ninth Five-year plan. The above target was finalized after considering the status of Sanctioned/ongoing schemes, new projects in pipeline, likely gestation period for completion of the projects and likely availability of funds. The Sector-wise/type-wise details are given below:

Sector-wise / type-wise capacity addition programme during ninth plan (Figures in MW)

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Sector Hydro Thermal Nuclear Total

Central 3455.0 7574.0 880 11909

State 5814.7 4933.0 --- 10747.7

Private 550.0 17038.5 --- 17588.5

TOTAL 9819.7 29545.5 880.0 40245.2

PRESENT POWER SCENARIO:

COUNTRY T&D losses as % of net generation

Sale per employee (MWH)

PUBLIC SECTOR OWNERSHIPIndiaIndonesiaPakistanPhilippinesThailandTurkey

23.516.922.215.610.012.3

204523219481492762

Private sector or commercializedUnited statesUnited kingdomArgentinaChileNew ZealandNorway

7.18.411.710.85.35.7

405719651514497122105520

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T&D losses are less in private sector entities than the public sector ownership as sale per employee is much more in private sector entities as compared to public sector ownership.

10. Power Sector Reforms : Chronology

Year

11. STATUS OF REFORMS IN STATES

Sl.No. State Status

1. Andhra Pradesh

SERC constituted, functional, two tariff orders issued.

Reform Law enacted, SEB unbundled.

Distribution privatization strategy being finalized

.MOU signed with Government of India.

2. Arunachal Pradesh SERC notified (yet to be

constituted).

3. Assam

Chairperson of the SERC appointed and SERC is functional.

MOU signed with Government of India.

4. Bihar


SERC notified (yet to be constituted)

5. Chhattisgarh MOU with Madhya Pradesh adopted.

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SERC constituted.

6. Delhi

SERC constituted, functional.

Tariff order issued.

Reform Law enacted DVB unbundled.

Distribution privatized.

RFP for Distribution privatization issued.

7. Goa


SERC constituted.

8. Gujarat

SERC constituted, functional, tariff order issued.

Reform Law approved by Government of India and introduced in the Assembly.


9. Haryana

SERC constituted, functional, two Tariff Orders issued.



10. Himachal Pradesh

One Member HPSERC constituted. Member appointed w.e.f. 6/1/2001.

Tariff order issued & implemented w.e.f. 1.11.2001


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11. Jammu & Kashmir

Reform Bill passed by State Assembly.

MOU signed with Government of India

12. Jharkhand MOU signed with

Government of India.

13. Karnataka

SERC constituted, functional, Tariff Order issued.



Distribution privatization to be completed by December 2001 as per MOA signed with Government of India.

14. Kerala

The State does not envisage unbundling of State Electricity Board Working of Board to be re-organized into three profit centres.

SERC constituted.


15. Madhya Pradesh

SERC constituted, Tariff order issued.

Reform Law passed by the Assembly and notified.


16. Maharashtra

SERC constituted, functional, tariff order issued.


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17. Orissa

SERC functional, four tariff orders issued.


Distribution Privatized.


18. Punjab

SERC constituted, Chairman, Members appointed.


19. Rajasthan

SERC constituted, functional, Tariff order issued.

Reform Law enacted, SEB unbundled. One generation, one transmission & three Distribution Companies created.

RFP for Distribution privatization to be issued by July 2002.


20. Tamil Nadu

SERC constituted.


21. Uttar Pradesh SERC constituted, functional, tariff order issued.


Distribution privatization strategy to be finalized.

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22. Uttaranchal


SERC constituted

23. West Bengal

SERC constituted, tariff order issued.


24. Nagaland Have shown willingness to constitute Joint Electricity Regulatory Commission.

25. Meghalaya

26. Mizoram

Tariff order issued.

27. Manipur

28. Tripura

29. Sikkim

S.No.

Name of the State Tariff orders issued

1 Andhra Pradesh Yes

2 Arunachal Pradesh Yes

3 Assam

4 Bihar

5 Chhattisgarh

6 Delhi Yes

7 Goa

8 Gujarat Yes

9 Haryana Yes

10 Himachal Pradesh Yes

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11 Karnataka Yes

12 Kerala Yes

13 Madhya pradesh Yes

14 Maharashtra Yes

15 Orissa Yes

16 Rajasthan Yes

17 Tamil nadu

18 Uttar pradesh Yes

19 Uttaranchal

20 West Bengal Yes

21 ** Mizoram yes

12. Central Electricity Regulatory Commission (CERC)

The function of CREC regulates most decision-making comes under the Ministry of Power, with the Planning Commission involved in financing Plan expenditures. Functionally (and for execution), the activities of the Board are managed through a Secretariat provided by Central Electricity Authority (CEA). The Board meets at least once in year to consider amendments/additions to the rules (Ministry of Power 2002). The Central Electricity Authority is the operating body that has been responsible for much of the regulatory norms in force today, especially prior to the establishment of the Central Electricity Regulatory Commission (CERC) in 1998. The CEA was established in 1951 as a part time statutory body, and became a full-time body in 1975. It helps the ministry of power with all technical, economic, and operation tasks relating to the power sector, viz., techno-economic operation of the Indian power system. It has been the body responsible for techno-economic clearances (TEC) for all power projects above a certain size. After the 1998 reforms, the regulatory responsibilities of CEA have been shifted to CERC. We study the regulatory commissions in more detail shortly.If a generator (IPP or PSU) wants to build a power project, it comes to the CEA for techno-economic clearance.The functions of CERC include

Regulating the tariff of generating companies owned or Controlled by the central government

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Regulating the interstate transmission of energy including The tariff of transmission utilities

Promoting competition, efficiency, and economy among the power sector activities

Advising the central government on the formulation of tariff policy.

The central government and a few state governments have appointed regulators, and some states have unbundled the sector into transmission, generation, and distribution through state enactments. However, a number of reform measures have not yet been attempted at the central or the state level. These measures include setting up a wholesale electricity market, the introduction of competition, and the determination of generation tariff in a competitive market environment. There is a need to make an easy entry of different players into the competitive market supervised by regulators.

13. Privatization of distribution entities

India‘s power industry is characterized by inadequate and poor quality

power supply. Peak capacity and energy supply shortages are

estimated to be over 20% and 15% respectively. The sector is plagued

by major revenue shortfalls due to low tariffs, heavy cross subsidies,

and extremely poor collection performance. The sector’s heavy

reliance on increasingly tight state budget resources has constrained

power expansion and system upgrading. In 1991, the government of

India took several policy initiatives and introduced a number of reforms

in the power sector. It has since become evident that in the absence of

major structural and regulatory reforms in power sector, notably at

state level, no revenue enhancement mobilization would be

sustainable.

The problems confronting the SEBs are so enormous and so

fundamental that there is no realistic prospect, which can be solved by

managerial or other internal reforms. Reform must be implemented

through a transition programme that manages disruption and provides

time and assistance to those who must adjust, but that accomplishes

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its objectives on a well-defined schedule. Privatization of significant

parts of the SEBs current activities and assets is required, which must

be implemented through restructuring to create autonomous,

independent, commercially motivated business units. Such

restructuring as a prelude to privatization has proven effective at

dealing with similar problems in other parts in India, and in electricity

systems in other places like Chile and Argentina.

There are many reasons why marginal reform of SEBs has not

succeeded and probably cannot succeed. Poor morale and lack of

motivation are too deeply imbedded in the SEBs culture to be

eliminated by exhortation or promises. As in any financially sick

business, fundamental changes are required to make the promised

changes credible and to attract the new money needed to implement

the changes. In order to succeed, a reform must promise fundamental

changes that will overcome the personnel and institutional inertia that

has smothered past reform efforts. Most of the problems confronting

the SEBs are directly traceable to non-commercial constraints officially

imposed by governments and by unofficial interference from individual

politicians. Government promises to stop political interference in a

state-owned enterprise seldom hold-up for long, not in India but in

advance industrial economics as well. For all these reasons and more,

only way to assure that improvements in power sector are real and

lasting, and lasing, and to convince the industry and potential investors

that they are, is to establish private ownership in the large part of the

sector, under truly independent regulation. But neither the industry nor

the external investors will believe in change in real until they see that

the government has the potential and ability to define, endorse and

begin implementing a well-defined privatization programme.

Privatizing the SEBs as one corporate body with its existing

structure and monopoly powers intact would be unlikely to be of great

benefit to the public or to stimulate the new investment that is so

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badly needed. Creating a large, powerful, private monopoly would

create many problems, including the following:

Political Problems: trying to privatize a monopoly would

expose the government to severe political criticism.

Regulatory Problems: As a single monopoly, the SEB would be

difficult to regulate effectively or efficiently.

Managerial Problems: Private management of a large, diverse,

far, –flung SEB would face the same problems of efficiency and

control faced by SEB. Economics of scale do not justify single

ownership or control of most of the SEB’s activities; indeed, it is

likely that excessive centralization increases cost.

Privatization Problems: It is unlikely that entire SEB could be

sold to a trade buyer for good value.

Perception and Credibility Problems: There is suspicion

likely within the SEB and aid communities that the Government

is not serious about reform. Announcing that shares in a

corporative SEB will be sold at some time in the future would not

do much to allay these suspicions.

Reform of the power sector will not be real, lasting, or credible

until the Government adopts and begins implementing a

programme to privatize much of the sector, and that this is best

accomplished by restructuring the SEBs into smaller business

units that can be put under private management and ownership

as commercial, economic and political conditions permit.

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14. RESTRUCTURING OF DISTRIBUTION ENTITIES

It is expected that as the time passes the consumer will be more

&more concerned about the reliability and quality of electricity

supply and therefore the power utilities will have to be more

service-oriented. The consumer complaint centre in urban and

rural areas should have micro –computer service for better fault

analysis & service monitoring.

Management should be work -oriented type .Trade union should

respond to accountability and responsibilities of workers

earnestly. The person employed in power sector should also have

shares in the profit gained by the power sector. This will mobilize

them to work harder for betterment of power sector.

The computer should play a central role in the management of

distribution systems.

Conservation of energy should be the top most priority. Law of

conservation should be enacted by the central government and

should be enforced through out the country. People should be

induced to save electricity with the help of media such as TV,

Radio, and Newspapers etc.

Electricity minimum tariffs for agriculture should be fixed on

uniform basis through out the country by the central government

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and linked with the long –run marginal supply cost on regional

basis.

Steps should be taken for 100% rural electrification of villages.

Right-of-ways for sub-station and lines is a big problem in the

urban areas and therefore underground system for the urban

areas are expected to play a greater role.

Maintenance free technologies should expand from LT to higher

level voltage system , such as micro-processor based system

protection and consumer metering, distribution, SCADA, modular

type of equipment construction, modular type of software

structure, SF6/vacuum switch –gear, amorphous core

transformers, polymer cables, use of ABC line system and

aluminium alloy conductors.

Overall energy shortage and gap in peak demand is expected to

increase. The role of demand side management may prove to be

important as an alternative to generation capacity expansion.

Renewable energy sources, solar power, wind power, micro/ mini

hydel, mini thermal plant technology may be commercially viable

for grid connections.

There is an urgent need of a national power grid.

Electric energy storage system using superconducting material

should be developed.

Information technologies should play an important role. Power

utilities should become integrated for engineering and

construction, as well as for utility –wide operations. The Indian

power utilities should be interconnected to world power utilities

through internet or superhighway for better exchange of

information on productivity, effectiveness and resources.

Power utility business should be ‘process-oriented’. The process

is a collection of activities that takes one or more kinds of input

and creates an output that is of value to the consumer.

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Power utilities should need to reinvent themselves constantly,

since there would be constant changes in markets and

technologies. They should be transformed mere distributors of

electric energy, to producers of electric energy solutions.

Competitive bench marking should be the continuous process of

measuring products, services and practices against the

recognized leading power utilities.

To conserve energy, energy services should be evolved.

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15. T&D LOSSES

Losses vary in each state because of varying system characteristics

such as load density, urban/sub urban/rural network, predominant

sub transmission voltage of supply. Other factors such as

inadequate designs and bad maintenance contribute to higher

losses. Their may be significant proportion of unaccounted losses

due to inaccuracy in meters and metering equipment, flat rate tariff,

error of consumer billings, pilferage of energy and unauthorized use

of electricity. India has about 22%T&D losses whereas China has

only 13%. The main reason attributed to low losses in china is

installation of generating stations of near load centers such as

numerous mini/micro-hydel plants, nuclear plants etc.

The outlay on generation component in the total power sector

outlay, which was about 69% in 1992-93, declined to 56.4% in

1995-96. Increased outlays on R & M projects are also desirable

because it would improve the average PLF of the existing power

plants. The outlay on T&D increased to 30.7% in 1995-96 from

22.5% in 1992-93. Investments on T&D scheme however continue

to be lower than what is consider desirable from operational point of

view. The share of the generation in the power sector outlay was

62% in the eighth plan where as T&D had only 28% share as against

recommended 1:1 ratio in the investment of generation and T&D.

this is one of the main reason that has result in high T&D losses and

poor quality of electricity supply to the consumers in almost all

states.

49

(i) Factor contributing the technical losses

Distribution losses are reported to be over 20 percent. Technical

losses may be reduced by augmentation, renovation, and

modernization of the distribution system and way of switching over

to aerial bunched conductors and usage of single-phase high-

tension (11 KV) line. This will also improve the quality of service to

the customers.

Factors contributing technical losses:

Inadequate reactive compensation and poor voltage regulation

Corona losses, overloading of the transmission line

Improper location of power and distribution transformer

Inappropriate rating of the distribution transformer

50

Inappropriate choice of voltages

Disproportionate load growth in low and medium sectors, low

power factor

Ratio of HT to LT lines(LT 60% of total line length)

Unbalanced loading of the transformer and transmission lines

Over frequency of the system

(ii) Factor contributing the non-technical losses

Non-technical losses are due to theft of electricity by way of tampering

meter or/direct tapping. Most of the theft occurs with connivance of

employees or inability of employees to take strong action against

stake. A well-managed company would be able to tackle the situation

in an organized manner.

(iii) Factors contributing non-technical losses :

Unaccounted energy attributable to administrative and policy

decisions of govt. and utilities

Problems in metering and billing

Unauthorized abstraction of energy

Legal constraints in prosecution of theft and tampering

(iv) Losses reduction

Correction and misclassification of customers:

There is a tendency on the part of the customers to use power,

which is connected into a premise for domestic use, for commercial

purpose. A number of shops and professional instruction located in

domestic area pay only domestic rates, which are lower than

51

commercial rates thus causing substantial loss to the SEBs.

Experience shows that the correction in classification and billing the

customer as per the right tariff classification can bring substantial

revenue addition.

Saving of O&M expenditure:

The operation and expenditure consists mostly the expenditure on

salaries and wages for the staff employed and on stores and

consumables. While large shares goes to wages & salaries, and next

highest expenditure is for repairing the transformers. Transformers,

is properly loaded and regularly maintained should not go for repair.

Only private sector distribution can manage and control of

inventories and burning of distribution transformers, which can lead

to substantial savings.

reduction the time lag between meter reading,

billing & collection of revenues:

Proper meter reading, billing& collection along with time scheduled

followed by spot billing procedure will fetch revenue addition.

Various means for reducing the system losses are

given below:

i) Optimizing line capacity

a) Selecting appropriate KVA-KM capacity based on the required

voltage regulation and normal power factor for the conductor

used for LT distribution circuits.

b) Select appropriate MW-KM capacity for the standard conductors

used in primary distribution, thereby limiting lengths of primary

feeders.

ii) Optimizing transformer capacity, location and use

a) Selecting appropriate capacity of distribution transformers in

relation to the consumers fed by it to keep voltage drop to a

minimum.

52

b) Selecting appropriate location of distribution transformers in

relation to the consumers fed by it to keep voltage drop to a

minimum.

c) Optimize the use of distribution transformers based on load

factor occurring on them.

iii)Maintaining appropriate voltage levels in distribution systems.

iv)Installation of shunt capacitor

a) Apply shunt capacitor across individual inductive load or at

suitable point on the main LT distributors based on economic

viability.

b) Apply shunt capacitors for optimum rating at optimum locations

on primary feeders to save line losses and improve voltage

condition.

v) Select single wire earth return system for sparsely populated rural

areas having lesser potential for future development.

vi)Use of Alloy Conductors : All Al-Alloy Conductors(AAAC) have

gained worldwide acceptance for use in overhead lines, because of

its superior overall performance, longer life, higher working thermal

temperature of 90 C, lower losses over conventional ACSR. The AC

resistance of AAAC is lower than the ACSR of the same cross

sectional area. Since there is no steel core in AAAC, there is no

magnetization core loss in AAAC.

vii) Line Unbalance in LT Supply : As a result of unequal load on

individual phases; negative and zero phase sequence components

cause overheating of transformers, cables, conductors and motors,

thus increasing the losses and the motor malfunction under

unbalanced voltage condition. Keeping the system negative phase

sequence voltages within limits amounts to saving in capital (as

otherwise equipment is derated) as well as energy losses.

53

viii) Miscellaneous Measures : There is large for energy saving in

areas such as use of computerized control for network monitoring

and management, use of solid state or digital energy meters

instead of conventional induction type, laying efficient public

lighting with MLL,SOX,SON lamps, installation of low loss amorphous

metal alloy core distribution transformers, staggering of agricultural

loads in rural areas not using of proper minor irrigation motor pump

for agriculture and silicon diode and thyristor converters in place of

rotary and mechanical arc converters, decentralized power

generation from renewable energy sources, limit harmonics, good

construction and maintenance practices, viz., jointing, jumpering,

tapping etc., good operational practices. Suitable controllers can be

used to arrange an operation with one or two transformers in the

most economical in terms of total transformer losses. The

transformers can then be automatically switched in and out to

minimize loses.

ix)Revamping the Existing System : In the existing system higher

losses can be due to –

Improper construction and maintenance of lines and transformers.

