CIAO DATE: 2/00

Energy in India: An Overview

The South Asia Monitor
Number 14
October 1, 1999

The Center for Strategic and International Studies

 

India’s opportunity for higher GDP growth could be thwarted by chronic energy shortages, in the absence of far-reaching structural reforms in the fuel and power sectors. India’s crude oil and natural gas production has been stagnating in recent years. Demand, however, has been growing by more than 6 percent annually, resulting in rapid growth in oil imports. Oil imports presently account for 60 percent of total oil consumption and are expected to increase to 70 percent within five years, if current demand and production trends continue. The cost of oil imports is expected to rise from U.S.$6 billion in 1998-1999 to U.S.$8 billion in 1999-2000, due to increases in global petroleum prices. At the same time, bottlenecks in power supply are crippling growth and the financial condition of the power sector is draining scarce budgetary resources.

India’s yawning energy needs and the looming import gap have in recent years led to a reassessment of its energy strategy. Policies in the energy sector are now aimed at exploiting domestic oil and gas resources more efficiently, attracting foreign investment to finance the required infrastructure, and shifting from imported oil toward the more competitive natural gas. Still, greater deregulation and restructuring of the sector, coupled with a more serious policy on regional cooperation in energy, is what is required to ensure competitive and reliable energy to a growing economy, reduce pressure on the balance of payments, and reduce budgetary transfers to the sector. The need for structural reforms is all the more compelling as oil prices rise and industrial recovery gets under way.

 

The energy situation:

India’s total energy consumption, driven by the demand in electricity generation, industry, and transportation, is expected to more than double by 2020. Assuming a GDP growth rate of 5.5 percent per annum, average energy consumption in India is expected to grow annually by 3.8 percent between 1996 and 2020; similar estimates are one percent for the United States and Western Europe, and 4.1 percent for China. Average annual growth between 1995 and 2020 in net electricity consumption is projected at 4.9 percent, second only to China’s (5.7 percent).

Currently, coal is India’s most abundant fuel, accounting for nearly 60 percent of primary energy consumption, followed by oil (30 percent) and natural gas (8 percent). By 2010, the share of natural gas in primary energy consumption is expected to rise to 12 percent, of coal to diminish to 50 percent, and of oil to remain at 30 percent. Given modest increases in the domestic production of natural gas and oil, India is set to become a major importer of these fuels by 2005.

INDIA: ENERGY CONSUMPTION in 2000, 2010, 2020
	2000	2010	2020	Average Annual Growth (%), 1996-2020
Oil (million barrels per day)	1.9	3.1	4.1	3.8
Natural gas (trillion cubic feet)	1.2	2.8	5.0	8.6
Coal (million short tons)	371	465	536	2.2
Electricity (billion kilowatt hours)	493	802	1,192	4.9
Hydroelectricity (quadrillion BTU)	1.2	1.6	2.6	5.3
Source: EIA/DOE: International Energy Outlook 1999

 

Fuel supply:

India’s domestic oil and natural gas production has been stagnating, with declining oil reserves. The stagnation in the domestic industry can partly be ascribed to the grip of state monopolies, such as the Oil & Natural Gas Corp (ONGC), Oil India (OIL), and Indian Oil Corp (IOC) among others, on all upstream and downstream activities. Another factor is the continuing control of prices for gas and petroleum products at the crude, refining, distribution and marketing stages under an “administrative price mechanism” (APM) regime.

Since 1993, private investors have been allowed to import and market liquefied petroleum gas (LPG) and kerosene freely; private investment is also allowed in lubricants, which are not subject to price controls. Prices for naphtha and some other fuels have been liberalized. In 1997 the government introduced the New Exploration Licensing Policy (NELP) in an effort to promote investment in the exploration and production of domestic oil and gas. Under NELP, foreign investors are granted the same treatment as domestic companies and no longer have to partner with state oil companies; no blocks are reserved for the national oil companies; and income is tax-free for seven years from the start of production. In addition, the refining sector has been opened to private and foreign investors in order to reduce imports of refined products, and investment in downstream pipelines is being encouraged. Attractive terms are being offered to investors for the construction of liquefied natural gas (LNG) import terminals.

