7. ELECTRICITY

above). India’s interregional capacity in the national grid stood at 99 050 MW, using alternating current (AC) lines of 765 kV and high-voltage direct current (HVDC) lines of 800 kV and above. India also has a special voltage of 1 200 kV AC, which was developed indigenously by Powergrid.

Captive producers

The high tariffs and erratic supply experienced by industry have led to a slow but steady decline in the growth of industrial electricity purchases from utilities and a gradual transition towards industry generating power itself (captive generation) or purchasing it from dedicated generators (open access). Around 18% of grid-connected capacity stems from so-called captive power plants, which satisfy 71% of India’s industrial electricity consumption (ICPPA, 2018). India has around 80 GW of installed capacity in the form of captive power plants owned by industrial customers for localised production and use, stemming from the need for uninterrupted and affordable power supply for industry, amid relatively high industrial power tariffs. Captive power plants exist in diverse industries, including steel and iron, aluminium and metals, cement, chemicals, fertilisers, paper, textiles, sugar and engineering. The captive plants run on coal (54 GW or 68% of the total), natural gas (9.5 GW or 12%), diesel/fuel oil (3.5 GW or 4%) and renewables (bagasse, biomass, wind and solar) (15 GW or 16%). Load factors have been low for captive plants in the past two to three years, as the state-driven reduction of coal imports has led to a shortage of domestic coal, which has been mitigated by prioritising coal deliveries to critical power plants supplying residential and commercial users rather than industrial consumers.

System operation

India has achieved the integration of the five unsynchronised regional state grids, a process which started in the 1990s and was completed in December 2013. In 1991 the north-eastern and eastern grids were connected. In March 2003 the western region was interconnected, and in 2006 the northern grid was interconnected. This created four synchronously connected regional grids, northern, eastern, western and north-eastern, forming a central grid operating at one frequency. On 31 December 2013 the southern region was connected to the central grid in synchronous mode, thereby achieving “one nation-one grid-one frequency”.

POSOCO operates the single NLDC and five RLDCs. The world’s largest synchronous power system is operated via the NLDC, the five RLDCs and 33 State Load Dispatch Centres (SLDCs). The central-level power dispatch is divided into five regions: northern, western, southern, eastern, and north-eastern. DISCOMs work with SLDCs or have their own load dispatch department.

Power market reforms

The structure of India’s power sector is the result of a long history of reforms, which were driven by the need to provide affordable, cleaner and secure electricity to the country’s growing population.

India’s Electricity Supply Act was first enacted in 1948. State electricity boards were set up and in 1951 the CEA was created to carry out the planning of the electricity sector.

160

IEA. All rights reserved.

7. ELECTRICITY

The National Thermal Power Corporation (NTPC) and the National Hydro Power Corporation (NHPC) were created in 1975.

In the 1990s the Indian electricity sector was partially liberalised, with unbundling and privatisation (only one state electricity board was privatised). The 1998 Electricity Regulatory Commissions Act introduced the CERC and state regulators. The MoP enacted several State Reform Acts to modernise the power system at the state level and encourage private players to enter the generating sector as IPPs. The Electricity Act 2003 marked a complete overhaul of the sector and consolidated the many reforms that started in the 1990s. It removed licensing for the generation sector to create competition, but maintained the licensing of transmission and distribution operations. The 2003 act introduced open access to transmission and distribution.

The development of a competitive electricity market has been the key objective of the Electricity Act of 2003 and CERC has been the main driver of reforms, supported by the CEA. The Electricity Act of 2003 reinforced the role of the regulators – it mandated the creation of Electricity Regulatory Commissions in every state.

The National Electricity Policy 2005 provided guidelines to ensure access to electricity for all by 2012 and to foster the financial viability of the power sector, while keeping in view resource availability and security. The policy set out the strategic steps for securing private investment in the power sector, through captive power generation (large users), spot trading on exchanges and the formation of the Rural Electrification Corporation of India, aiding rural village electrification.

Market integration across India proceeded in several steps. In 2004 open access to transmission and distribution was introduced and power trading allowed. In 2007 the CERC guidelines created the power exchange. Only in 2008 was open access introduced to interstate transmission, which facilitated electricity trading at the exchange. In 2012 the 15-minute block became a new product at the exchange. To maintain grid discipline amid large power outages and frequency dips, CERC introduced unscheduled interchange charges in 2009, which were subsequently replaced by the Deviation Settlement Mechanism in 2014. Further, the Ancillary Services Mechanism was introduced in 2016 to reduce congestion, increase power trading and stabilise grid frequency. As one of the last milestones for regional trade across India, CERC established regulations governing the communication system for interstate transmission of electricity.

India’s central generators have an availability-based tariff (ABT), which is a frequencybased pricing mechanism for unscheduled electric power transactions. It was conceived to provide incentives and disincentives to grid participants against deviations in committed supplies. On the positive side, the ABT has streamlined the grid and system operation. Generator’s schedules are determined as per their share of generation in central stations. Any constituent that helps others by under-drawing from the regional grid in a deficit situation is compensated for the energy under-drawn. Second, the grid parameters, i.e. frequency and voltage, have improved and equipment damage correspondingly reduced. During peak load hours, the frequency can be improved only by reducing drawn electricity, and necessary incentives are provided in the mechanism to achieve this. A high frequency situation, on the other hand, is checked by encouraging a reduction in off-peak generation. Third, because of the clear separation between fixed and variable charges, generation is better aligned with its cost to the merit order. Fourth, a mechanism is established for

161

ENERGY SECURITY

IEA. All rights reserved.