Uneconomic conductor size.

Inadequate layout of the feeder.

Overloading of distribution transformers.

Low voltage conditions in the network.

Poor power factor due to inadequate reactive compensation.

Use of poor quality of construction material.

Uneven distribution of load on various feeders and substations.

The measures to be adopted to reduce losses and improving

voltage regulation are:

Power factor correction be done by providing capacitors near to

load centers.

54

Redistribution of load among various feeders.

Redistribution of feeders among various substations.

Re-routing of feeders or adding of link lines.

Proper tap-setting of interconnecting transformers.

Providing proper sectionalizing of lines.

Shifting of transformers to load centers.

Overloaded transformers should be augmented or new

transformers to be added.

Conductors of higher size should be used for heavily loaded

feeders.

Use of good quality material and proper joining and good

maintenance should be carried out.

High levels of vigilance should be regularly carried out to check

pilferage of energy and other unauthorized use of electricity.

System extension for release of new power connection be done

after taking into account of voltage regulation at tail end,

balancing of loads and not overloading of transformers.

Upgrading the operating voltage by conversion of the existing

system of operation at the next higher voltage level. For

example, it may be feasible to convert the existing LT lines and

system operating at voltage below 11 KV into 11KV lines and

11KV lines into 33KV using the same supports and conductors by

changing the cross arms and insulators only.

The computer aid could be taken for accurate and speedy analysis

of the system to undertake revamping or extension. For example: to

minimize the system losses, and improved overall system

performance, Wipro Information Technology Ltd. have brought out

Computer Aided Power System Improvement(CAPSI) facility. Many

power boards like Punjab state electricity board has purchased this

system.

55

16. TARIFF RATIONALIZATION

The primary objective of tariff rationalization is to ensure that every

consumer pays at least the cost of supply initially and gradually

moves to pay more than the cost, so as to adequate internal

surpluses. the policy of the government so far, has been to

subsidize sectors like agriculture and residential costumers .As

subsidies cannot be extended till eternity, it is essentially to identify

segments in each category and consumers that deserve subsidy.

Subsidy extended to such target groups would be so marginal that

it would not be difficult for other consumers in the same segment to

cross subsidize.

There are many methods of tariff management, which

would be considered in, and an integrated manner.

1. differential Tariff: This can be in the form of three step time of

the day tariff:

(i) A high charge rate reflects the large share of the demand

related costs during peak hours.

(ii) OFF Peak Rate, for supply during night time through the year

and /or on holidays with a low charge, that would exclude

demand related cost

(iii) Intermediate rate for supply during the remaining period, at a

rate between the(I) and (ii)

It encourages the spread of electrical l9oad and reduces the impact

of demand peak hours, which mean fewer power cut problems. This

requires the use of differential or multi-rate meters.

Differential meters with demand metering are almost 3 times

costlier as compared to conventional two part meters.

2. Long run Marginal Cost(LRMC) base tariff: Electricity

pricing in India has been based on the broad guidelines of the

56

Electricity Supply Act., and the basis of pricing is average cost

plus a minimum return of 3% on invested capital. Those users

who desire additional capacity must really pay for it. Thus, if

prices based on operating costs(variable prices based on

operating costs) are charged to the peak time users, they will

continue to the operate during peak periods, whereas others who

can manage , will shift their loads away from peak to off-peak

periods, when they do not have to pay the additional capacity

charges. This would improve the daily utilization of the power

system capacity.

3. Rational Tariffs: There are two basic tariff making philosophies

– Cost Based and Market Based. The factors used in developing

cost based tariffs are identified as capacity related, energy

related and consumer related. These factors vary for different

classes of consumers (residential, agricultural, commercial,

industrial etc.) and require an analysis of much data in order to

properly allocate costs. Cost based tariffs are generally preferred

because they are less likely to be criticized by consumers.

(A)Cost -Based Tariffs: Tariffs should have sufficient rates to

raise adequate revenue to meet the financial requirement of

the utility.

The Tariff should be based on supply cost for each category of

consumer. However, urban consumers will subsidize the rural

consumers to some extent. Profit oriented consumers i.e.

commercial or large industry, should contribute to earn the

same rate of return for utility.

Peak consumers should pay both capacity and energy costs,

whereas off peak consumers (such as agriculture) should pay

only the energy costs.

57

The lower the service voltage, the greater the costs consumers

impose on the system. Therefore, higher tariffs for low voltage

conw8umers are desirable.

Tariff should be based on marginal costs of serving demands

For different consumer categories.

For different seasonal industries i.e. rice sellers, ice industries

etc.

For different hours of the day i.e. higher rates for peak hours,

medium rate for day time and lower rate for night hours.

For different voltage levels i.e. HT or LT supply consumers.

(B) Market based Tariff: following are some examples of

market based tariffs –

a) Certain industrial classes may be subsidized to attract

new industry to an area.

b) Other classes may subsidize residential rates for

social/political purposes.

c) Agricultural tube-wells services may be subsidized to

encourage increased food production.

17. METERING

Largely, metering is still viewed as instrumentation at the end of

distribution line. This is understandable, for decades, “the reason for

being” for meters has been measurement of the energy used. The old

electromechanical meters, in any case could not do much more than

measure.

These meters provide higher and sustained accuracy and

reliability. They are also good at detecting, recoding, and thus

deterring theft. However, more importantly, they can record and store

all kind of usage data. Therein lays the key difference between the old

and new metering. Most of the modern metering technology is

58

dedicated to intelligence, not measurement. In fact form not more than

10% of the device.

Unfortunately, the SEBs in India (like the utilities overseas)

has not really utilized this power. They need to look upon metering as

more than just billing. They need to think of it as a key utility

management issue. For, the real benefit of electronic metering comes

not just from an intelligent device at the customer’s premises.

Here is a brief write up on electronic meter in metering which

extensively use the latest techniques.

Meter reading instruments : A meter-reading instrument (MRI) is

a data collector that retrieves usage information from the meter

using optical sensors. Typically, the meter reader takes this

instrument to the customer site and connects it to the meter. The

data is transferred from the meter to the MRI. The meter reader

brings the MRI to the billing station.

Remote meter reading : In fact, the meter reader does not even

need to visit the customer site to collect the billing information. If

there are good communication facilities, the reading can be done

automatically and remotely. The microprocessor in the meter

sends the information to the billing computer that generate

invoice. Tampering and fraud are also curtailed.

Spot billing : The utilities can go one-step further by attaching a

printer, portable or otherwise, to the MRI. The meter reader can

generate the bill on the spot. This can help cut down the billing

cycle from a few days or weeks to a few minutes, and thereby

expedite revenue collection.

Pre-payment meters: These meters permit customer to consume

only the amount of energy that has been paid for in advance. The

payment is made at the collection station of the SEB or utility .This

technology is also known as smart card.

59

Advantages:

Reduce the cost of theft and corruption : Electronic meters

ensure that SEBs collects the proper revenue for the electricity

that they provide. Electronic energy meters now exist that can

measure current in both phase and neutral and calculate power

consumption based on the larger of the two currents.

Improve cost and quality of electricity distribution: Besides

reducing the cost of manually reading meters, power outages can

be detected, identified, and corrected more quickly for customers

whose meters are communicating through a network.

Minimum pollution: Peak usage is minimized despite population

growth through multiple rate billing and distribution cleanliness I

maintained by monitoring the power quality pollution contributed

by individual consumers.

Comparison between conventional & microprocessor base energy meter

Attributes Conventional electromechanical meter

Microprocessor based electronic meter

Accuracy Can be affected by wear and tear, changing frequency, overloading etc.

No such loss of accuracy

Meter reading Manual and slow Automatic and fast Remote metering Not possible Possible Usage information on peak load, daily average etc.

Not available Recorded and stored over a period of time

Tampering possibility

High Very low

Billing process Slow due to paper work

Fully computerized and fast

Multi-tariff billing Not possible with Possible

60

(time-of day, load based etc.)

one meter

Load management capabilities

Not possible possible

Information on power factor, frequency etc.

Not available Displayed on meter

18. NATIONAL GRID

It is generally accepted that we have weak inter-regional transmission

links. Despite years of talking about it, we still do not have a national

power grid.

There are many reasons for this state of affairs. Chief among these is

the fact that originally, as in the first two decades after independence,

transmission and distribution was developed on a state-by-state basis.

It was only in1964 that five regional grids were formed, which fell

under regional electricity boards (REBs).

Another reason the inter-regional links are very weak is the fact that

these regional load dispatch centers were based on primitive

technology. In the 70s and the 80s, the government spent its time and

effort creating generating capacity but ignoring the augmentation of

transmission facilities.

Over the last few years, the Power Grid Corporation has tried to

improve matters. It has established the formation of a national grid as

a high priority. It hopes to put in place an efficient and adequate

national power grid.

61

Power Grid is also planning to upgrade the regional dispatch centers,

as well as create a national load dispatch and communication facility.

This is another necessary condition for the formation of a national grid.

The inter- regional and inter-state links are especially important in the

light of the fact that a number of mega projects are coming up in both

the public and private sector. The interconnection of these regions is

also needed because different load patterns. The supply patterns also

differ because of differences in thermal-hydel mixes across regions. In

the absence of a national grid, some regions may fall short in meeting

their peak load demand, while at the same time; other regions are

backing down their generation.

Problems of system interconnection in India :-

Lack of operational discipline among constituents: Each constituent in a region is expected to maintain a balance

between its own generation and demand .However due to overall shortage in installed capacity the constituents tend to over draw share from central stations. This leads to a disturbance in grid parameters and system stability.

Frequency regulation : During off peak conditions frequency goes about 51 Hz. Proper load management, use of under frequency relays for automatic load shedding and accelerated setting up of new generation units is needed.

Voltage Control: A proper voltage profile is maintained in the system. The problem of low voltage is especially severe in summer season due to inductive loads of air-conditioners, coolers, fans etc. and in agricultural period due to inductive loads of pumps. These problems can be tackled by meeting reactive power requirement at the load centers. The program of installation of shunt, capacitors needs a big thrust.

Load Dispatch and communication: The present power line carries communication (PLCC) system cannot be expanded due to congestion in the available frequency spectrum, difficulty in cascade tandem operation etc. It is proposed to add multi channel digital microwave system and fiber optic communication system to provide better load dispatch and communication facilities.

Lack of spinning reserve: At the time of peak loads, the demand is more than the generation and there is no spinning reserve in

62

the system. Better load management and installation of additional load generation facilities is needed.

Metering and instrumentation: Adequate metering and instrumentation is needed at different levels. It is necessary to install sequential recorders, disturbance recorders, time of day meters etc.

Advantages of national grid:- System interconnection leads to several advantages both to the

members of the pool and the users of electricity. It is necessary that

advantages and savings be examined thoroughly and weighed against

the cost of system interconnections. This analysis is complicated by

the fact that some benefits cannot be evaluated in terms of money.

Increase in Service Reliability: Every equipment is prone to outage

during its operation. System interconnection leads to increase in

reliability of electric supply. In the event of one utility falling short of

generation, due to forced outage of generators or unexpected increase

in demand, another utility of the pool can come to its rescue by making

its surplus power available. An interconnection between the local

transmission systems of two utility can lead to an increase in service

reliability at considerably less expense than that which both would

have to incur in the construction of additional lines. When the lines are

fed from more than one-generation source, the reliability is still further

improved.

1. Addition and Replacement of Transmission

Facilities: Load growth necessitates additional transmission

facilities. The question like cost of right of way and installation of

63

line and the territory to be served can be more economically and

easily decided when more than one utility is involved. The utilities

can share the cost and use of lines. This would evidently lead to

optimum use of facilities.

2. Installed Capacity Savings : An interconnection is likely

to decrease the installed capacity needed to meet the load

requirement. In majority of cases, it happens that the maximum

demand of one area does not coincide with the maximum demand

of another area. This could be due to difference in sun times and

weather condition of two area. It could also be due to the fact that

I one area the major load is industrial while in the other is

residential and commercial. if two such area are inter connected,

the diversity of loads would cause the maximum combined

demand to be less than the sum of the individual maximum

demands.

3. Decrease in Spinning Reserve Requirements : Every

utility has to keep some generation capacity as reserve to take

into account the capacity reduction due to forced outages and

scheduled maintenance. When two systems operate separately,

each has to maintain a separate reserve capacity. If they are

interconnected, it may be sufficient to have a smaller total reserve

for the combined system for the same degree of reliability.

4. Operating Savings : When two different utilities are

operating separately, each would run its units most economically.

However when the two are interconnected and the optimum

scheduling is decided for the combined system, the operating cost

are likely to decrease. Thus, energy interchange between the two

would result in saving for both.

64

5. Optimum losses : The optimum system losses in the

Indian power system as suggested in the World Bank

Report No – 6 are as given below-

Optimum Technical Losses

System, Component Max. to be tolerated

Within Cumulativ

e

Step – up station

EHV transmission and station

HV transmission and station

Sub-transmission

Distribution station

Distribution primary

Distribution transformer and

secondary

0.50

1.00

2.50

4.00

0.50

5.00

2.00

0.50

1.50

4.00

8.00

8.50

13.50

15.50

The Rajadhayaksha Committee (1980) has capped the total system

losses not exceeding 15%.

65

19. Captive power policy & cogeneration

i. Background :

Industrial sector is one of the largest consumers of electrical

energy in India. However, a number of industries are now increasingly

relying on their own generation (captive and cogeneration) rather than

on grid supply, primarily for the following reasons:

Non-availability of adequate grid supply

Poor quality and reliability of grid supply

High tariff as a result of heavy cross-subsidization

As a result, the captive and cogeneration potential has been

increasing over the years and it is estimated that nearly 30 per cent of

the requirements of the industrial sector is met from in-house

generation. Some of the recently published statistics indicate a captive

power potential to the tune of 12,000 MW and cogeneration potential

of 15,000 MW. Looking at the trends in generation capacity additions in

the public and private sector, the role and significance of captive and

cogeneration are expected to increase in the coming years.

The state governments and the state electricity boards (SEBs), aware

of their inability to meet the needs of the industry in the immediate

future have also been taking various policy initiatives to promote

66

captive power production and cogeneration. At the same time they are

also concerned with the impact of a high growth of captive power

production and cogeneration on the deteriorating finances of the SEBs,

the environment and the optimal growth of the power sector in the

long run. The policies adopted by different states, based on the

prevailing situation and their perceptions on achieving a balance of

interests, are, therefore, not uniform.

The captive power producers and cogeneration promoters by and large

do not appear to be happy with the present policy initiatives and have

been asking for increased incentives. The state governments and the

SEBs have been cautious in their response for reasons stated above.

With independent state electricity regulatory commissions (SERCs)

being set up in different states, the SERCs will now be concerned with

the approval for setting up captive power plants and third party sales.

A clear understanding of the concerns of both captive and

cogeneration owners and state governments /SEBs and an open and

objective discussion of the contentious issues assume importance in

this context.

ii. Concerns of State Governments/SEBs :

These include:

Captive and cogeneration plants may have adverse impacts on the

finances of the utility.

Industrial load is the main source for cross-subsidizing revenue

flows.

Billing and collection is much more efficient for HT consumers.

SEBs ability to service escrow accounts for security packages is also

reduced.

Non-optimal growth of the sector.

Problems in grid management especially in case of states with

surplus power.

67

Adverse environmental impacts arising from types of fuels used and

from higher emissions per unit of production, as compared to large

power plants

Reliability of power supply from captive and cogeneration plants as

a source of firm power.

Concerns of owners of captive and cogeneration plants:

Non-remunerative tariff structure for surplus power produced by

them.

No risk sharing in case of non-availability of fuel, change in variable

cost due to switching of fuel after entering into power purchase

agreement (PPA) etc.

Inadequacies in wheeling and banking facilities.

High contract demand charges.

High level of duties and taxes on sale of power.

High wheeling losses assumed for power to be sold to grid by

captive or cogenenerative plant.

Need to devote time and energy to an activity, which is not their

core business.

Restrictions on the minimum amount of power to be wheeled.

If the captive power plant (CPP) fails, charges for back up or stand-

by power from the grid are twice the normal rate for captive plants.

No formal policy for purchase of cogenerated power (in most of the

states).

iii. Captive power production:

Industries representing primary producers of infrastructure

material such as aluminum, cement, fertilizers, iron & steel, paper, and

sugar have significant captive capacity to meet a significant part of

68

their energy requirements. Notably, about 30 per cent of the electricity

requirement of the Indian industry is met from the in-house power

plants. Table 1 gives state-wise captive capacity and Table 2 shows the

captive contribution by various industries in India.

