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ramping capability to cope with the “duck curve” in the morning and evening hours. Wind integration requires transmission and balancing capacity to keep up with wind power’s strong seasonality. Better regional interconnections across India’s regions and more flexible power plants besides storage are critical. Hydro generation is at a maximum in the month of July, as is wind power, which therefore limits the way these sources can complement each other. Chapter 8 on system integration focuses on key sources of flexibility, that is interconnections, demand-side response, storage and power plant flexibility.

Assessment

In 20119 India had installed power generation capacity of 366 GW, 7 with coal-fired generation (204 GW), solar (33 GW) and wind (37 GW), followed by hydro (50 GW) and natural gas (25 GW). Grid-connected solar PV has been growing particularly quickly, with around 25 GW added alone during 2013-18. Biomass accounts for10 GW and small hydro for 4.5 GW. It is coal power that continues to dominate the generation mix with a contribution of 74%, followed by hydro at 9.3% and natural gas at 4.6% in 2017.

Peak electricity demand in India stood at approximately 165 GW in 2017, but recent data suggests that peak demand surpassed 180 GW in late 2018. Unavailability due to the age and low efficiency of the plants aside, this margin indicates a considerable amount of surplus in the dispatchable capacity. 8 Demand has been growing more slowly than anticipated in recent years at an annual average of 5%, notably below expectations in the industrial sector. Loads are expected to grow in the residential segment, driven by cooling demand as well as to some degree by increased access to electricity.

India has made remarkable progress in connecting its citizens to the electricity grid in recent years. In 2018 the GoI announced that all villages had been electrified, and that all households had reached full electricity access in March 2019. States that have traditionally featured the lowest levels of electricity access in the country (like Bihar, Assam, Orissa or Uttar Pradesh) have made substantial progress in their efforts to roll out electricity access. This development can only be commended and is an important step to remove the shackles of poverty from hundreds of millions of people, not least women and children. This will enable increased economic productivity, growth and bring modern-day comforts to the entire country.

However, connection to the electricity grid is not identical to around-the-clock supply. Notably, the power system has been marred with frequent load shedding for decades, and while interruptions are going down, they are still a normal part of life for many citizens. The GoI has set a target of providing 24/7 access to electricity across the country. However, reaching this objective requires action at the state level. States control electricity distribution and supply via the predominantly state-owned DISCOMs.

India has largely focused on the adequacy of power generation to meet peak demand and ensuring adequate fuel supply, with energy planning under the CEA, in particular via the

7Excluding captive producers.

8There is a substantial number of so-called central-level plants, where multiple states have a right to receive a share of the generated electricity and pay a proportionate share of the costs (in total of 84.5 GW, of which 57 GW are coal, 12 GW are hydro and 7.2 GW are natural gas).

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National Electricity Plan, drafted by the CEA and prepared under the aegis of the MoP and in consultation with POSOCO, state governments, CERC, NITI Aayog and various other stakeholders. The power system in India is in transformation and most growth is expected to come from solar PV, most of it located behind the meter and not visible to system planners and dispatchers.

To improve its assessment of adequacy, India will need to consider energy efficiency impacts in energy system planning. The National Electricity Plan would benefit from better demand data (which would stem from the scale-up of smart meter roll-out coupled with data management and analytics). Moreover, transmission planning in India is not yet carried out to ensure network adequacy for the new ambitious renewable target of 450 GW and expected contributions from battery storage, reflecting the need to consider the mix of different stakeholders at the state level, private/public utilities and merchant investors.

The apparent contradiction between ample generation capacity and unmet demand points to the core challenge of the Indian power sector: the financial viability of its DISCOMs. Retail electricity tariffs are heavily subsidised by state governments, as well as via crosssubsidies from industrial and commercial sectors to residential consumers. Revenues are further challenged by very high losses. AT&C losses in India average approximately 20% and vary across a wide range (up to 50% in some states) according to recent government data. Compared to many other countries, commercial losses are very high. Most DISCOMs do not earn money by supplying residential customers, but rather accumulate losses by doing so. Interruption of supply to such consumers is thus one of the tools that DISCOMs have available to reduce their financial losses. These practices have cemented a low quality of supply, which in turn has created an expectation on the side of customers that they should pay very little for electricity – or nothing at all. This feedback loop and subsidy trap is a core reason behind the stubbornly high AT&C losses in many states.

Being a hotly debated topic for decades, the government has taken steps to tackle this situation, most recently in 2015 via implementing a reform package known as the UDAY scheme. The core idea of this scheme is to transfer 75% of the DISCOMs’ debt, which stood at USD 60 billion (INR 4.3 trillion) in financial year 2014/15, to the states. In turn, DISCOMs are committed to more stringent enforcement of metering, accounting, billing and revenue collection in order to cut AT&C losses and improve revenue. In addition, a target was set that electricity tariffs could only be set within a band of +/- 20% of the average cost of supply – any tariff below this band would have to be paid for by the states to the DISCOMs. The scheme has had some successes, but many DISCOMs still run substantial losses, and while metering has improved, the collected revenues often remain well below the cost of supply. In fact, the GoI has announced measures to ensure future conditionality of loans to DISCOMs based on achievement of actual loss reductions.

In contrast to the residential sector, commercial and industrial customers are financially attractive for DISCOMs since they pay higher tariffs covering not only the cost of supply, but also a cross-subsidy to offset part of the losses incurred in the residential sector. However, the comparably low reliability of electricity supply has triggered the widespread adoption of back-up power solutions and captive generation in these segments. There is substantial uncertainty over demand for DISCOMs and other system operators, as industrial clients are increasingly deciding to purchase power via open access or choose autoproduction (captive plants), while sometimes, however, switching back to DISCOMs.