The response of international companies to bidding for exploration blocks under NELP has, however, been modest, because the blocks on offer were not deemed attractive (and it was felt that ONGC had obtained the best ones), because of low recovery rates in the country and political uncertainty at the time. Other obstacles to foreign investment are the continuation of the APM, limited pipeline infrastructure, and controls on private companies’ rights to market transport fuels. Continuing subsidies and cross-subsidies on petroleum products are resulting in wide distortions in consumer prices and leading to the overconsumption of diesel and kerosene, with an adverse affect on the import bill.

Over the medium-term, hydroelectricity may become more attractive as India tries to limit its dependence on imported fuels. At present, hydroelectricity accounts for 13 percent of India’s electricity; annual average growth in its consumption up to 2020 is projected at 5.3 percent, second only natural gas’s.

 

Regional collaboration:

India is keen to diversify both its sources and suppliers of energy. India will be a major importer of natural gas and LNG over the next century. Gas pipelines from Central Asia and the Middle East, through Pakistan, would be the cheapest method of supply but are also politically unfeasible. Hence, India has been focusing on the costlier LNG imports. Contracts for LNG imports from Oman and Qatar have been signed; the LNG will be used as feedstock for petrochemical industries and as fuel for power plants on the western coast. On the eastern coast, India would favor the option of importing natural gas from Bangladesh and hydroelectricity from Bhutan and Nepal. As with regional cooperation in other areas, India will need to overcome suspicions and political opposition from its neighbors and may in addition have to grant greater trade access to its own market. Secondly, a regulatory framework coordinating the various LNG projects (five are presently under consideration for Gujarat) and determining issues such as pipeline access is required.

 

Power:

India’s electric generating capacity is 97 gigawatts (GW), of which 73 GW is thermal, 21 GW hydro, and 2 GW nuclear. The power sector is rent by bottlenecks in generating capacity, transmission, and distribution, resulting in frequent power outages; the demand-supply gap is 12,000 MW or 12 percent during periods of average demand and 18 percent during peak demand.

According to the latest Five Year Plan, up to an average of 10,000 MW of additional power per year over the next five years is required if India is to meet its demand for electricity. The cost of this additional infrastructure is estimated at over U.S.$150 billion over the next five years. Successive governments have tried to attract foreign investment to the sector by offering attractive tax breaks and automatic clearance for 100 percent foreign equity projects of up to U.S.$35 million. Although several independent power producers (IPPs) did enter the market, only a handful of such projects have reached financial closure. The financial viability of the State Electricity Boards (SEBs) has in fact been the main roadblock to increasing generating capacity.

The SEBs are the main players in the power sector: they control 55 percent of generation and 90 percent of distribution. The majority of the SEBs are, however, in poor financial condition due to subsidized electricity tariff rates for agriculture and losses arising from theft and technical inefficiencies. According to official figures, SEB losses in 1998 were approximately U.S.$3 billion. The SEB losses are in turn subsidized by the state governments, whose own financial positions are weak (cumulative state budget deficits are 3.5 percent of GDP).

The SEBs can afford neither to generate the power themselves, nor to buy it from the IPPs. IPPs, however, need creditworthy buyers; state governments, on the other hand, lack the finances and credibility to provide guarantees for their SEBs or to provide escrow coverage for more than a couple of IPP projects. In a few cases, such as for the eight “fast track” power projects including the privately owned Dahbol power plant, the central government stepped in by providing a sovereign guarantee—such guarantees, however, heavily increase its risk exposure.

In 1998, the government introduced a policy favoring large-scale power projects of above 1,000 MW. According to the plan, a newly established Power Trading Corporation would buy power from the IPPs and sell it to the states, and in case the states default on their payment to the IPPs the center could use transfers earmarked for the states for such payments. This policy, however, is not really feasible, particularly in view of the political leverage the states have in relation to the center. Ultimately, for the SEBs to be commercially viable and to be creditworthy buyers, the tariff rates they charge will have to be raised from their present subsidized level, and losses stemmed. Opposition to reform from farmers used to cheap power, and from urban consumers, is, however, entrenched. Orissa, the state that has implemented the farthest reforms in its power sector, has been able to unbundle its SEB partly because it has a weak agricultural lobby where farmers do not depend upon electrical pumps for irrigation.

Raising tariff rates will also help to stem the losses in transmission and distribution. Presently, less than two-thirds of installed capacity is being utilized, mainly because of average national transmission and distribution losses as high as 21 percent; a reduction in such losses would lower the amount of additional generating capacity required to meet demand. While legislation allowing private participation in transmission has been passed in Parliament, opposition from the SEBs is staunch, as theft is often carried out in collusion with SEB personnel.