Table1: Captive contribution by state

StateInstalled Capacity (MW)

Captive Capacity (MW)

Andhra Pradesh 8204 1220

Assam 1078

Bihar 4656 614

Delhi 1436

Gujarat 8376 1505

Haryana 882 335

Himachal Pradesh

3570 32

Jammu & Kashmir

1536 3

Karnataka 3462 1045

Kerala 1766 151

Madhya Pradesh 7173 1333

Maharashtra 11072 570

Meghalaya 239

Orissa 3243 1544

Punjab 2620 311

Rajasthan 2176 528

Tamil Nadu 8271 1107

Uttar Pradesh 12473 1240

West Bengal 6515 786

Total 89167 12322

69

http://www.teriin.org/discuss/power/captive.htm#table2

http://www.teriin.org/discuss/power/captive.htm#table1

*includes coal, bagasse, cogeneration and other forms of steam

** includes diesel, LSHS, HFO, FO, HSD and similar fuels

IndustryCapacity (MW)

% Share

Cement 1223 9.9

Chemicals 2076 16.8

Electronics 59 0.5

Engineering 2479 20.1

Jute 207 1.7

Metals & Minerals

2404 19.5

Miscellaneous 784 6.4

Paper 473 3.8

Services 80 0.6

Sugar 706 5.7

Textile 1303 10.6

Unclassified 530 4.3

Total 12322 100.0

Cogeneration:

Cogeneration offers an attractive solution to meet the industrial

energy requirements in an efficient manner, while conserving the

national resources. Cogeneration is the simultaneous production of

power, either electrical or mechanical, and useful thermal energy from

a single fuel source. Cogeneration offers numerous direct benefits to

70

industry and institutional applications, but also positive carry-over

benefits to utilities and the society at large. The opportunities for the

industry, utilities, and the society are given below:

Cogeneration Opportunities

for Industry

Cogeneration

Opportunities for

Utilities

Cogeneration

Opportunities for Society

and Ratepayers

Reduce energy costs Defer capacity needsMore efficient use of

resources

Enhance revenues Reduce line losses Reduce emissions

Offer fuel flexibility Reduce risk Lower electricity rates

Protect the company from

power interruptions

Expand business

opportunitiesIncrease employment

Increase power quality Reduce utility debt

Offer short-up times

Reduce wastes

Traditionally, refineries, fertilizer plants and sugar plants have

cogenerated power and heat requirements for various industrial

processes, but without exporting to the grid. Given the suitability of

cogeneration to industry in India, the candidates for cogeneration

would include industries with substantial combined heat and power

requirements, such as sugar, textile, paper, fertilizer, food processing,

chemicals and petrochemicals. Cogeneration is already being practiced

widely in various industries such a pulp and paper, rayon, sugar,

chemicals, and fertilizers. The estimated potential of cogeneration is

between 17,000 to 20,000 MW, based on conservative estimates. It is

difficult to give an accurate figure as many small-scale industrial

71

applications and industrial estates may also have cogeneration plants

and no estimates are available for these areas.

Table 3: Cogeneration potential in India

Industry Potential (MW)

Alumina 59

Caustic soda 394

Cement 78-100

Cotton textile 506

Iron & steel 362

Manmade fibres 144

Breweries 250-400

Coke oven batteries 200

Commercial sector 175-350

Dairies 70

Distilleries 2900

Fertilizer 850-1000

Petrochemical 250-500

Plywood manufacturing industry

50

Rice mills 1000

Solvent extraction 220-350

Sponge iron 225

Tyre plants 160-200

Paper & pulp 850

Refineries 232

Sugar 5200

Sulfuric acid 74-125

Total 14628-15586

72

20. RENOVATION AND MODERNISATION

Renovation and modernization of old power plants can deliver

additional clean power, cheaper and faster. There are about 100 power

stations and over 150 units which can benefits from renovation and

modernization. By some estimates, R&M can create the equivalent of

4000 MW to 5000 MW of new capacity at a fraction of cost.

R&M exercises are good investments. The cost of reviving lost

generation is only about 20% to 40% of that of building a new plant of

equivalent capacity. The time taken can also be much less.

But despite the promise of cheaper and faster power, R&M

efforts at SEB owned plants have of late been negligible. The biggest

bottleneck is the shortage of funds as just about every SEB is in a poor

financial state.

In the 1980’s, R&M projects where pursued more vigorously. The

money came from the central government. Phase I of the R&M

programme (1984-1985 to 1992-1993) covered 164 stations adding up

to almost 14000 MW.

Phase II, however, has not been very successful. Very few

identified projects have actually taken off. The central government is

no longer providing the money to the same extent. The SEBs are in a

much worse condition.

The R&M approach is driven by the going in objective. The focus

can be:

To regain capacity lost due to plant aging and resultant

dreading;

To a great capacity to a higher output level;

73

To increase the efficiency of the plant operation by retrofitting.

Some times the objective of R&M efforts is to get more years out of a

power plant. These exercises are, appropriately, called life extension

programmes.

Regardless of the objective, an R&M programme will inevitably

entail improvements in one or more of the following areas:

1. boiler and boiler auxiliaries

2. turbines

3. coal handling plants

4. instrumentation and control

5. environment

6. development of new ash disposal area

The ministry of power therefore needs to refocus its attention on

R&M. The plants have already been identified. The private investors

are ready to come in. the SEBs, however, need help and direction.

R& M OF SUBSTATION AND TRANSMISSION LINES

To cope up with growing demand for power, construction of new

Transmission Lines and Sub-Stations is always a difficult proposition

due to various factors like high initial investment, approvals, ROW and

environmental concerns. R&M and upgradation of existing projects is

one of the cost effective alternatives to increase the power

transmission capabilities and reduce losses of a Transmission System.

The transmission line and substation voltage upgrading offer

considerable advantages. The conversion of transmission lines and

substations to higher voltages has emerged as a viable alternative in

meeting load growth or transmission requirements. This approach

offers several advantages. In addition to the practical aspects such as

use of available Right of Way (ROW) and substation site (i.e better

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utilisation of existing transmission system), the economic advantages

may be of considerable interest, particularly if some of the original

foundations, structure, or equipment can be used with minimal

modifications. The economic advantage is also linked with reduction in

losses. The ratio of specified substation insulation level to the rated

voltage decreases substantially with increasing system voltage level.

In other words, there are much higher margins with lower voltage

substation than with substation of higher operating voltages. Further,

with the availability of metal oxide surge arresters, there is

considerable opportunity for substation voltage upgrading in the

operating voltage range below 245 kV. To effectively implement

various such schemes, CEA Engineers gained knowledge in the

following areas during training/ familiarization on Technology

Improvement Program in Power Systems at Chicago, USA:

Residual Life Assessment of Sub-Station and Transmission Lines

Upgradation of Sub-Station and Transmission Line

GUIDELINES FOR UNDERTAKING RENOVATION AND

MODERNISATION (R&M) AND LIFE EXTENSION (LE) WORKS IN

RESPECT OF THERMAL POWER PLANTS.

1. For undertaking Life Extension works, plants need to be categorised

as the plants which have been under long shut down or are having

very low level of performance i.e. PLF below 40%, the plants which are

not having desired level of performance i.e. having PLF between 40%

to 60% and the plants operating at satisfactory level of performance

but the performance can be further improved/sustained (PLF) above

60%) with modernisation.

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2. In order to facilitate the implementation of R&M and LE works,

utilities may appoint consultant like NTPC, NLC, APGENCO, KPCL etc.

3. In respect of units operating at PLF below 40% :

A. The units which are under long (more than one year)

shut down, the decision to revive or scrap these units need

to be taken by the utilities in consultation with

Consultants. The recommendation for scrapping the unit

will be forwarded to the existing Standing Committee of

CEA for final decision.

B. For other units operating at a PLF up to 40%, the

performance of these units need to be improved by

adopting better O&M practices and by using essential

resources like spares, trained manpower etc. A suitable

consultant with long and proven track record to be

appointed by utilities at the earliest for introduction and

improvement of O&M practices. The deliverable for the

above exercises is to bring PLF of the unit to around 50%.

C. Performance of these units is to be further improved

simultaneously to around 65% PLF by adopting need based

R&M works.

D. Further improvement need to be attempted for Life

Extension and optimum PLF.

4. The units operating at PLF between 40% and 60% :

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A. Walk down exercise need to be done by CEA, NTPC

(consultant), BHEL and O&M engineers of utilities to

identify need based R&M works.

B. Performance of these units is to be improved by taking

measures as given in para '3-B' above. Also R&M works so

identified need to be taken up to improve the performance

of these units as close as possible to the design

parameters (name plate ratings)

C. Further improvement need to be attempted for the life

extension and attaining optimum PLF.

5. Units operating at PLF above 60% :

A. Efforts need to be made to further improve the

performance and sustain high levels of performance. The

utilities need to adopt latest O&M practices with the help of

reputed consultant like NTPC. Also life extension studies

need to be taken up to reduce cost of generation as well as

extend the life of the units, as a pro-active measure.

Typically, measures like improvement in heat rate,

reduction in auxiliary power consumption etc. need to be

attempted.

B. In case of on-going R&M and LE schemes as well as RLA

studies, being undertaken by the utilities with PFC funding,

these should continue to be executed as it is. These

schemes should continue to get the grant/interest subsidy

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loan under Accelerated Generation and Supply Programme

(AG&SP)

C. All the steps recommended for improvement in

performance and sustain high levels of performance in

respect of all the three categories mentioned above need

to be scheduled in such a time frame so that the entire

R&M/LE programme is completed within 10th Five Year

Plan. For successful implementation, the utilities may

adopt the following approach:

i) The power stations where BHEL has supplied the

main plant e.g. Boiler and TG (BTG) sets, the R&M work

may be awarded through negotiations with BHEL. BHEL

should ensure reasonable prices. Further, attempt should

be made to restrict the cost of LE works between Rs.0.8

and 1.25 Crores/MW depending on the quantum of LE

works. Utility shall accept the price negotiated by the

committee of CEA, NTPC and the Utility.

ii) The power stations where BTG equipment of

different make are installed, the utility may appoint

consultant such as NTPC, NLC, APGENCO, KPCL as per the

decision by the utilities.

iii) The utility shall prepare the R&M proposal,

including benefits in association with consultant and

submit the same to CEA for clearance and to PFC for

sanction of concessional loan under AG&SP. While

preparing the tender specifications for R&M/LE works, the

utility may stipulate only performance related guarantees

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such as plant capacity, heat rate, boiler efficiency and

stabilised operation for 1-2 years. The utility should not

stipulate guarantees for parameters such as PLF,

generation dependent availability etc.

iv) RLA & Life Extension works will be clubbed and carried

out simultaneously in one shut down by the appointed

agencies. For the Balance of Plant (BOP) equipment,

where no RLA is required, R&M work may be taken up

simultaneously. However, the consultant should ensure

that all BOP is covered under R&M programme.

RENOVATION, MODERNISATION & UPRATING OF HYDRO ELECTRIC

POWER PROJECTS

In the present scenario of resource constraint and to tide over the

shortage of electricity in the country, Renovation, Modernisation &

Uprating (RM&U) of the existing old hydro electric power projects is

considered the best option, as this is cost effective and quicker to

achieve than setting up of green field power projects.

The cost per MW of a new hydro electric power project works out to

about Rs. 4 to 5 Crores whereas the cost per MW of capacity addition

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through up-rating and life extension of old hydro electric power project

works out to about 20%. Further, the R&M of a hydro project can be

completed in 1 to 3 years depending upon scope of works as compared

to gestation period of 5 to 6 years for new hydro projects.

In order to augment the hydro generation and improve the availability

of existing hydro power projects, Government of India has put

emphasis on R&M of various existing hydro electric power projects in

the country as detailed below:-

Recognising the benefits of the R&M of hydroelectric power projects,

Govt. of India set up a National Committee in 1987 and a Standing

Committee in 1998 thereafter and have identified the

projects/schemes to be taken up for implementation under R&M. The

National Perspective Plan document for R&M of hydro electric power

projects in the country was also prepared in C.E.A. during the year

2000, incorporating the status of various projects/schemes already

identified for implementation/completion till the end of the XIth Plan,

i.e. the year 2011-12.

Under the hydro R&M programme, 61 hydro electric schemes (13 upto

the VIIIth Plan, 20 in the IXth Plan & 28 in the Xth Plan) with an

installed capacity of 10134 MW at a cost of about Rs.1693 crores have

been completed by the end of the Xth Plan (i.e by 31st March 2007) &

have accrued a benefit of 2246 MW. The State-wise lists of these R&M

schemes are given at Annex. I , II & III.

For the XIth Plan (2007-12), a total of 69 hydro R&M schemes having

an installed capacity of 12538 MW at an estimated cost of Rs. 3626

Crores are now programmed for implementation to accrue a benefit of

4377 MW. Out of 69 schemes, 36 schemes are already On-going. The

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state-wise lists of these R&M schemes are given at Annex IV (A) & IV

(B). Further, 14 nos. of hydro electric schemes having an installed

capacity of 2646.00 MW, which were originally programmed for

completion during XIth Plan, have now been shifted to XIIth Plan, as

utilities are not in a position either to carry out RLA studies or units are

running satisfactorily. After completion of the R&M works of these

projects, there may be a benefit of 2403.0 MW at an estimated cost of

Rs. 658.93 Crs.(provisional). The state-wise lists of these R&M schemes

are given at Annex V. Other hydro R&M schemes which are to be taken

up for implementation during XIIth Plan, will be identified and finalized

during the beginning of XIth Plan.

Plan-wise summary of hydro R&M projects in the country as on

31.03.2007 is as given below:-

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State wise List of Ongoing Hydro RM&U Projects programmed for

completion in the

XIth Plan (Phase I Projects* & Phase II Projects)

As on 31.03.2007

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21. RURAL ELECTRIFICATION

Rural electrification has two primary objectives. First, to improve the

economic status of the rural population by increasing the productivity

of human and animal labour and secondly, to promote rural welfare by

providing an environmental equal in comfort and convenience to that

enjoyed in urban areas.

Rural system: At present (1996) only about 35% of the total power

generated in India is consumed by over 70% of the country’s rural

population. Concentrated endeavor must be made to raise this

consumption to 50% of the total generation, which can serve as a good

index of India’s rural prosperity.

It is essential to provide low cost technology for rural

Electrification such as low loss distribution transformers without tap

changer and breather, outdoor sub-stations up to 66KV without a

control room building; 11KV gear; auto recloser(vacuum or SF6 or air

CB) with ac series trip with kiosk type for outdoor use etc.

b. Improvement of existing rural distribution system:

Poor power factor, high distribution losses and poor voltage conditions

in the rural system are generally because of the following factors:

Long and overloaded 11KV and sub transmission lines.

Low P.F of the agriculture tube well consumer installations

Absence of shunt compensation in the sub-transmission and

distribution system (required because of heavy inductive load of

agriculture).

Distribution of distribution transformer centers away from the

load centers.

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The main consideration in voltage regulation which is kept within

the usual stipulated limit as – 9%, + 6% for 11KV and 6% for LT as

prescribed by IE rule 54. The corrective measures for this are:

Rerouting the main link line of the feeder by the shortest route.

If rerouting is not possible, then the feeder should be studied for

bifurcation at suitable points with a view to transferring loads to

lightly loaded feeders.

Provision of shunt compensation on 11KV feeder can be made.

The problem of switching and over voltage can be avoided by

compensating only 25 to 30% of the KVARs on average load.

Wherever the distribution transformer is overloaded and additional

loads are anticipated the existing transformer can be replaced by

a higher voltage transformer, alternatively.

When the power transformer in the HT sub-station is fully loaded,

the augmentation of the transformer capacity can be carried out

either by installing an additional transformer or by changing the

existing transformer with a higher size unit.

Provision of new 11KV and LT feeders and distribution transformer

can be made.

Power factor at the load point can be improved considerably by

installing LT capacitor at the consumer premises.

Sparse or isolated villages with one or two 3-phase motor loads

may be electrified with single wire earth return system poses no

problems concerning voltage regulation.

22. POWER THEFT

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With the increase in consumers, persons

indulging in illicit abstraction of power and

tampering with the supplies equipment

have increased. Anti- social elements

exploit the inability of electricity under

taken to remain vigilant at all times.

The legal position against theft of

energy is covered by sections 3,20,39,44

and 50 of Indian electricity act and also the Indian electricity rules,

1956. Theft of energy is a cognizable offence.

Mode and Remedies:- The methods and means mostly employed in

theft of energy and remedies necessary to prevent its further

escalation are as follows -

Supply is tapped directly from the mains by hook rods. Presently

distribution wires are naked so instead of, insulated wires should

be used.

Supply is tapped from the supplier’s cutout which is before the

meter. Power utilities are now connecting the meter directly after

aerial fuse and before supplier’s cutout so that such pilferage is

also metered.

The link connecting the potential & current coils is opened

rendering the meter inoperative. Most electricity boards now link

the two inside the meter cover. In case of P.T.s, the P.T.s fuses

should be sealed properly.

In some cases the current coil is by passed with a loop .some

introduce a switch in the loop, so that they could allow the meter

to run or stop at will.

A fine small hole is made with the sharp edge or drill in the meter

cover & foreign matter like sticks are inserted through the hole

to arrest the disks. The sticks are not permanently left in the

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meter & are inserted as & when required to regulate the meter

reading.

Strong magnetic field near the disk can slow or stop meter.

Often unscrupulous consumers are helped by organized gangs

with know-how & expert knowledge there are persons who have

sealing pliers with inscriptions similar to the inscription used by

undertakings. These persons have some consumers as their

regular customers. They frequently break open the seals in the

meter, reset the meter reading backward and then reseal it.

Meters have now been developed with ‘reverse running stop’ and

the meter disk can not rotate and creep backward.

In the three phase service, one of the elements is connected in

the reverse, so that the meter would record only 1/3 of the actual

consumption.

In 1-phase services, the phase & neutral are connected vice

versa, so that the current coil is in a neutral circuit. Any load

connected between the phase and earth goes unmetered.

When supply is available in the same premises at two different

tariffs, the consumer can easily misuse by connecting

equipments intended for one to the other. The suppliers should

evolve the tariff in such a way that supply at two tariffs to one

premise should not be given.

Meters are tilted as some meters become slow or dead stop

when tilted vertically. Meter plumb fixing nuts-bolts or screws

should be under sealed cover.

Other measures are: keeping joint –free service lines, proper

sealing of metering equipment, and effective checking of

connections/meters.

THEFT PROOF SYSTEMS: There are places where large scale

theft of energy from power utilities is common. It is almost

impossible to exercise proper vigilance and enforce

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administrative measures to curb theft of energy in such regions

because they are crime and terrorist affected areas. Such places

are international border areas strips in Punjab and J&K. The

possible remedy is to develop a theft proof system which is

difficult to tap and which also involved the vigilance of the

consumers themselves. For tube-wells electrification within a

10KM belt of such international borders, only HT distribution

should be undertaken. For each tube-well motor, a 5KVA or

10KVA transformer should be installed and a connection should

be released on HT, i.e. 11KV or 22KV. Power utility should install

a11/0.48/0.24KV transformer at the cost of the consumer. If the

transformer is damaged, the consumer is liable to pay for the

cost of replacement. The tariff may be based on LT metered

supply or on the basis of transformer rating if flat rate tariffs

applicable. In this case the motors on the tube –wells can be 1-

phase 240V or 480V and the service cable should be laid by the

consumer himself. Such systems are in operation in western

countries for rural electrification.