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Agriculture is a large burden for DISCOMs, too, as they cannot cover their costs. Electricity needs in agriculture are primarily driven by water pumping. Because pumps can be operated with a degree of flexibility across the day, this consumption is highly flexible and can match the availability of solar output and water needs. But still, in many states water pumping is done during the night-time and could be shifted to the daytime when there is greater solar PV penetration. Separating agricultural feeders from the rest of the grid and supplying agriculture directly with solar PV can dramatically reduce supply costs for DISCOMs, hence reducing losses while also boosting variable renewable energy generation.

For energy-intensive industries, captive subcritical coal plants have been the option of choice, with total capacity at 80 GW (68% of all captive plants are larger than 1 MW) in 2017. The number of back-up generators running on diesel is even higher than this, with estimates around 140 GW. While these options can provide commercial and industrial consumers with the required reliability, they come at a very high cost, especially if relying on diesel. Assuming a diesel price of USD 1/litre, per-kWh costs are in the range of USD 0.25-0.30/kWh. Triggered by the high price of diesel for back-up power for smallscale captive applications, solar PV has emerged as a cost-effective option for offsetting grid-based electricity for smaller industrial and commercial customers. Combined with batteries, this option not only helps reduce electricity bills, but can also guarantee reliable supply. The widespread adoption of such options poses an additional financial risk for DISCOMs, but it could also be an opportunity for adding flexibility to the power system if electricity tariffs are reformed (see Chapter 8 on system integration).

The general insufficiency of revenue and non-cost-reflective tariffs are among the major challenges. Reform of tariff structures – while politically challenging to implement – are ultimately required to ensure the long-term functioning of the sector. Additional steps need to be taken to ensure the efficiency of retail markets by improved metering, accounting, scheduling, billing and revenue collection at state level. The push for advanced technologies such as smart meters can help reduce AT&C losses, increase the efficiency of the system and provide for the adoption of innovative approaches to targeted subsidy payment to protect certain segments of customer. In addition, further reforming the DISCOMs through the unbundling of grid and retail business, i.e. separation of carriage and content, can open up improved operations in the grid and the financial viability of both segments. In order to continue to move towards open access and enabling customers to choose their supplier, fair and transparent access to the grid is crucial.

The poor financial position of DISCOMs also has repercussions at the wholesale level. Wholesale markets in India are currently dominated by long-term PPAs between generators and DISCOMs. DISCOMs pay an ABT that recovers capital and fixed costs (capacity payment) independent of the plants’ use, and a variable cost depending on its dispatch (fuel cost payment). Around 90% of all the electricity supply in India is covered by such agreements. As frequency deviation is no longer a real issue, the ABT may no longer be compatible with the power system in India.

While the ABT was successful in fostering India’s power availability and investment, the way it has interacted with the wholesale market has now become a major source of inefficiency and overcapacity. These contracts have been interpreted as physical contracts, without the possibility of taking advantage of cheaper surplus energy to be purchased from other generators or even from other DISCOMs. Combined with problems of fuel supply, this has created a situation in which inefficient and polluting generators can

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have higher utilisation than newer and more efficient plants. The vision of CERC and its proposal on the creation of a market-based economic dispatch addresses these concerns and could help improve the economic efficiency of the system.

The poor financial position of DISCOMs translates into payment delays to generators. Indeed, approximately 40 GW of coal capacity and 25 GW of gas-fired capacity has been considered a stressed asset, due to lower than expected demand and utilisation, and payment delays from DISCOMs. One crucial measure to alleviate this situation is the retirement of old, inefficient capacity. Notably, the MoP has identified approximately 20 GW of old capacity that will be retired over the coming years, adding to 8 GW of retirements that have occurred over the past five years. While such measures bring important benefits also from an environmental perspective, they are not sufficient. What is needed is a more comprehensive reform of wholesale electricity markets.

Reforming wholesale markets with a view to enhancing operational efficiency is a priority, against the background of rising shares of variable generation. Today 90% of electricity is traded in the form of highly inflexible PPAs and the vast majority of interstate transmission capacity is reserved under long-term agreements. Boosting the liquidity on day-ahead and intraday markets, as well as establishing real-time/balancing markets and ancillary services markets, should be priority areas for regulatory action. Finally, mechanisms for unlocking more efficient use of interstate transmission and managing congestion are needed.

While the possible benefits from introducing comprehensive wholesale market reforms have been laid out, notably by CERC, it will not be easy to implement such comprehensive reforms in India’s complex energy governance structure. In this context, wider awareness of the possible benefits of such reforms – both for consumers (via reduced costs for DISCOMs to buy power on wholesale markets) as well as investors and owners of stressed assets (via increased utilisation) – will be key.

Apart from supply-side reforms, the demand side will be of paramount importance for the future of the Indian electricity system, as load is expected to double up to 2030. A large proportion of this will come from buildings, in particular for space cooling. The demand side will also be critical for improved integration of renewable energy (see section on system integration).

The DISCOM governance model needs to be restructured. Governance needs to be improved through appropriate monitoring, control and financial oversight. At the retail tariff level, greater rationalisation is critical with a tariff system that allows all market participants, industrial, commercial or residential participants to purchase electricity. DISCOMs need to be required to perform in accordance with public policy objectives, thus ensuring quality of supply, investing in metering and smart grids, making infrastructure upgrades such as feeder separation, and undertaking detailed data collection and analysis.

While smart meters do not directly result in end-use energy savings, they can enhance or enable savings opportunities by providing consumers with actionable information about their energy consumption. Smart meter data can also be used to validate efficiency project savings. However, smart meter deployment has been very slow, despite legal requirements and monitoring under the GoI UDAY scheme. Enacting a broad set of standards for power quality can be a cost-effective way of improving the performance of the grid and avoiding costly interruptions in electricity supply, especially for industry. Power

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