Development of electric co-operatives: In rural areas, there is

large power theft from utility mains. The theft could be reduced if

the entire responsibility of distributing the power to individual

consumers is undertaken by village electric co-operative. The

consumer could draw the metered supply from the utility local

transformers at a tariff and then supply to there members in the

village on payment of a certain tariff. The bills would then be

collected by the co-operatives. Co-operatives can curb theft and

improve distribution efficiency as has been observed in the

working of about 50 of them working in AP. It will also be easier

to apply different period- of-day tariff by co-operatives for

consumers other than agriculture consumers.

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Totally electronic meters (micro-processor based) are tamper/

fraud-proof and must be put in service.

In-built provision of “Monthly Minimum Charges” should be made

in the tariff applicable to each category/ type of consumer based

on realistic consumption estimate.

Pilferage of energy can be detected through analysis of

individual consumer load curve, compared it with similar

consumers operating the same type of business during the same

period of time.

Large power consumers must be offered power at time of day (T

o D) metering, coupled with an adjusted tariff system consisting

of three rate levels-night, peak and daytime.

Controlling Electricity Theft and Improving Revenue

The state government of Andhra Pradesh, India launched a

campaign in January 2000 to control the theft of electricity from

government-owned power supply companies and improve their

revenue collection. The initiative, now in its fourth year, has

reduced losses, boosted revenues, and improved customer service.

The improvements seem likely to be sustainable: the utilities have

institutionalized new business processes and made visible changes

in their organizational culture. This Note reviews the experience.

23. Plant Load Factors (PLF)

While capacity has not increased substantially in recent years, the generation has improved somewhat more, largely because of the increased output from generators, with some increase coming from increased inter-region transfers. We can see below that the PLFs have improved markedly. While state plants have shown the most improvement, hey still lag behind central and private plants, which are both operating above 74% PLF.

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Many government documents show this as a positive trend, but a deeper analysis shows several issues. For starters, PLF is can not increase indefinitely, since there must be lower demand periods in a day when reduced output is required. What is disturbing is that official documents treat such normal backing down as “unplanned outages,” as if all thermal plants would operate at almost 100% PLF if possible. In fact, the metric of availability indicates reasonably healthy performance, with NTPC (the central PSU) showing an availability of close to 90%. In addition, increased output from thermal plants comes with increased marginal costs. As per the Planning Commission (2002), “The gap between the plant availability and plant load factor (PLF) indicates that thoughThe plants are available at 80% of the time; they are forced to back down in some of the states, particularly in eastern region, during the off-peak hours due to lower demand. Efforts need to be made to address this issue and utilize the plants optimally.” A deeper problem lies with the mistaken approach that PLF is the appropriate measure of performance. PLF of a system should mirror the demand. Given that the peak (capacity) shortfall is lower than the average (energy) shortfall, as the system improves, it is only natural that overall PLF should fall. In the US, the system-wide PLFs only about 53% (EIA-WEB updated periodically). One causative mechanism for the problem is that the tariffs for generators have been based on a normative PLF, 68.5% (for thermal stations). As long as they output this amount, they will make their stipulated returns, and increased output gives them a bonus (Tongia and Banerjee 1998). In fact, some regions are contracting for guaranteed PLFs of 80% (and asking for

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take-or-pay power purchase agreements), citing energy shortfalls. In a well-run system, dispatch rules should indicate which generators are operating based on real-time load. These should be economic decisions based on marginal costs, ideally. Instead, in India, contractual or political issues come up, and some operators refuse to back down, since that affects their profits (and “performance” metrics). This is why the frequency of the system can often go over 50 Hz, especially at night. What is required for such decisions to be made is a load duration curve, something utilities in India lack. UK numbers (Figure 2 below) indicate that all generators should not expect to operate at the same (high) PLF. The base load plants would be nuclear power, coal, some CCGT (if cheap gas is available), and hydropower (if extensive water is available). Peaking power would come from hydropower (especially pumped storage), oil, and simple cycle gas turbines. Intermediate power would come from a combination of gas and coal, depending on the situation. One difficult issue becomes comparing long term vs. short term marginal costs (Ellerman 1996). Once built, coal power is often cheaper than gas power, but gas plants cost much less to construct. So, higher load factors are often the norm for coal based plants, especially since these have long operating lead (ramp-up) times to come to full power. Unfortunately, correct methodologies are not followed when choosing gas versus coal plants in India, nor are correct planning methods used for PLFs for pricing purposes. In response to some of these issues, there is a recent move towards Availability Based Tariff (ABT), instead of the previous PLF based two-part tariff (fixed costs recovered at 68.5% PLF and variable costs at actual). ABT would give credit to generators even when they are asked to back down, and would penalize all groups(generators as well as consuming states) for deviating from the prescribed norms (supply or drawl). However, as the availability of a modern thermal plant is expected to be high (and invariably higher than the currently prescribed norms), this doesn’t help the pricing of the power. There are also other problems with ABT, briefly discussed later.

24. Players in generation distribution & transmission

National Thermal Power Corporation (NTPC) was incorporated in 1975 as a Central PSU, to enhance thermal power generation (largely coal). It is considered a professional and efficient organization, and has grown today 20,435 MW (excluding Joint Venture capacity of 314 MW), making it the 6th largest thermal generating company in the world. Its return on capital employed was over 11.9%, which is better than most utilities in the world (not all capital is equity, as, worldwide, most utilities are leveraged, i.e., carry debt). NTPC’s unaudited financials for

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2001-02 (off their website) indicate that revenues were Rs. 17, 911.04 crore and net profit was Rs 3,539.62 crore. NTPC’s thermal plants had a PLF of 81.1% (84.3% excluding the Eastern Region, which has low demand and limited export capability) (Ministry of Power 2002). NTPC will be a key player in India’s power sector, and is aggressively looking to expand its businesses, moving beyond not only thermal projects into hydropower, but also power trading and consultancy, and is even pursuing the distribution business.

The National Hydroelectric Power Corp. (NHPC) was established in 1975 to build large hydropower projects, but the growth has slowed and their installed capacity today is only 2,175 MW (Planning Commission 2002). The North-Eastern Electric Power Corporation, Ltd. (NEEPCO) was established in 1976 to develop power generation (hydro and thermal) in the northeastern region of the country, one that lags behind in terms of infrastructure development. NEEPCO contributes 700 MW of capacity in the region, which is 40% of the total. This company is profitable, but its role will remain regional and niche.

Central generating stations (or others that cater to multiple states) see their power sent over transmission owned by the Power Grid Corp. of India Limited (PGCIL). PGCIL was set up to help build up a national grid, and was actually a spin-off from NTPC (being incorporated in 1989 but beginning management of in 1991). PGCIL is responsible for all interstate power transfers, handling some 40% of the country’s power. The states (or their new corporations) still own their internal transmission. Generators like Independent Power Producers (IPPs) are either purely in-state or they too rely on PGCIL for transmission of their power. It is (self) reported to be the largest transmission companying the world, with over 40,000 circuitous km of transmission lines and connection to one third of the capacity in the country. In 2000-01, it had profits of Rs. 742 crore (≈US$ 165 M) On revenues of Rs. 2,683 crore (≈US$ 596 M). Thus, it saw a profit of almost 28% (!), which is quite high for a transmission company, especially one not operating in a market environment and able to use sophisticated financial tools. The focus today is on extending Extra High Voltage (EHV) transmission and strengthening inter-region transfers. It is also actively pursuing a telecom venture (as a Joint Venture), utilizing extensive optical fiber that was laid alongside its Rights of Way (for SCADA34 purposes). PowerGrid’s role is likely to expand significantly as a new Grid Code comes into force, envisioning greater use of transmission facilities.

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The Power Trading Corporation (PTC) was established in 1999, and 8% equity is to be held by each of NTPC, PGCIL, PFC, and NHPC (the first three have paid up as of 2002). Other shares are available to financial institutions and investors. Its vision is to help set up a power market and to “correct the distortions in the market.” The plan is to have mechanisms to trade electricity, but these would be paper trades since PTC is not a facilities operating company. Some of its trades are designed to be facilitated through the web, making this more like a B2B transaction than a spot market. The volume of transaction is very low, with a sizable fraction made of international (hydro) purchases resold in India. As per its website, it charges five paise/kWh (negotiable) for the transaction, and in the current (2002-03) financial year, it has traded over 3 billion kWh thus far. It remains to be seen what the impact of this company will be, not because of its own limitations, but rather the structure of the sector where most projects operate on bilateral, with Power Purchase Agreements, and where there is little surplus capacity.

The Rural Electrification Corporation (REC) was established in 1969 after the famines of the 1960s, with a mission to “facilitate availability of electricity for accelerated growth and for enrichment of quality of life of rural and semi-urban population.” However, it is not entirely modeled on the erstwhile US Rural Electrification Administration. REC provides loans for a variety of power sector projects, not only rural electrification but also specific projects like pumpsets, increasing the penetration density, etc. These are provided only to utilities, not end-users, and have terms of 7-10 years, at 10-12% rate. As of March 31, 2002, it had cumulatively disbursed loans of Rs. 24,687 crore to SEBs and utilities. These loans are at or just below market rates for infrastructure projects, but lower than what many project promoters would find available independently. In effect, REC helps consolidate and transfer risks, since the bulk of its own finances come from secured and unsecured loans, including from the Govt. of India. In 2001-02, REC sanctioned Rs. 6,764 crore of loans, and disbursed 4,722 crore of loans, with a pre-tax, pre-depreciation profit of 503 crore Rupees.

The Power Finance Corporation (PFC) was established in 1986 with the goal of becoming the primary development financial institution for power projects in the country, for central, state, and municipal PSUs, and is wholly owned by the Govt. of India. The funds from PFC are meant to be in addition to Plan expenditure, and are to be given on the merits of individual projects. PFC sanctioned 8,506 crore Rs. of projects in 2001-02, of which 5,150 Cr. were disbursed, and its profits before taxes were Rs. 950.4 crore. PFCs sources of money include domestic debt (60% in 2001-02),

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operating capital, paid up capital, bonds, term loans, and foreign currency loans. Most loans are given at attractive rates (lower than bank lending rates by several percent). Despite its strong performance, PFC can not meet the entire anticipated needs of the power sector as per its growth plans, even for government bodies.

25. Quality of Electricity

Utilities in India do not publish standard performance statistics, as they would bean order or two of magnitude behind acceptable norms. Standard metrics include

SAIFI (System Average Interruption Frequency Index), the average number of interruptions experienced by customers per year,

SAIDI (System Average Interruption Duration Index), the average number of interruption minutes experienced by customers per year,

CAIDI (Customer Average Interruption Duration Index), the average duration of an interruption, equal to SAIDI divided by SAIFI.

The US had averages of SAIFI – 1.26 interruptions per year SAIDI – 117 minutes of interruption per year

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CAIDI – 88 minutes average duration per interruption (Brown and Marshall 2001).

Clearly, the distributions have strong skew, since most people in the US don’t experience nearly two hours of downtime; some just experience much longer downtimes, especially in the winter due to storms. Instead of these, India uses a measure called loss of load probability (LOLP). LOLP is often allowed in the percent range, and even this is not met.In India, load-shedding is common in most of the country, with even the capitalNew Delhi facing several hours of rolling (controlled) outages per day during peak months. Agricultural supply is significantly curtailed, and the total downtime is likely to be measured in days, not minutes.One exception is Mumbai, which has largely had good power supply (and quality supply). The reasons have been not only institutional, with non-SEB utilities (Tatas, large private conglomerate, BSES, an established private player, and BEST, a municipal undertaking) providing power, but also technical. The city has enough capacity available to it internally, and can “island” itself from the rest of the state29 to ensure quality supply. However, such a fix will not be available in other parts of the country, making privatization more difficult.

26. Restructuring of the Indian Power Sector

Keeping in view the pros and cons of different restructuring processes in various countries, it is recognized easily that India is not yet ready for electricity restructuring. The first and major restructuring problem is the gap between demand and generation. Thus, this study suggests the following steps towards the restructuring of the Indian power sector:

Bridge the gap between power demand and electricity generation

Decentralize the planning process for an easy entry of generators

Increase the intrastate transmission lines Increase the tariffs incrementally Reduce the direct government control Establish an independent regulating authority

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Unbundled SEBs as generation, transmission, and distribution entities

Privatize and commercialize the power entities Establish a competitive power market.

The restructuring process as a whole is a very complex process, and steps suggested here are overlapping and interrelated. The first four steps will prepare a background for restructuring, i.e., after implementing phase one, India will be ready for restructuring in a real sense. Steps five to seven are part of the second phase, and steps eight and nine constitute the third phase. Many of the steps suggested here are already underway in India either directly or indirectly as part of ongoing reforms.These steps are further discussed as follows.

Bridge the Gap Between Demand and Generation To bridge this gap, the following measures could be taken. Tariff Setting. The current pricing method used by most utilities in the Indian power sector is the traditional cost-plus method. The cost-plus method starts with the identification of costs, which include the fixed costs related to capacity, the variable costs related to fuel, and other customer related costs. Then these costs are allocated as equitably as possible among consumers through the tariff structure. Typically, electricity prices in India are less than the cost of electricity production and substantially less than the cost to build and operate a new power plant. The poor power factor leads to the increased transmission and distribution (T&D) losses, thereby raising the cost of power delivery. Any analysis of power tariffs should consider both the structure of tariffs and the costing methodology for ratemaking. On the consumption side, energy pricing is a very important tool for demand side management, especially in the long run. Incentives should be established for maintaining a high power factor and for conservation during peak hours and seasons. This study suggests the introduction of a time-of-the-day metering. Develop an Integrated National Grid. The development of a national grid will lead to the better utilization of resources. The five existing REBs are not fully interconnected. The development and operation of the Indian power sector are at present limited to the regional level. The development of a national grid could avoid the generating capacity expansion by 2,784 MW with a total cost of $4,912 million for installation, fuel, operation, and maintenance. Further study shows that generation system reliability will also increase tremendously, and the expected unserved energy will decrease from 5158 GWh in REBs to 26 GWh in the case of the national grid.

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Decentralize the Planning Process for an Easy Entry of Generators

At present in India, it takes a long time for new private power projects to be approved and initiated. Previously, the independent power project (IPP) approval was through MOU, on behalf of the Government of India. Now as part of the reform process, the government has also started competitive bidding routes. The competitive bidding process involves the request for qualification (RFQ) and the request for proposal (RFP) stages. The competitive process takes much time currently and needs to be decentralized. Our study suggests the establishment of new functionary, i.e., the Regional Bureau of Investment Promotion in Power (RBIPP), which will be responsible for the approval of IPPs. RBIPP will be working as a government organization with autonomy and will merely report its activity to SERC. RBIPP will work with SERC to approve IPPs. IPPs will be encouraged to contact RBIPP of the region where they are willing to set up the project.

Increase the Interstate and Intrastate Transmission Lines Any reform to increase the generating capacity in India could be futile so long as there is an insufficient transmission capacity for transferring the added generated power to demand sites. Before embarking on the open electricity market, a sufficient transmission line capacity should be made available to avoid congestion. Thus, private investment for adding transmission capacity should be encouraged in India. The proposed RBIPP can work out a plan for adding transmission lines and then request bids for implementing the plan. The participation of the private sector in transmission system will be conceivably limited to the construction and the maintenance of transmission lines under the supervision of the Power Grid Corporation of India Limited (PGCIL) and RBIPP. Transmission charges payable to private owners will be directly proportional to the availability of transmission lines. Furthermore, special attention should be paid to the northeastern region of India where large potentials for hydropower exist for the foreseeable future.

Increase Tariffs Incrementally At present, the household electricity price in India is minute due to government subsidies. It is expected that restructuring would lead to higher electricity prices. It is critically important for the people of India to recognize that subsidies have resulted in a substantial loss to SEBs and to the economy as a whole, and SEBs’ financial conditions should be improved by a hike in household electricity prices. To have the support of the general masses for restructuring, the reform process should lead to lower prices for electricity. Thus, our study suggests that the government of India should increase the electricity prices in six-month steps (perhaps to a greater extent in urban areas and a lesser extent in rural areas) to the level that, when electricity markets are in

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operation, would lead to comparatively lower market prices for electricity.

Reduce Direct Government Control Current planning strategies in India are centralized and political. The political timeframe causes a mismatch between planning and the responsibility for its implementation, limits long-term thinking, and neglects the distribution system planning. Most of the already implemented restructuring models around the world limit the government’s involvement in the regulation and the co-ordination processes. Thus, the government role should be reduced in the restructuring of the Indian power sector, and most of the government functions like tariff setting, granting licenses, and taking care of the interests of consumers and investors should be delegated to independent regulators. This also involves limiting the government’s role in the planning and implementation of new resources, which currently involve many government functionaries in India.

Establish an Independent Regulating Authority

An independent regulator is already in place in India at the central level. There is also a need for establishing an independent regulating authority for the power sector at the state level. CERC, which was established in 1998 by the Electricity Regulation Commission Act, is charged with the responsibility of increasing the competition and efficiency in India. Electricity regulations that are issued by CERC can provide different reform measures for adding the competition and efficiency by allowing easy and transparent entries of participants in the interstate power market and grid under clearly defined principles and rules. A few states like Orissa, Haryana, and Andhra Pradesh have established SERCs already. Other states should start the process of setting up SERCs urgently.

Unbundle SEBs as Generation, Transmission, and Distribution Entities

The activities of an SEB should be broken into separate divisions, Which would operate on commercial principles or as separate profit centers. This step is relatively easy to accomplish, as it does not require any legislative actions or staff reallocations. The SEB’s activities can be divided into separate divisions based on their functional roles, i.e., generation, transmission, and distribution. It is possible to further subdivide the divisions. The generation business can be divided based on the nature of the generating plants, i.e., thermal, hydro, nuclear, nonconventional, etc. The distribution business can be divided on geographical lines into zones of manageable size. The divisions must operate as separate profit centers with a full financial

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autonomy and functional independence. Many states in India are in the process of unbundling; however, this process must be implemented more unilaterally.

Privatize and Commercialize the Power Entities It is well recognized that reforms cannot be meaningful unless the competition and the privatization are initiated. The central government must, therefore, break up its generating PSUs into smaller companies and introduce measures to enable the competition amongst these companies. Generation companies will be responsible to participate in an open market for trading power, which will be created by the unbundling of SEBs.

Establish a Competitive Market The central government has to take initiatives to set up the wholesale power market, create an electricity pool and enforce market-like competitive pressure. The power markets operating in different parts of the world include: monopoly model, single buyer model, bilateral contract, pool co model, and hybrid model.In a single buyer model, a single entity purchases the power from all generators on a competitive basis. This is the simplest model, but buyers do not have any incentive to seek out the most economical source of supply the bilateral contract model allows generators to have direct contracts with distributors and large consumers without an intermediary. This model requires an open access to transmission lines, which leads to a complex transmission system development, concerns for access costs, and critical regulatory control on transmission access.The pool co model envisages different generators to sell owner to a pool and distributors or large consumers to buy room the pool. This model also requires open access on transmission lines. The hybrid model is a combination of power pool and bilateral contract model. The choice of an appropriate market structure for India has to be necessarily related to the present operating environment and the extent of competition that is feasible/desirable for India. Our study suggests applying the single buyer model at the state level, which consists of one agency to buy all the necessary power. This agency will be the upshot of the unbundling of REBs. The single buyer model will ensure better coordination in transmission system planning and a uniform tariff throughout the state. By applying this model, REBs will be able to either follow contractual commitments made with various generating companies or renegotiate the existing agreements. In the future, the single buyer model can gradually evolve into a power pool model, with a provision for a hybrid model in which bulk consumers will be allowed to acquire power directly from generators.

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27. DISTRIBUTION AUTOMATION

Definition:

Distribution automation is an integral concept for the digital

automation of distribution substation,feeder.

The demand on electric power supply in India has changed drastically,

both qualitatively and quantitatively. With increasing development, the

dependence on electric power supply has increased considerably.

While demand has increased, the need for steady power supply with

minimum power interruption and fast fault restoration has also

increased. To meet these demands, automation of the power

distribution system needs to be widely accepted. To cope with the

complexity of the distribution network, the latest computer,

communication and distribution technologies need to be employed.

At the same time, specialized software package developed in-house or

out-houses by the utilities and other institutions must be usefully

selected. Distribution automation (DA) is an integrated concept for the

digital automation of distribution substation, feeder and user functions

it includes control, monitoring and protection of the distribution

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system, load management and remote metering of consumer loads.

The distribution automation contains:

Computer hardware

Computer software

Remote terminal units (RTUs)

Communication systems

Consumer metering devices

The benefits of DA are:

Improved quality of supply

Improved continuity of supply

Voltage level stability

Reduced system losses

Reduced investment

The distribution automation system provides automatic resoling of

relays, automatic feeder switching and provides remote metering and

controlling of distribution equipment (transformer, capacitors,

breakers, sectionalize, communication nodes etc.) from substation up

to an including the consumer interface. It affords the utility in

minimizing outage time and ultimately, better consumer service and

lowering of the total delivered cost of electricity.

It allows operation of the system with less capacity margin. The

technical aspects of distribution automation are complex and need a

thorough examination for there planning.

DA means something different to each utility, and functionally, there is

n industry standard. The various functions can be:

Electrical network analysis

Work management

Trouble call analysis

Consumer load monitoring

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Intelligent remote metering e.g. automatic meter reading etc.

Automated capacitor control

Substation automation

Intelligent electric devices

Advanced remote terminal units

Computerized power distribution relays

Power quality monitoring

Automated mapping (AM)/Facilities management (FM)/Geographical

information system(GUIs)

Energy management

As work forces are being cut, and consumer expectation

and demands are rising, automation becomes essential to system

maintenance and improvement of consumer service. Some

standards for various distribution automation functions such as data

formats, communication protocols etc., are now beginning to

emerge. The distribution automation system is also referred to as

the distribution management system (DMS).

28. Solid state transformers

It uses pulse width modulation to achieve ac voltage regulation without

the need for large inductors. At present, below 11 KV voltages, solid

state transformers based on bidirectional switch mode technology

efficiently transform voltages and can also perform voltage and current

wave shaping. They can be more compact, have improved thermal

management, and be insensitive to DC current components such as

the troublesome ones from geomagnetic storms.

29. High Voltage Direct Current (HVDC) Transmission

Systems Technology

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Beginning with a brief historical perspective on the development of

High Voltage Direct Current (HVDC) transmission systems, this project

presents an overview of the status of HVDC systems in the world

today. It then reviews the underlying technology of HVDC systems, and

discusses the HVDC systems from a design, construction, operation

and maintenance points of view. The project then discusses the recent

developments in HVDC technologies. The project also presents an

economic and financial comparison of HVDC system with those of an

AC system; and provides a brief review of reference installations of

HVDC systems. The project concludes with a brief set of guidelines for

choosing HVDC systems in today’s electricity system development.In

today electricity industry, in view of the liberalisation and increased

effects to conserve the environment,

HVDC solutions have become more desirable for the following

reasons:

Environmental advantages

Economical (cheapest solution)

Asynchronous interconnections

Power flow control

Added benefits to the transmission (stability, power quality etc.)

Historical Perspective on HVDC Transmission:

It has been widely documented in the history of the electricity industry,

that the first commercial electricity generated (by Thomas Alva Edison)

was direct current (DC) electrical power. The first electricity

transmission systems were also direct current systems. However, DC

power at low voltage could not be transmitted over long distances,

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thus giving rise to high voltage alternating current (AC) electrical

systems. Nevertheless, with the development of high voltage valves, it

was possible to once again transmit DC power at high voltages and

over long distances, giving rise to HVDC transmission systems. Some

important milestones in the development of the DC transmission

technology are presented in.

Some Important Milestones in the Development of HVDC

technology:

Hewitt´s mercury-vapour rectifier, which appeared in 1901.

Experiments with thyratrons in America and mercury arc valves

in Europe before 1940.

First commercial HVDC transmission, Gotland 1 in Sweden in

1954.

First solid state semiconductor valves in 1970.

First microcomputer based control equipment for HVDC in 1979

Highest DC transmission voltage (+/- 600 kV) in Itaipú, Brazil,

1984.

First active DC filters for outstanding filtering performance in

1994.

First Capacitor Commutated Converter (CCC) in Argentina-Brazil

interconnection, 1998.

First Voltage Source Converter for transmission in Gotland,

Sweden ,1999.

There are many reasons as to why HVDC was chosen in the above

projects.A few of the reasons in the selected project are

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Rationale for Choosing HVDC

There are many different reasons as to why HVDC was chosen in the

above projects. A few of the reasons in selected projects are:

In Itaipu, Brazil, HVDC was chosen to supply 50Hz power into a

60 Hz system; and to economically transmit large amount of

hydro power (6300 MW) over large distances (800km)

In Leyte-Luzon Project in Philippines, HVDC was chosen to enable

supply of bulk geothermal power across an island

interconnection, and to improve stability to the Manila AC

network

In Rihand-Dadri Project in India, HVDC was chosen to transmit

bulk (thermal) power (1500 MW) to Delhi, to ensure: minimum

losses, least amount right-of-way, and better stability and

control.

In Garabi, an independent transmission project (ITP) transferring

power from Argentina to Brazil, HVDC back-to-back system was

chosen to ensure supply of 50 Hz bulk (1000MW) power to a 60

Hz system under a 20-year power supply contract.

In Gotland, Sweden, HVDC was chosen to connect a newly

developed wind power site to the main city of Visby, in

consideration of the environmental sensitivity of the project area

(anrchaeological and tourist area) and improve power quality.

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In Queensland, Australia, HVDC was chosen in an ITP to

interconnect two independent grids (of New South Wales and

Queensland) to: enable electricity trading between the two

systems (including change of direction of power flow); ensure

very low environmental impact and reduce construction time.

Price variation for an AC transmission compared with an HVDC

transmission for 2000 MW is presented below.In this figure we observe

that upto 700 Km the price of DC is higher than that of AC.But after

700 km the AC transmission system is comparatively cheaper than that

of DC.It is very clear from the following figure.

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Itaipu the world's largest HVDC transmissions system has

pecial features:-

1. Transmission at +/-600kv Dc.

2. Total rated power of 6300 MW.

3. It consists of two bipolar DC lines.

4. Connecting hydro power plant in Itaipu to Sao Paulo.

5. Connecting 50hz network to 60hz network.

The diagram below illustrates the cost differences between 765 kV AC,

500 kV DC and 800 kV DC. The example is for a 2 000 km long line to

transmit 6000 MW.

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Overview of HVDC Applications:

Overview of HVDC Applications:

30. Flexible AC Transmission System (FACTS)

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Flexible AC Transmission Systems (FACTS) technology is an evolving

technology based solution for power transmission at small additional

investment with a short gestation period. The IEEE has defined FACTS

as “Alternating Current Transmission Systems incorporating power

electronics based and other static controllers to enhance controllability

and increase power transfer capability”. Thus FACTS increases the

flexibility of power systems, makes them more controllable and allows

increased utilization of existing network closer to its thermal loading

capacity without jeopardizing the stability. FACTS technology can boost

power transfer capability in stability limited systems by 20 - 30 %. By

this process not only is there increase in capacity but also cost savings

in design and installation.

It provides increased stability, improved voltage regulation, reactive

power balance and also improves load sharing between parallel AC

transmission lines. The other advantages include damping of inter-area

oscillations and mitigation of sub-synchronous resonance. This

technology regulates the reactance of a line or voltages at both line

ends or angle difference between the line ends or any combination of

the three parameters by fast acting switches.

A FACTS Project under R&D, which envisages installation of Fixed

Series Capacitor and Thyristor Controlled Series Compensation, has

been taken up at Ballabhgarh end of the 400 kV Kanpur- Ballabhgarh

S/C line of Power Grid. The project has been executed in two phases.

Phase-I covers design, development, supply, erection and

commissioning of the fixed part of series capacitor bank of 35%.

Phase-I was commissioned in April 2002 and has been performing

satisfactorily and with this there is increase of about 120 MW in power

carrying capacity of the line. Phase-II, which covers design,

development, supply, erection and commissioning of Thyristor

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Controlled Series Compensator with range of 8 to 20% has been

commissioned and charged successfully on 29th November 2004.

EHV AC TRANSMISSION SYSTEM

Standardisation of 800 kV and 400 kV Transmission Systems

Standardization of the parameters and specifications of major items of

400 kV and 800 kV substation equipment and transmission line

materials was carried out by CEA. The standing EHV committee has

been revived to review the standardization of the parameters and

specifications in respect of 400 kV & 800 kV transmission line and

major substation equipment. Revision I of Report on 800 kV Sub-

Station and Transmission Line material was issued in December 2002.

31. SCADA SYSTEMS

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What does SCADA MEAN?

SCADA stands for Supervisory Control And Data Acquisition. As the

name indicates, it is not a full control system, but rather focuses on the

supervisory level. As such, it is a purely software package that is

positioned on top of hardware to which it is interfaced, in general via

Programmable Logic Controllers (PLCs), or other commercial hardware

modules.

SCADA systems are used not only in industrial processes: e.g. steel

making, power generation (conventional and nuclear) and distribution,

chemistry, but also in some experimental facilities such as nuclear

fusion. SCADA systems used to run on DOS, VMS and UNIX; in recent

years all SCADA vendors have moved to NT and some also to Linux.

In a distribution network, computerization can help manage load,

maintain quality, detect theft and tampering, and thus reduce system

losses. The biggest benefit, however, of computerization is

centralization of data collection. At a centralized load center, data such

as current, voltage, power factor and breaker status is tale metered

and displayed.

This in turn, would lead to improvement in voltage profile, reduction in

power loss, improvement in reliability, quick detection of fault and

restoration of service.

A key feature of these systems is the remote control facility that allows

faster execution of decisions. The system also helps in eliminating

manual errors and over sights.

Distribution automation combines distribution network monitoring

functions with geographical mapping, fault location, and so on, to

improve availability.

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Supervisory control and data acquisition (SCADA) refers to a system

that enables an electricity utility to remotely monitor, coordinate,

control and operate distribution components, equipments and devices

in a real time mode from a remote location with acquisition of data for

analysis and planning from one central location.

Therefore, the purpose of SCADA is to allow operators to observe and

control the power system. It supports both energy management and

distribution automation.

The specific tasks of SCADA are:

Data acquisition which provides measurements and status

information to operators.

Trending plots and measurements on selected time scales.

Supervisory control, which allows operators to remotely control

devices such as circuit breakers and relays.

Distribution automation through SCADA systems directly leads to

increases reliability of power for consumers and lower operating costs

for the utility. It results in forecasting accurate demand and supply

management, faster restoration of power in case of a failure and

alternative routing of power in an emergency. Distribution automation

through SCADA also reduces human influence and errors.

Initiatives in India

Rajasthan:

The erstwhile Rajasthan state electricity board (RSEB) is the first

state electricity board in the northern region which has a full fledge

SCADA in operation. RSEB’s SCADA system has 30 remote terminal

units (RTUs) installed at remote stations with two dual data

concentrator (DDC) and other computer equipment installed in

Heerapura.

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The first phase of installation of the system, consisting of one

DDC and twelve RTUs, was completed in February 1992 covering the

Heerapura 400kv/220kv grid sub station and eleven other 220kv grid

substations and generating stations located within the state. Four more

stations where commissioned in 1993. The online of about 15 stations

is also being telemeter to the northern region electricity board (NREB)

at New Delhi. Later, to cover all 220kv substations and Hydel

generating stations, 1 DDC and 15 stations where e, to cover all 220kv

substations and Hydel generating stations, 1 DDC and 15 stations were

added to the scheme in 1994.

RSEB is in the process of upgrading this scheme by adding 26

RTUs, 3 DDCs and a LAN-based computer system at the load dispatch

centre at 1 Heerapura and remote display terminals at the board

secretariat.

Tamil Nadu

A SCADA system covering all the substations in Chennai was

recently inaugurated at the Tamil Nadu Electricity Board (TNEB).

Installed at a cost of Rs.191.3 million through an ADB-assisted project,

the system helps TNEB monitor and control the substation from a

centralized location. A distribution control centre has been established

at the TNEB headquarters for this purpose.

Andhra Pradesh

Andhra Pradesh is in the process of developing a SCADA system

for effective control and monitoring of distribution load at Hyderabad

and Secunderabad. Spread over an area of 1500 sq.km. The network

comprises about 20 EHV stations and 100 33/11kv stations.

Other states such Uttar Pradesh and Haryana also plan to set up

SCADA systems for there key distribution networks.

The Hurdles

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The biggest hurdle in the installation of SCADA system is there

cost. The cost of complete automation suites for a major city may

range from Rs.300 million to Rs.500 million. Another limiting factor is

the quality of existing communication network.

32. STEPS TOWARD REFORM (SUGGESTIONS)

India’s power sector is undergoing broad reforms, not only unbundling the previously vertically integrated monopolies (the State Electricity Boards) and opening up the sector to competition, it is also moving towards a significantly reduced role of the government. The roles that remain will be of regulator, stakeholder, and financer (especially for rural electrification), but not operator. The drivers for the reforms have been such a significant deterioration in SEB finances and operating parameters that there is a political will to do whatever it takes to fix the problem. Part of this was a tacit acceptance of the poor power situation as a failure of governance. The initial reforms (1991 onwards) focused on generation (and private players), but this did not lead to any significant increase in capacity. Since the mid 1990s, reforms have been focused on structural changes in the system, with the establishment of independent regulators, and unbundling of the SEBs. There is a current thrust on improving distribution systems, reducing the high technical and commercial (theft) losses that take away some 30% of net generated power in the country. Equally importantly, there is an attempt at tariff rationalization, without which the long term viability of the system will be suspect. As India is a diverse nation and different states move ahead differently, and at varying speeds. Some general trends that can be seen are:

In the first phase, the Indian government should establish an appropriate background needed for restructuring, which involves bridging the gap between power demand and generation, decentralizing the planning process, increasing the number of transmission lines, and increasing the tariffs in steps.

In the second phase, the direct government control should be reduced, SEBs should be unbundled, and an independent regulator should be established.

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In the third phase, the privatization and commercialization of newly formed entities should be considered, and a free electricity market should be established.

Establishment of an independent Electricity Regulatory Commission Attempts to rationalize tariffs Directives to lower losses (especially theft) Moves towards unbundling the system, with privatization of

distribution a possible goal Eventual moves towards a power market, driven by national

legislation instead of state initiatives.

It is too early to tell how successful the reforms have been, and they can best be described as necessary but not sufficient steps. In the last few years, the T&D losses have stabilized somewhat, but there is only limited interest of private players into the sector, especially new players. Those who state that overall financial losses have increased after the reforms do not factor in the increase in costs due to generator price increases regardless of reforms, even from government generators and PSUs. The next five years will likely be critical when determining the health of the power system, especially with the passage of dramatic legislation like the Electricity Bill 2001, which opens up the sector to private participation with limited approval obligations. This sector is vital to India’s growth and development, and reforms have addressed several of the shortcomings like efficiency, losses, etc. At the same time they have not sufficiently addressed structural changes for grid operation and discipline Dispatch), such as based on load duration curves, or access and penetration for the poor (especially how that affects financial performance). Nonetheless, they are a step in the right direction, ending years of government control and mindset. We do not suppose, prior, that government corporations will perform worse than private companies, but having all of them competing to perform better will only help the consumer and the sector as a whole.

33. Power Sector Reform in China

The Chinese electricity industry was born in 1882. It grew gradually through wars and regime changes in the next 60 years. By 1949 when the People’s Republic of China was founded, the country had a small electricity system with 1.85 GW installed capacity and 6,500 km transmission lines. Electricity system expanded rapidly over five decades to fuel the country’s massive industrialization effort. Between 1953 and 2000, installed capacity grew continuously at n average annual rate of 11.5 percent. The growth was particularly significant

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after the mid 1980s because of surging demand for electricity and increased investment associated with market economic reforms. By the late 1990s, the expansion fundamentally changed the chronic nationwide electricity shortage. The Chinese electricity system now is the world second largest with 338 GW installed capacity and 1478 TWh generation in 2001.The Chinese electricity industry has undergone rapid changes since the 1980s. Important reforms were carried out in the mid 1980s and late 1990s to address evolving issues of lack of financing, inefficiency and, to some extent, environmental damages. The central government is now beginning to implement the reform to de-integrate utility companies and create competitive wholesale markets as it continues to face the impediments to long-term system development. The electricity industry reform is embedded in a broader and more profound reform to transform the country’s centrally planned economy into a market economy. Economic growth and demand for power released by this broader reform and significant difficulties of the transition have been both a driving force of and constraint to the electricity industry reform.Experience so far suggests several potential difficulties that future utility market reform may face.

Financing capacity expansion under competitive market is vital because adequate capacity is the basic condition for other reform efforts. The reform practice since the 1980s shows that developing adequate capacity always dominated other objectives. Efficiency improvement, competition and environmental protection would not be urgent reform objectives until the gap was closing in between electricity demand and supply. Likewise, a turn from surplus to shortage would easily shift the reform focus back to capacity expansion. While the government effort to raise capital was successful in the past, relying on financial markets for investments in a competitive generation market is untested and may be difficult.

Balancing central planning and market competition is challenging. On one hand, the practice of central planning was a significant source of inefficiency in the electricity industry. Many projects developed or being developed under central planning may not be commercially viable in a competitive wholesale markets. Many may be exempt from competition or receive subsidies, at least for an extended period of time, limiting the scope of the market and competition. On the other hand, given a weak private sector and backward financial market, government may need to plan and invest in some energy infrastructure, which is of public good in nature.

Reform of Institutions of central planning is important and will be hard. The institution developed to facilitate central planning is in

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many ways incompatible with market competition. Changing current planning organization which causes regionalism and repositioning government from the decision maker to the impartial market supervisor is politically difficult and will be a prolonged process.

Policies are needed to help solve social issues associated with electricity sector reform. Environmental protection and social equity are evolving issues with electricity industry expansion and market reforms in China. To the extent that market competition does not deal it these social issues well, the government needs to make better public policies along with he utility market reform.

Reasons for success

To the extent financing is one of the difficulties in many developing countries, the success of the Chinese reform to raise capital many be attributed to two major factors. China’s domestic saving rate, at over 40% GDP, boasts one of the highest in the world. The high domestic savings constituted a strong domestic source of investment finance in the forms of bank loans, government bonds and power company equities. They financed $89 billion of $101 billion electricity sector fixed asset investment (89%) between 1996 – 2000, with foreign investment accounting for the residual.

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In addition to large domestic savings, the centrally planned institution and social political structure, which give the government the dominant control over the economy, enabled it to implement its reform policy and direct investment financing effectively. As electricity shortage became the bottleneck of economic growth, the central government was able to use its control of the banks, limited bond and stock markets to invest in the electric power projects. It was also able to raise endures prices with minimal resistance because state-owned enterprises and other forms of public companies constituted a major part of large endusers.9 And, unlike countries such as India, consumers were not organized as interest groups to influence government policy making.

34. Renewable Energy

Modern applications of renewable energy have grown steadily over the last 25 years. Led by solar photovoltaic and wind sources, these “new” renewables account for 20–25

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percent of the US $110–150 billion invested annually in power generation worldwide. The heightened role of renewables reflects a significant scaling up of investments traceable back to the late 1970s. The decade 1995 to 2004 witnessed a further acceleration with annual investments growing from about US $6 billion to nearly US $30 billion. Environmental quality, the climate change issue, energy access and security, and sustainable development are among the key drivers of growth.

Despite the rapid expansion of their role in the energy sectors of developing and industrialized economies, modern renewable energy technologies account for less than 5% of global power sector capacity. Widespread adoption of renewables is constrained by a multitude of policy, regulatory and financial barriers and gaps. The renewable energy work of the Energy Branch is directed primarily at uncovering innovative solutions to these constraints, and nurturing the replication of best practices. This work is necessarily multi-dimensional in scope, involving the coordinated deployment of several interventions including: channeling services and capital resources for investment in small and medium energy enterprises; supporting research and development efforts that enhance knowledge about the environmental and sustainability benefits of investments in renewable energy markets and industries; and building capacity of energy and development policy-makers in the design and deployment of renewables-friendly policies.

As a participant of the recently established Renewable Energy Policy Network for the 21st Century (REN21), UNEP is committed to fostering the rapid expansion of renewable energies in developing and industrialized economies. The Energy Branch partners with a broad spectrum of stakeholders in this effort, including industry associations, governments and NGOs, financial institutions and the private sector.

Current Activities

Rural Energy Enterprise Development (REED)

The REED approach offers rural energy entrepreneurs a combination of enterprise development services and start-up financing. This integrated financial and technical support allows entrepreneurs to plan and structure their companies in a manner that prepares them for growth and makes eventual investments by mainstream financial partners less risky.

Sustainable Energy Finance Initiative (SEFI)

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http://www.ren21.net/

SEFI provides current and targeted information to financiers while facilitating new economic tools that combine social and environmental factors - both risks and returns - as integral measures of economic performance

Indian Solar Loan Programme

This is a four-year effort to help accelerate the market for financing solar home systems in southern India. The project is a partnership between UNEP, UNEP Risoe, and two of India's major banking groups - Canara Bank and Syndicate Bank.

Solar and Wind Energy Resource Assessment (SWERA)

SWERA is developing the information and analytical tools to help developing countries more fully understand their available renewable energy resources. This will in turn help governments to develop progressive energy policies and programmes that can increase investment in renewable energy infrastructure.

RETScreen - Renewable Energy Technology Screen

RETScreen is a pre-feasibility analysis software for renewable energy projects. UNEP is working with Natural Resources of Canada (NRCan) to increase the awareness and enhance the usefulness of RETScreen internationally, including a greenhouse gas emissions (GHG) mitigation modeland an international training course on RETScreen. The software, available free of charge from the link above, can be used to evaluate the annual energy production, costs and financial viability of renewable energy technologies.

eCARE

With funding from the United Nations Foundation, UNEP launched e-Commerce and Renewable Energy (eCARE) in December 2005 as a 3-year initiative in partnership with Telecom Management Partner, a subsidiary of Telenor. The purpose of eCARE is to accelerate the extension of clean energy and modern telecommunications services to rural and peri-urban users. It is realizing this result by enabling small entrepreneurs to establish rural business centers (RBCs) that sell voice telephony, internet connectivity and clean energy products and services to rural and peri-urban customers. Selected entrepreneurs receive a combination of enterprise development services and start-up financing for their RBCs. The initiative is managed in-country by Ghana

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http://swera.unep.net/swera/index.php

http://www.uneptie.org/energy/act/fin/india/index.htm

Telecom, the main telecommunications service provider in Ghana. Kumasi Institute of Technology and Environment (KITE), a national NGO, identifies and trains prospective entrepreneurs in collaboration with field staff of Ghana Telecom. A local financial institution--Ghana Commercial Bank (GCB)--manages an investment facility set up under the project to meet the seed capital requirements of qualified entrepreneurs.”

Better Environmental Sustainability Targets (BEST) For Lead Battery Manufacturers

Lead batteries are an integral part of small-scale photovoltaic solar energy systems. However, lead emissions from battery manufacturing and illegal recycling are a major cause of lead poisoning throughout the developing world. UNEP supports an international partnership that is developing an environmental recognition program for lead battery manufacturers who meet minimum performance standards and agree to take back used batteries for environmentally sound recycling. Under this program major battery companies, bulk purchasers, government, and NGOs are creating a Better Environmental Sustainability Targets (BEST) standard and associated eco-label that will give certified manufacturers a growing market advantage

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http://www.okinternational.org/lead.html

http://www.okinternational.org/lead.html

Reform in different states

35. Uttar Pradesh

UTTAR PRADESH ELECTRICITY REGULATORY COMMISSION

Keeping the restructuring of the power sector in mind, the Government

of Uttar Pradesh has enacted the U. P. Electricity Reform Act 1999 and

has set up the U. P. Electricity Regulatory Commission (UPERC).

OBJECTIVES

That electricity will be supplied under the most efficient

conditions in terms of cost and quality to support the economic

development of the state of Uttar Pradesh.

Power sector would cease to be a burden to the state's budget

and would eventually become a net generator of financial

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resources.

Protection of Interest of Consumers

FUNCTIONS

The Commission is responsible for the discharge of the following

functions:

1. To regulate the purchase, distribution, supply and utilization of

electricity, the quality of service, the tariff and charges payable

keeping in view the interest of the consumer as well as the

consideration that the supply and distribution cannot be

maintained unless the charges for the electricity supplied are

adequately levied and duly collected.

2. To promote efficiency, economy and safety in the use of

electricity in the State, including and in particular, in regard to

quality, continuity and reliability of service, the standard of

performance by the units engaged in the electricity supply

industry in the State, the efficient utilization and conservation of

energy, appropriate demand side management and reduction of

wastes and losses in the use of electricity and to enable all

reasonable demands for electricity to be met.

3. To issue licences in accordance with the provisions of the Act and

determine the conditions to be included in the licences.

4. To regulate the working of the licensees and to promote their

working in an efficient, economical and equitable manner.

5. To regulate the assets, properties and interest in properties

concerning or related to the electricity industry in the state.

6. To aid and advise in matters concerning electricity generation,

transmission, distribution and supply in the state.

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Uttar Pradesh

A score of 42.83 has been assigned to the power sector in Uttar

Pradesh. This assessment is predominantly based on information

available/made available till August 2002.

The distribution of scores against the parameters is as follows:a

The State Government

The Government of Uttar Pradesh (GoUP) was one of the first States in

India to initiate reforms in the power sector through the enactment of

the UP Electricity Reforms Act, 1999, following which the erstwhile

Uttar Pradesh State Electricity Board (UPSEB) was trifurcated into three

corporations viz. Uttar Pradesh Power Corporation Ltd. (UPPCL), UP

Rajya Vidyut Nigam Limited (UPRVUNL) and UP Jal Vidyut Nigam

Limited (UPJVNL). The trifurcation of the UPSEB was accompanied by

the financial restructuring of the State’s power sector utilities involving

a write-off of liabilities worth around Rs. 190 billion. The GoUP

constituted its Electricity Regulatory Commission (ERC) in September

1998, and has largely adhered to the subsidy support that is required

to be provided to the utilities according to the Financial Restructuring

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Plan (FRP) approved at the time of the restructuring. While the GoUP

signed a MoU with the GoI in February 2000, the progress against

certain key parameters, like 100% metering of consumers,

computerisation of billings in certain select cities, and formation of

profit centres in distribution, has not been satisfactory. Yet another

failing of the GoUP has been its inability to ensure that Government

Departments pay their dues for energy consumed; the UPPCL

estimates its collection efficiency from Government Departments at

56% for 2001-02 .Uttar Pradesh State Power Sector scoring has also

been constrained by the unsatisfactory position of the Uttar Pradesh

Government finances, which in fact has led to the State’s equity

support to the utilities being inadequate, vis-à-vis the terms of the FRP.

ERC

The functioning of the Uttar Pradesh Electricity Regulatory Commission

(UPERC) is one of the positives of the State’s power sector. The UPERC

is fully operational, and its staffing strength and pattern, as well as its

revenue sources are adequate. The UPERC has already passed two

tariff orders: the first order (for 2000-01) was passed in July 2000, and

the second (for 2001-02) in September 2001. The delay has primarily

been on account of the inadequacy of the data furnished by the UPPCL;

even so, the turn around time as far as the Commission is concerned

has been good. In our opinion, the UPERC’s tariff philosophy is sound

with the targets for efficiency improvement and gradual move towards

eliminating cross-subsidy being realistic—the philosophy does not

threaten the viability of the licensee, and nor does it subject

consumers to sudden tariff-shocks.

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Operational Parameters (Generation, Transmission and

Distribution)

The power stations belonging to the State Sector in Uttar Pradesh have

been operating at low PLFs, which directly affects the financials of the

UPPCL, since the average cost of purchase from UPRVUNL at an

estimated Rs 1.54 per kWh is lower than the purchase cost from any

other source. With the formation of Uttaranchal, Uttar Pradesh will only

be entitled to the surplus power that is left after the generating units of

the UPJVNL have met Uttaranchal’s requirement. The UPPCL estimates

that the financial burden on account of the above will be Rs. 5 billion

per annum.The UPPCL also suffers from high T&D losses, estimated at

39% for 2000-01, which when combined with the collection efficiency

of 78%, results in an ATC loss of over 50%. As stated, the State Power

sector’s unsatisfactory progress on key distribution sector reforms like

energy audit and 100% metering of consumers is a cause for concern.

According to the UPERC tariff order for 2001-02, the problems have

been aggravated by the huge unmetered consumption, large billings

on ad hoc basis (even when meters exist), limited attempts at

recovering arrears, and inadequate investment in metering, system

improvement and capacity augmentation.

Structure of power sector in U.P

In terms of the UP Electricity Reforms Act, 1999 and the Uttar Pradesh

Electricity Reforms Transfer Scheme, 2000, which became effective on

January 14, 2000, the erstwhile, Uttar Pradesh State Electricity Board,

which was responsible for the generation, transmission and distribution

of power in the state of Uttar Pradesh (UP), was trifurcated into three

corporations, viz., Uttar Pradesh Power Corporation Ltd. (UPPCL), UP

Rajya Vidyut Nigam Limited (UPRVUNL) and UP Jal Vidyut Nigam

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Limited (UPJVNL). While UPPCL is the transmission and distribution

company, UPRVUNL has inherited the thermal generating facilities and

UPJVNL the hydel generating facilities of the erstwhile UPSEB. While

UPRVUNL has a total capacity of 4240 MW, UPJVNL has a total

generating capacity of 515 MW.

In addition to these entities, there are two other entities in the State--

Noida Power Company Ltd., which is responsible for distribution of

power in Greater Noida and Kanpur Electricity Supply Corporation Ltd.

(KESCO), which is responsible for distribution of power in Kanpur.

The total customer base of UPPCL as on March 31, 2000 was around

7.6 million. The per capita power consumption in UP (including

Uttaranchal) is low at 196 units compared with a national average of

around 360 units. Uttar Pradesh is one of the most energy-deficient

States in the country with an estimated deficit of 15% for the year

2000-01.

A separate State of Uttaranchal was carved out from UP in 1999 as a

result of which most of the hydel generating capacity residing with

UPJVNL is now situated in the State of Uttaranchal. As per the GoI order

dated November 5, 2001 UP shall have the first right of purchase in

respect of any surplus power left over from the power generated by

the units of UPJVNL after meeting the consumption requirements of

Uttaranchal. Through another order dated January 4, 2002, the GoI has

allocated 353 MW out of the undivided Uttar Pradesh’ s share of

3399.9 MW in the CPSUs of the Northern region to the State of

Uttaranchal. UPPCL has represented against the above orders to GoI.

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The UP Electricity Reforms Act, 1999 was notified on January 15, 2000.

As per the decision of the Government of Uttar Pradesh (GoUP), the

activities of generation, transmission and distribution of erstwhile

UPSEB have been transferred to Uttar Pradesh Rajya Vidyut Utpadan

Nigam Ltd. (UPRVUNL), Uttar Pradesh Jal Vidyut Nigam Ltd. (UPJVNL).

Uttar Pradesh Power Corporation Ltd. (UPPCL). In addition, the

Government of Uttar Pradesh has transferred Tanda Thermal Power

Project to the National Thermal Power Corporation (NTPC) and the

Kanpur Electricity Supply area was separated as a subsidiary company

of UPPCL and christened Kanpur Electricity Supply Company Limited

(KESCO)

A Memorandum of Understanding (MoU) between Government of India

(GoI) and Government of Uttar Pradesh has been signed on February

25, 2000 charting out the actions to be taken towards reforms in which

GoI has committed to support the GoUP in R&M, transmission works,

reforms studies, joint-venture hydro projects, rural electrification and

by way of additional central power allocation.

The status of implementation against the various reform parameters

are given below:

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36. Power Sectors Reforms in Delhi

Background to the Reforms:

A Fast-track Reform Process:

Milestones

INDIA’S LARGEST URBAN POWER UTILITY(2001-02)

Load in Megawatts :

Consumption in Million Units :

Privatisation not corporatisation was the aim

Fixing improvement targets.

How should we measure commercial efficiency?

How to fix the targets?

How should we achieve this balance?

Opening AT&C loss levels approved by DERC

What about tariffs?

How to value the assets?

Allocation of Assets & Liabilities

How to deal with liabilities ?

Conclusion

The crowning achievement of this Government has been the steps

taken to privatise the transmission and distribution of power by the

restructuring of the Delhi Vidyut Board. Our reform efforts have been

received by all sections of the society, including trade unions and

officer associations of the Delhi Vidyut Board without any protest,

agitation or labour disturbance. This has sent a clear signal to the

whole country in general and the private investors in particular about

our unflinching commitment to fundamental reforms.

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http://delhigovt.nic.in/power.asp#16

















Background to the Reforms:

The Delhi Vidyut Board (DVB) was a State Electricity Board set up in

1997 under the Electricity (Supply) Act, 1948, succeeding the Delhi

Electricity Supply Undertaking (DESU), which had existed since 1957 as

a wing of the Municipal Corporation of Delhi; it was an integrated utility

with generation, transmission and distribution functions serving all of

Delhi except the NDMC and MES (Cantonment) areas, to which it

supplied power in bulk.

The creation of DVB, replacing DESU, in 1997 proved to be merely a

change in the legal status of the organisation and was not followed by

any real change in its structure, functioning and work culture: its

reputation continued to deteriorate and its poor commercial

performance—the best known thing about DVB perhaps being its high

Transmission and Distribution (T&D) losses—made it a drain on the

public exchequer and incapable of raising the resources necessary to

improve its services. There were unprecedented, widespread

expressions of public discontent during the difficult summer of 1998.

A Fast-track Reform Process:

Against the above background, one of the first major steps taken by

the new Government of the NCT of Delhi was to bring out a Strategy

Paper on Power Sector Reforms in February 1999. There followed a

unique, innovative yet fast track reform process that ultimately

resulted in the unbundling of DVB and privatisation of distribution with

effect from 1st July 2002. The Delhi power sector reforms are now

being widely acclaimed as marking a breakthrough, and are being

widely studied. The methodology adopted in Delhi has been favourably

commented on in the report of the Distribution Reform Policy

Committee appointed by the Central Government under the

135

chairmanship of Shri A.K. Basu, then Secretary (Power) in the Central

Government and now Chairman of the Central Electricity Regulatory

Commission. Recently, on October 23, 2002, at the 4th Techno-

Economic Summit & Expo on Power, Telecom & Infrastructure

Construction held in Mumbai, Shri Ajay Maken, Power Minister, on

behalf of the Government of Delhi, received from the Union Power

Minister the Power India 2002 Excellence Award for the most

progressive State Government; this prestigious trophy was awarded by

a distinguished panel of judges headed by Mr. Justice A.M. Ahmadi,

former Chief Justice of India.

Milestones

We may look back briefly at some of the major milestones in these

historic power sector reforms, and consider how complex, yet how

transparent, the reform process actually was:

February 1999: The Government brought out a Strategy Paper on

power. This paper envisaged:

Setting up of a Regulatory Commission;

Unbundling of the Delhi Vidyut Board into separate Generation,

transmission and distribution companies;

Disinvestment of distribution;

Interim measures to improve the performance of DVB;

Protection of staff interests.

March 3 1999: Delhi Electricity Regulatory Commission was set up

under the Central Electricity Regulatory Act, 1998. At this stage the

Commission’s functions were limited to tariff setting.

November 17, 1999: M/s. SBI Capital Markets were engaged as

consultants for the reform process.

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December 12, 1999: Shri V.K. Sood was appointed as Chairman and

single member of the Regulatory Commission.

December 22, 1999: The first draft of the Electricity Reform

Ordinance was sent to the Central Government. Thereafter, several

revisions in the draft were made on the basis of suggestions received

from them.

April 7, 2000: The Consultants’ Inception Report, indicating the main

features of the proposed reform strategy, was received and began to

be examined and processed by the departments concerned in the

Delhi Government.

June 26, 2000: A Coordination Committee was established to monitor

the progress of the reforms. It included representatives of Ministry of

Power, Power Finance Corporation, outside experts and consultants, as

well as Delhi Government and DVB officers.

October 28, 2000: The Delhi Electricity Reforms Ordinance was

promulgated. The Ordinance

empowered GNCTD to restructure the power industry;

gave DERC full powers to regulate the power industry including

licensing, restricting the Government’s role to policy matters.

On the same day a Tripartite Agreement was signed between GNCTD,

DVB and employee representatives ensuring the following to all the

present employees of DVB:

No retrenchment;

No change in service conditions;

Service under DVB and under successor entities to be treated as

continuous;

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Creation of a fund to be administered by a Trust to be set up by

the Government, with Principal Secretary (Power) as chairman

and with other Government representatives plus employees, for

retirement benefits of existing pensioners and employees.

Existing welfare schemes like compassionate appointment and

medical reimbursement etc. to continue.

Ad hoc pay increase of Rs.500/- monthly on transfer to the new

corporate entities, adjustable against next pay revision.

November 11, 2000: The Delhi Assembly passed the Delhi Electricity

Reform Bill, which was sent for Presidential assent.

January 6, 2001: The Cabinet of GNCTD accepted the Consultants’

Inception Report with some modifications.

January 17, 2001: An Investors’ Conference was was organised by

GNCTD, DVB and the Power Finance Corporation (PFC). More than 100

attended – major national and international companies, financial

institutions, foreign diplomatic representatives and industry

associations.

February 15, 2001: Request for Qualification documents were

issued, inviting Statements of Qualification by April 16, 2001. The main

eligibility requirement was that the bidder should be a company with a

net worth of Rs.500 cr.

The documents were sold to 31 parties.

March 11, 2001: The Delhi Electricity Reform Act came into force,

after receiving Presidential Assent.

May 10, 2001: A Committee was set up to evaluate the SOQs

received. It included the representatives of the Ministry of Power,

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Central Electricity Authority and a senior outside expert, besides

officers of GNCTD.

May 15, 2001: After seven prospective bidders submitted their SOQs,

the Committee prequalified six: A.E.S., BSES, China Light & Power,

CESCON, Reliance and TATA Power.

July, 2001: Six ‘shell’ companies were registered, viz. a Holding

Company, a Generating Company, a Transmission Company and three

distribution companies. These would become successor entities of DVB

on operationalisation of the Transfer Scheme.

July 16, 2001: The consultants submitted their Final Report.

October 5, 2001: The GNCTD Cabinet approved the Consultants’

Final Report.

November 20, 2001: Government issued the Transfer Scheme Rules

which gave the Opening Balance Sheets of the new companies and laid

down the manner in which the assets and functions of the DVB would

be transferred to the new companies.

November 22, 2001: Government issued Policy Directions binding

the regulatory commission to the conditions on which distribution

companies would be disinvested as a result of the bidding process.

February 22, 2002: DERC fix the opening loss levels and initial BST,

which was a pre-requisite for receiving bids.

April 10, 2002: Bids were received. The Cabinet considered the bids

unacceptable ‘in the present form’ and a Core Committee of senior

officers was authorized to explore alternatives including negotiations.

May 31, 2002:

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The Cabinet met and approved the report of the Core

Committee, which had obtained acceptable bids after protracted

negotiations.

The Share Acquisition Agreement was signed with the successful

bidders.

June 27, 2002: The Shareholders’ Agreement and other agreements

with the bidders were signed.

June 30, 2002: Transfer Scheme was operationalised and the

management handover to the successor entities including the three

distribution companies under private management become effective

on midnight of June 30th 2002.

Features of the Reform Process: Magnitude of the task: The power

sector reforms in Delhi had a number of unique features. First of all we

must appreciate the magnitude of the task. The Delhi Vidyut Board

was in fact the largest exclusively urban utility in India, much bigger

than the private utilities in Mumbai and Calcutta as the following table

shows:

INDIA’S LARGEST URBAN POWER UTILITY (2001-02)

DVB CESC(**) BSES

CONSUMER/THOUSAND 2645 1600 2290

AREA OF

SUPPLY(SQ.KM) 1483 567 384

EMPLOYEES/10 2287 1476 3500

PEAK LOAD(MW) 2879 1183 1400

(**) 1998-99

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With the privatization of DVB, the size of the private sector in power

distribution in India has roughly doubled. In this context, it was also a

relevant consideration throughout the reform process that there were

relatively few parties who might be willing to take over the enormous

task of distributing power in the national capital, with all its attendant

risks. The earlier privatization in Orissa had appeared only a partial

success and the companies which had taken over distribution there

had been suffering losses.

Other features of Delhi power distribution: The heavy losses in Delhi

were well known. Some of the features of power distribution in Delhi

include:

Very high per capita consumption – per capita consumption in

Delhi is about 1228 units against the national average of 338

units (1998-99).

Rapid growth in load and consumption both, Delhi’s population

and the urbanized area have been expanding rapidly both in a

largely unplanned manner. Therefore, the system has to be

augmented every year and arrangements for purchase of more

power have to be made every year on larger scale than in other

141

metropolitan cities in India. The peak demand met and the

consumption in Million Units in the months of July, which is

normally the month of heaviest consumption has grown as

shown below in the last few years:

Load in Megawatts:

Consumption in Million Units:

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Variable requirement: There is a wide gap between the peak and

off-peak loads in Delhi. In winter, the load early in the morning is

double the load at night, and even in summer there is a wide gap

between the peak and off-peak times. Again there is a

substantial variation seasonally. The states with agricultural

loads are able to flatten the load and consumption curves

throughout the day by supplying agricultural power in off-peak

periods, but in Delhi it becomes necessary to make costly and

difficult arrangements for power supply for the peak period.

Unauthorised development: In Delhi the advantage of negligible

agricultural power is off-set by the presence of unauthorised

colonies. Electricity was stolen in unauthorised colonies and

jhuggies, which we are not formally electrified and metered. It

will be a Herculean task to bring the unauthorised areas within

the billing net.

143

Its T&D losses were perhaps the best-known thing about DVB.

These losses have increased substantially during the previous

decade, particularly from 1993, as the following chart will show:

As the table shows, the steady increase in T&D loss was somewhat

controlled and slightly reversed from 1999 onwards. However, it was

clear to the Government that it would be necessary to privatize

distribution as quickly as possible.

Privatisation not corporatisation was the aim

In other states where reforms have been introduced, the policy has

been to first create Government-owned corporations managing

distribution and then gradually start the process of privatization. These

government corporations run for several years and the experience so

far does not indicate that they have been able to function viably. In

Delhi, the intention was to privatize and not merely to corporatise, and

the interim period of Government corporate functioning envisaged in

other states was by-passed here. DVB continued to function until

144

midnight of 30th June, 2002 and was immediately succeeded by the

private companies in Distribution.

Fixing improvement targets.

The basic problem of the power sector in India is that the distribution

business incurs heavy losses, being unable to issue bills for all that

energy supplied (i.e. high T&D losses) and unable to collect payment

for many of the bills that are issued (i.e. low collection efficiency). The

basic purpose of power sector reforms is to reduce these losses and

make this sector self-sustaining. Commercial efficiency is the ultimate

consumer interest because it means the consumer will not have to

bear the cost of the utility’s losses, and this alone will ultimately keep

the tariff under control. In Bombay, where the losses are low, there has

been no tariff increase for six consecutive years and yet the utilities

are profitable. That shows why it is absolutely necessary that any

reform package should involve a steady, targeted reduction of T&D

loss.

How should we measure commercial efficiency? All State

Electricity Boards issue figures of the T&D losses but, with the

exception of Delhi where all registered consumers were metered and

bills were printed on the metered consumption, these figures lost much

of their credibility. The T&D loss figures of State Electricity Boards do

not bear scrutiny because much of the billing is on a flat rate basis (i.e.

without meters) and can easily be inflated to keep the losses from

appearing high. Thus after the reforms in many States, it has been

found that the T&D losses were much higher than had been stated

earlier. In Orissa this misinformation caused the investors who took

over the distribution companies to suffer heavy losses. In Delhi, both

the figures were more accurate, but it did happen that after the

accounts were finalised they would sometimes be one or two

145

percentage point different from the original figures. In order to create

faith and confidence in the data in Delhi, we introduced the new

concept of Aggregate Technical & Commercial (AT&C) Losses in place

of T&D losses. T&D losses are the difference between energy supplied

and energy billed; but since this figure may not always be accurate,

the criterion adopted in Delhi was the difference between the number

of units of energy supplied and the number of units of energy for which

payment was actually recovered. This new criterion was called AT&C

losses and it has since been adopted (under the term ‘effective loss’)

by the UPERC in its last tariff order for Kanpur, and is now being

advocated for all States by the Union Power Ministry.

How to fix the targets? In Delhi at current prices one percentage

point of AT&C losses involves about Rs.80 crores per annum. In other

words if an investor misses a target of AT&C loss reduction by 1% he

stands to lose about Rs.80 crores, since the tariff would have been

fixed according to the loss reduction targets. It is therefore very

important that the targets should be achievable but (in the interest of

the public) they should be fixed as high as possible.

How should we achieve this balance? The innovative target-setting

methodology adopted in Delhi was to establish the efficiency

improvement targets through the bidding process itself. This is a

transparent method by which we have been able to show the public

that we have obtained for them the best deal possible in the

circumstances. The reduction of AT&C losses has been fixed at a level

which will ensure that distribution in Delhi becomes viable by the end

of the five-year period i.e. that the tariff should be completely under

control without Government assistance after the end of this period.

146

The opening AT&C losses for each distribution company and the

targeted improvements are as follows:-

Opening AT&C loss levels approved by DERC

Central/East 57.2%

North/Northwest 48.1%

South/West 48.1%

All 50.7%

AT&C Loss Reduction Targets accepted after

negotiations

2002-

3

2003-

4

2004-

5

2005-

6

2006-

7

Central/East 0.75% 1.75% 4.00% 5.65% 5.10%

South/West 0.55% 1.55% 3.70% 6.00% 5.60%

North/Northwest 1.50% 2.25% 4.50% 5.50% 4.25%

In case the companies achieve more than the targets originally set by

the Government (which are a few percentage higher than those

above), the new companies will keep half of the additional benefit as

incentive and pass on half of it to their consumers as a rebate on the

tariff. It should be remembered that Government retains 49% share in

the distribution companies so that the private investors actually get

about one-fourth of the additional benefit, which is a very justifiable

incentive since once the losses come down it is a permanent benefit to

the public.

What about tariffs? During this interim period after privatisation, the

AT&C losses will still be high. Who is to bear the cost? Logically, the

147

answer would be that the tariff should be increased to meet all the

allowed cost of distribution including the allowed AT&C losses, but this

would impose an undue burden on the public. Therefore, to bridge over

this interim period before the industry becomes self-sustaining the

Government will be giving a loan assistance of approximately Rs.3450

crores to the Transmission Company, which during this period will be

buying power from outside Delhi and from the Generation Company,

and supplying it to the distribution companies at a lower rate. It needs

to be stressed that this does not helped the distribution company at

all, since they are entitled to all their allowed costs, but is purely a

means of helping the consumer.

This also makes it possible to have differential tariffs for the three

distribution companies in order to maintain a common retail tariff

throughout Delhi (subject only to slight variation because of the

different rebates might earned for overachievement) during this

interim period. This is in the public interest because otherwise the

losses, and consequently the tariff, might be lower in well-to-do areas

than some of the other areas where there is more unauthorised

development.

How to value the assets? As we have seen, the controlling interest

in each of the distribution companies has been sold to the investors

who committed the highest loss reduction. How were the companies

valued?

There are different ways of valuing assets. One conventional method is

to value all the physical assets taking depreciation into account for

each item. Alternatively there are various methods of business

valuation. The Department of Disinvestment, Government of India in

its manual entitled “Disinvestment: Policy and Procedures” advises

that physical asset valuation is inappropriate for running businesses

148

and that “business valuation methodologies are generally used for

valuation of a going concern”. The asset valuation method, it says,

“would be relevant only for valuation of assets in case of liquidation of

a company”.

The assets of the Delhi Vidyut Board were valued on a business

valuation basis. The method adopted was to take into account the

projected efficiency improvements and reasonable retail tariff

adjustments, as well as the projected Government assistance,

assuming that the electricity business should become self-sustainable

within five years. On this basis the assets and liabilities of Delhi Vidyut

Board were valued as follows:-

Allocation of Assets & Liabilities (Rs. in Crores)

Successor Entity Total Asset Value/ Serviceable

Liabilities

GENCO 350

TRANSCO 450

DISCOM1 (E+C) 290

DISCOM2 (S+W) 1150

DISCOM3 (N+NW) 920

TOTAL DISCOMS 2360

GRAND TOTAL 3160

It will be seen that the valuation of the companies varies considerably,

one of the companies (Central + East) being of much lower value

because of its limited commercial potential. But there is no real fear of

under-valuation. It has to be remembered that this is a licensed

business in which there is no prospect of “asset stripping” and the

distribution companies cannot reduce the assets without the

permission of the Regulatory Commission. In fact land have been given

149

to them on licence basis and therefore they cannot divert the property

entrusted to them to any other use but electricity distribution.

How to deal with liabilities ?

DVB and its predecessor DESU accumulated enormous losses which

could not reasonably be passed on to the new companies. Nobody

would buy them with heavy outstanding liabilities. Therefore the

existing liabilities of DVB were diverted into those which were

serviceable which will eventually be repaid by the successor entities

after an initial four-year moratorium and those which were

unserviceable will remain with the Holding Company and have to be

dealt with separately.

Conclusion:

As a result of the power sector reforms in Delhi, the national capital is

now served by two of the best electric utilities in India, BSES and Tata

Power. They will take some time to make the projected improvements,

for which they have targets, but with economic viability the power

situation in Delhi can only get gradually better with every passing year,

reversing the legacy of deteriorating service that we had seen in the

past.

37. Orissa

Orissa is one of the less developed states in India, based on average

human development indices, but it also has some amount of large

industry. Nonetheless, it was a somewhat non-obvious candidate for

leading the reforms in India, and conventional wisdom indicates the

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reforms came not from within but due to World Bank and outside push.

Of course, like most other SEBs, Orissa SEB (OSEB) was in financial

difficulties, and didn’t have the funding to improve its situation. The

reforms in Orissa were not a success, and we explore some of the

happenings and their causes.

Some of the causal factors for Orissa’s reforms included (Rajan2000):

Contextual factors:

Poor Performance of the SEB (driven partly by a rise in thermal

power over hydropower, as well as by other factors common to

other states)

Conditionality by lending agencies (World Bank)

Trigger factor:

Inability of the state government to support the utility

Facilitating factors:

Support of the government

Absence of a powerful lobby (relatively low agricultural

consumption)

Support of top management

The process of reform began in November 1993, through discussions

with the World Bank – who were already involved with financing a

hydropower project in the state, which was facing rehabilitation

difficulties – on how to improve the operating performance of the

sector, and draw investment? Based on these, an agreement was

signed between the Orissa Govt. and the World Bank (WB) for a reform

process, and this was later reviewed and approved by the Chief

Minister and his cabinet in 1995 (Rajan2000). Based on the WB

agreement and reform program, the reforms would consist of:

Restructuring of OSEB via unbundling and corporatization

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Privatization of generation, grid corporation, and distribution

Competition for new generation capacity

Separate regulatory body

Tariff Reform

Out of the estimated one billion dollar extra expenditure for the

restructuring (loans), $350 would million come from WB loans, and the

UK government would also provide DFID support for around $100

million. The blueprint and milestones for the reforms were drawn up

via the World Bank’s Staff Appraisal Report (SAR), and the reform

experiment was ready by 1995.

The process was as follows:

1993 Chief Minister announces power reforms plans.

1994 Planning for reforms continue.

1995 Regulatory Reforms Bill passes in the state legislature.

1996 Orissa Electricity Reform Act took effect on April 1, 1996.

OSEB was divided into the Orissa Hydro Power Corporation

(OHPC) for all hydel capacity and GRIDCO. GRIDCO inherited the

transmission and distribution infrastructure, as well as the

liabilities of the SEB. The already existing Orissa Power

Generation Corporation (for thermal power) continued, but future

generation capacity was to come from IPPs (Mahalingam1997).

Orissa Electricity Regulatory Commission (OERC) was also

established. No budgetary support was envisaged for any of the

bodies, except the regulatory body. But, to help out the

enterprises, their accumulated losses were to be written off, their

assets revalued, and their liabilities readjusted

(Mahalingam1997). Based on the recommendations of various

consultants, a depreciated replacement model was chosen to

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revalue the assets of OHPC and GRIDCO. The assets of GRIDCO

increased from a book value of Rs. 1,183 crore to Rs. 2,395.8

crore. There were also various liabilities, including to NTPC, and

these were converted to a term loan of Rs. 1,148.9 crore, plus

some significant short-term liabilities (Mahalingam1997). The

total capacity was 2,120 MW within these units.

1997 OERC issues first tariff orders.

1998 Distribution zones were established as separate

corporations (still PSUs) out of GRIDCO. Even then, GRIDCO

remained the single-buyer of power to sell to the 4 DistCos.

1999 The 4 DistCos were also privatized, with a release of 51%

of the equity in each held by GRIDCO. 39% would remain with

the state government, and 10% would be held by employees.

The central zone went to AES Trans power, the US multinational,

and the other zones went to BSES. Workforce allocation and

severance were long, drawn out processes according to most

reports. To facilitate the sale, GRIDCO accepts deferred

payments, which affects it cash flow position significantly later

on. Orissa Government divests 49% of its stake in OPGC, via

competitive bidding. AES wins with a Rs. 6.03 billion bid, giving it

operating control of 2x 210 MW thermal plants in Ib Valley. These

plants were commissioned in 1994 and 1996, at an investment of

Rs. 11.35 billion (Iyer 2000). Not the entire bid was towards

assets; fresh capital was also invested (8%, equal to Rs. 1.03

billion).

2000 GRIDCO’s financials worsen, and debt levels of the

companies rise.

2001 Government constitutes Kanungo Committee to examine

the reforms process AES withdraws from the central zone

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distribution.

Government appoints an administrator for this zone. His appointment

is stayed by the courts. BSES states it is not interested in taking up the

central zone. 2002 The performance of 3 of the 4 zones worsens

compared to the previous year (Southern, with BSES, is the exception).

That reforms are not straightforward, nor can private operates easily

succeed is illustrated by the attempt in September 1996 to hand over

one section of distribution (the central zone, which included cities like

Cuttack and Bhubhaneshwar) to BSES for operation, under a

management contract. After the first 6 month review found negative

performance, the management contract was terminated in April 1997.

In response, BSES stated it was not given enough time to effect

change, disputed the baseline numbers, and said that it never really

had control over the staff (Mahalingam1997), a concern for any reform

mechanism based on outsourcing. Also, AES came into distribution

somewhat reluctantly (Mahalingam1998). It was originally in the state

as a power generator (IPP), with the 500 MW (250 x 2) Ib Valley

Project. However, during the privatization process, BSES was the only

eligible bidder for the 4 zones, after Tatas withdrew from the central

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zone (Prayas 2001). But, to ensure they didn’t get all the zones, AES

was persuaded to take over the central zone.

Results

The reforms were supposed to improve the power position in Orissa,

but peak shortages continue. The finances of the companies have

worsened to some extent, and the losses continue to mount (financial

as well as technical). GRIDCO failed to pay generators what it owes,

citing failure of receiving payments from the DistCos. Had they

received their money, the generators (OHPC and OPGC) have a book

profit of Rs. 768 crores between April 1, 1996 and March 31, 2001

(OERC 2002). The WB-SAR based report called for a number of

milestones, details on which can be found in Prayas (2001). Most of

these were based on structural changes, like setting up the distribution

zones, having OERC issue tariff orders, etc. However, some of these

had negative operational effects as well. The goal of 16% returns for

OHPC along with its valuation hiked the costs to GRIDCO significantly,

by hundreds of percent. This is an indication that the via the reforms

process, as profitable companies come up along the power sector

(generation, transmission, and distribution), this will raise the average

cost of power compared to today’s loss-making utility. One casualty of

the reforms process was rural electrification. Private companies were

not interested in such loss-making operations. The agricultural demand

for power went down from a low 6% in 1992-93 to a very low 3% in

1999-00 (Kanungo Committee 2001). But yet, the finances didn’t

improve. This highlights the importance of mechanisms to ensure

rural/underserved areas are catered to. Either specific targets must be

set and met, or an outside entity should be entrusted with such a role.

Rural cooperatives might be one solution for such consumers. The

noted environmentalist Ashok Khosla points out that if communities

treat electricity as a shared resource, they would manage it better, as

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they have done historically for things like a shared water supply

(personal communication).

What went wrong?

Some of the main problems with the operations of the sector were

relating to cash flows. OERC limited the increase in tariffs (citing that

not all costs could just be passed on to the consumers – e.g., for bad

performance – unlike the pre-reform days). This created losses for the

DistCos, who also had deferred payment agreements with GRIDCO.

GRIDCO, owned by the Govt. of Orissa, was caught between the

increasingly expensive generators and non-paying DistCos, who were

unable to improve performance as expected. The compromise solution

involved the government promising to pay its dues in 15 days.

After the reforms, GRIDCO’s and DistCos finances went down because

of a number of factors (Prayas 2001; OERC 2002):

The bulk of the liabilities went to GRIDCO, Rs. 16 billion vs. 6 billion

for all the Distcoms.

Assets of GRIDCO were revalued upwards, to help match the

increase in liabilities. This had operating implications, like the

increase in depreciation costs.

OHPC’s tariffs were increased to meet the 16% returns. Overnight,

the tariff went from Rs. 0.1 to Rs 0.49/kWh in 1996. Even central

station’s power was expensive, and GRIDCO had to offtake such

power.

There were unrealistic T&D losses estimated during the unbundling

process. This stresses the importance of accurate baseline

information, and realistic performance targets. The forecast for T&D

reduction from 39.5% in 1996-97 to 22.7% 2000-01 wasn’t

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achieved. Even the initial assessment of 39.5% for 1996- 97 was

grossly incorrect. A later audit showed this to be 49.4%.

Tariff increases were lower than in the WB-SAR.

There was no budgetary support via subsidies.

The growth of load, especially profitable load, did not materialize.

The WB-SAR called for 7,009 million kWh for railways plus industrial

high tension (bulk) supply, while the actual sale in 2000-01 was

2,760 million kWh. This affected not only the cross-subsidy

potential, but the T&D losses as well.

Poor collection rates from consumers. Distcos achieved only 75 and

76% collection in 1999-2000 and 2000-01, respectively.

However, the biggest reasons for the poor performance appear to be

the false assumptions and expectations of the players, and the limited

support provided by the government, either for subsidies or to the

companies who had liquidity issues in addition to solvency issues.

Money coming in from outside sources was often diverted to state

budget needs, and there remained significant institutional lethargy and

morass in the sector. The government failed to pay its own dues for

power, some Rs. 1.5 billion.

Some of the lessons from the Orissa experience, other than the

obvious ones like not getting the numbers wrong, include (IDFC 2000):

Incomplete separation of transmission and distribution can cause

problems.

Regulators should give a clear picture of their tariff philosophy,

rate base, valuation methods, likely profile of prices and

expected performance levels.

There should be a structured, time-bound financial support

mechanism, with a fixed schedule for tapering off coupled with

improvements in operating parameters and collection.

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The single buyer model is necessarily not the best, and the

Transco might be better as just a wires company.

Determining who gets priority claims over revenues is important.

Do not escrow the revenues from the distribution zones for

meeting TransCo needs, like was done in Orissa.

Don’t tinker with valuations, especially just before privatization.

This can have a serious impact on tariffs, as Schedule VI of the

Supply Act 1948 is based on assets (and newer methods allow

for 16% returns on equity).

38. Andhra Pradesh

Andhra Pradesh (known as AP) is a large state considered to be the

northern-most state in South India. Since 1995, it has been governed

the by techno-savvy Chief Minister, Chandrababu Naidu, a central

figure in the reforms process. Naidu has been successful in pushing

reforms, also driven by his push towards rural empowerment.

Naidu announced in August 2002 that the state should be power

surplus, and that agricultural power supply would be guaranteed at 9

hours per day, a big improvement over then supply. Of course, AP was

not power surplus when considering agricultural supply rostering. What

AP had done was to separate rural domestic/commercial from

agricultural supply (through phase-wise isolation of feeders), and

promise that rural domestic/commercial supply would not get cut off

when agricultural supply was curtailed (a major step, compared to

many parts of India), and that agriculture would also get 9 hours per

day of 3-phase supply. This plan, despite the increased capacity in the

state and purchases from outside to meet full demand (excluding

agriculture), put immense burden on the utilities (APTransco), whose

finances were projected to take an annual hit of close to a thousand

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crore to meet such increased supply. As mentioned before, protests

against tariff hikes in 2000 turned violent, but the AP government still

vowed to proceed with reforms.

The APSEB was established in 1959, similar to many SEBs in the

country, and was unbundled in 1999 as part of ongoing power sector

reforms. By June 1997 there was a public policy statement to

unbundling, and the required legislation was enacted in February 1999.

This split up APSEB into APGenCo and APTransCo. The APERC was also

instituted, and it has issued 3 tariff orders to date. According to utility

officials (and examining its tariff orders and pronouncements), it

appears quite independent.

AP’s power sector is quite large, with a capacity close to 8,000 MW.

Compared to its capacity, it faces poor consumer averages, with one of

the highest number of pumpsets (over 1.8 million) and number of

consumers (some 12 million) in the country. Noteworthy points about

the sector are that AP has had some of the greatest success with IPPs

(driven by not only political will but also because Godavari Basin

natural gas is available). 1,060 MW of IPP power was added in 5 years,

from 5 different projects, one of the highest in the country. While

financial concerns are a fundamental driver for reforms, SEB losses are

a somewhat recent phenomenon. In 1994-95 APSEB earned a profit of

Rs.87.25 crore, but in 1995-96, losses came to Rs.1,244.68 crore,

climbing to Rs.1,533.04 crore in 1996 – 97 Reddy 2000).

In looking at the reforms, the first step was likely the 1995 high level

committee, haired by Hiten Bhaya, to suggest reforms to be introduced

in the power sector (Reddy2000). While focusing on unbundling APSEB

and operating on commercial lines, as well as tariff rationalization, the

World Bank commented that the Hiten Bhaya Report didn’t go far

enough with the reforms process. The regulatory commission should

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focus on all tariffs, and full unbundling, without holding companies,

should be the way forward. The World Bank also advocated a minimum

50 ps/kWh for agriculture. While the AP government stated the WB role

was only advisory, studying the reform paper showed nearly full

correlation with such recommendations (Reddy 2000).

Driving ahead with reforms, the government pushed the Andhra

Pradesh Electricity Reforms Act of 1998through with stunning speed.

The Telugu Desam Party government introduced the Billon April 27,

1998, which was passed within one day. Helping ensure its smooth

passage, the entire opposition was suspended from the Assembly

(Reddy 2000).

Because of its reform programs, AP was the beneficiary of the a major

portion of

World Bank funding in India, and it received 6,600 crore of loans

towards total reforms, two-thirds of which were for the Andhra Pradesh

Power Sector Restructuring Program.

These loans were under the Adaptable Program Loan (APL). Such

disbursements were despite sanctions imposed on India after its May

1998 nuclear tests. The reforms created a GenCo, a single-buyer,

APTransco, and (eventually) 4distribution companies (by geography).

The DistCos were only hived off from

APTransco in April 2000. The borders for the 4 DistCos were chosen not

on operational grounds, but to ensure that no one company had an

extreme mix of consumers (too many agricultural or all the paying, i.e.,

industrial/commercial, customers). In the AP model, the tariffs set by

the APERC would be based on annual revenue requirements, and any

subsidy beyond the allowed cross-subsidy would be borne by the state.

However, the bulk-supply rates charged to the various DistCos is

unequal, factoring in its customer mix and ability to pay. In 2001-02,

the gap in the ARR calculations of Rs. 2,062 crore53 was filled by

efficiency gains of Rs. 501 crore and a Govt. of AP subsidy of 1,561

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crore rupees (APERC 2002). These subsidies are paid out to the

DistCos, who pay full bulk supply tariffs to APTransCo.

In terms of privatization, the government has scaled back its plans to

privatize the Distcos anytime soon, citing troubles in Orissa with

rushing into things. They also want to bring down losses in the system,

perhaps to increase the likelihood of a successful sale.

39. Gujarat

Gujarat is an industrialized state in Western India, and has been

pursuing reforms since 1999 (under the cover of the central ERC Act of

1998). Despite high per capita consumption of power, and high state

electricity duties (earnings for the state – some 1/3 of the total such

duties in India), the power sector is considerably under funded and loss

making. The Gujarat Electricity Board (GEB) continues to provide

generation, transmission, and distribution in the state, but there are a

number of private (and central) generators in the state.

The city of Ahmedabad operates under Ahmedabad Electricity

Company (AEC).

This private operator, established in 1913 is profitable (and publicly

listed), but the same is the case for other companies operating in

urban areas. AEC has paid a steady dividend, but recent changes in

supply costs have reduced the dividend from a peak of 25% in 1999-

2000 to 18% in 2000-01 to 10% in 2001-02. Notably, the Torrent Group

(primarily a pharmaceuticals company) is the largest stakeholder, who

also has a stake in Surat Electricity Company (the private electricity

operator in Surat, also in Gujarat), and they also have interests in

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generation. The remainder of AEC is held by financial institutions,

private investors, and the Gujarat Govt. (almost 20%). While we do not

examine the details of the Gujarat power sector, some observations

include the fact that the reforms process has slowed down, partially

due to external factors. A massive earthquake on January 26, 2001

caused massive state-wide difficulties, and there were also widespread

riots and elections in 2002. All of factors combined to slow down the

reforms process, which clearly requires political will and support of the

government.

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40. Statistic of different region

Baseline Estimation Details of Northern Region

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Constituent-wise Installed Capacity of NER Grid (in MW)

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POWER SUPPLY POSITION IN NER

GENERATION

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DEMAND

During FY 2004-05 & 2005-06 , the Peak Demand & Demand met in NER is furnished below:

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Peak Demand in MW

Demand met in MW

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ENERGY REQUIREMENT Vs AVAILABILITY

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During FY 2004-05 & 2005-06 , the energy requirement Vs availability in NER is furnished below

Energy Requirement in MU

Energy Availability/Consumed in MU

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PROGRESS OF CONSTRUCTION OF GEN. UNITS & TR. ELEMENTS

The status of progress of construction of Generating Stations and Transmission elements during 2004-05 is given below:

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HARYANA POWER PROFILE

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41. Conclusion:

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India needs huge investments not only to bridge the supply-demand

gap in generation, but also to see us through in transmission and

distribution. However, in view of the current state of affairs, few private

sector players are willing to enter this industry because of the huge

risk perceived.

Reforms began on the generation front. Several foreign players

entered the Indian market. The approach of generation reforms,

however, was found to be unsuccessful. Reforms need to begin with

the distribution business, which is now being undertaken by the

government. Many foreign companies which entered the power

generation sector have left; some are about to leave.

In the current scenario, benchmarked competition is the way out. The

Delhi model, having learnt from the failure in Orissa, now provides a

conceptual framework for other states to reform the distribution sector.

The benchmarking of competition is based on the principles of golf; the

regulator ensures an ‘appropriate handicap’. If the distribution

company fails to perform as per the regulator’s standards, the

distribution company accounts for the losses. Performances above the

set standard are appropriately shared by consumers and the

distribution company. Now that several companies have entered the

distribution business, there could be an opportunity for market-based

competition between distribution companies.

Privatisation alone cannot reform the sector. It is the basic realisation

and awareness that electricity is not a political commodity that will

help India realise its dream of ‘Power to all by 2012’.

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An important lesson to be learnt from international experience is that

the sequencing of events is an important success element for the

reform process to be successful.

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Power Sector Reform

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