In a recent interview with Indian Infrastructure, Ghanshyam Prasad, chairperson, Central Electricity Authority (CEA), discussed the progress made by the power sector over the years and his outlook for energy transition. He also spoke about the CEA’s key initiatives, as well as its top priorities and focus areas going forward. Edited excerpts…
What is your assessment of the current state of the power sector?
The power sector has grown significantly over the last few years, especially in the last five to seven years – be it in terms of generation capacity addition, transmission expansion or distribution reforms. Energy deficits, which could go up to over 10 per cent 10 years ago, have fallen to practically nil and remain at less than 1 per cent today. That too is attributable to distribution issues and local faults. In the transmission segment, we have recently had instances of over 25,000 ckt. km being added in a year. We have added 183,662 ckt. km of transmission lines since April 2014. The interregional transmission capacity has also grown to about 112,250 MW, and electricity transfer between regions has become easier. Consequently, there is no market splitting in the country. Earlier, the Indian power market operated in different zones even within a single region, with differences in market prices.
Furthermore, we are connected with our neighbouring counties (Bhutan, Nepal, Bangladesh and a small link with Myanmar). We are targeting more interconnections with Sri Lanka, Singapore and Oman. These interconnections are a part of the “One Sun, One World, One Grid” concept promulgated by our honourable prime minister. We are exploring options to expand to the neighbouring regional grid of Southeast Asia (Singapore, Indonesia, etc.) and thereafter connect with Europe through Oman and Saudi Arabia.
Our generation and transmission businesses are healthy. There have been issues with the distribution business, and a number of reforms have been undertaken. The erstwhile delays in payments from discoms to generating companies and transmission companies affected the entire value chain of the power sector. In the past, discom dues had reached as high as around Rs 1,350 billion. To tackle this, the Ministry of Power implemented the Late Payment Surcharge Rules. Consequently, the current dues started getting paid on time, mainly because the discoms were aware that they would not be able to access the market if they failed to pay by the due date. Moreover, after the second instance of default, their long-term access would be curtailed. The government has devised a mechanism whereby the discoms could repay their past dues in instalments. This is a good initiative and most discoms with past dues have come on board, making the liquidation of past dues successful. About 60 per cent of the past dues were liquidated in just over a year. This made generation and transmission companies and coal companies, in turn, viable. Hence, all these segments have become investor-friendly, and people have started investing in renewables and transmission as well.
How do you rate the performance of the power sector in advancing energy transition?
We are in sync with the global target, in fact, we are ahead of it. We have fulfilled the commitments made at the COP20 summit (Paris). We are on track to achieve the commitments made at COP26 of increasing the share of non-fossil fuel energy to 50 per cent. Currently, the share of non-fossil fuels is at 43 per cent, and increasing it to 50 per cent in the coming seven years is definitely achievable. We are adding more and more renewables. The share of non-fossil fuel will keep increasing, with proportionate reduction in the share of fossil fuel. To quote a number from our CEA study, we shall achieve around 65 per cent non-fossil fuel capacity by 2030.
“The share of non-fossil fuels is currently at 43 percent; increasing it to 50 per cent in the coming seven years is definitely achievable.”
What are the new and emerging requirements of transmission system planning to manage the growing amount of renewable energy?
There were concerns about the availability of adequate evacuation infrastructure for renewable energy plants, because the gestation period of transmission lines is longer than that of renewables. A solar plant can be built in 18 months to two years, but transmission lines require three to four years. To tackle this, we have adopted “transmission ahead of generation”. For renewables, transmission evacuation plans and execution start early, as they are based on the potential area. We have already provided visibility for up to 2030, targeting about 535 GW of renewables. Several transmission lines have been built, accommodating over 175 GW of renewables. Some lines are in the pipeline, and certain others are under bidding. The process is phased because we do not want stranded transmission lines, as certain renewable projects are not getting commissioned soon.
What is your perspective on the current competitive landscape for TBCB? How has it evolved, and what is the outlook?
Initially, there was resistance in the industry against building transmission lines under the tariff-based competitive bidding (TBCB) route. We allowed experienced infrastructure players to set up transmission infrastructure. Consequently, we now have multiple players. This is mainly because now there is long-term visibility of a stream of transmission projects. Thus, even more players are coming in. Earlier, visibility was limited due to the lack of pipelines. Now, we have a project pipeline for transmission up to 2030.
Moreover, we are trying to dynamically plan transmission lines. Resolving the dissonance between planned and actual generation requires system upgradation. Earlier, planning was done every five years, with significant changes. Such adjustments are now being done every six months and uploaded on the website. Thus, the central transmission utility, in consultation with the CEA, is attempting dynamic transmission planning and execution, which is unprecedented in India.
“We are laying down several checks and balances to ensure that discoms have optimal financial and operational performance.”
What more needs to be done in the power distribution segment?
The distribution sector needs to be viable, and we have taken certain steps for this. We have introduced the Revamped Distribution Sector Scheme (RDSS). We are also laying down several checks and balances to ensure that discoms have optimal financial and operational performance. For instance, we have mandated that the subsidy amount has to be paid to the discoms on time, government dues have to be liquidated, etc. We are also advocating for cost-reflective tariffs. Thus, with timely subsidies as per Section 65 of the Act, liquidated government dues, timely payment from customers (or prepayment), etc., a healthy cash flow is expected for the distribution business.
What is your outlook for the power demand in the country in the near to medium term? Where will
our power demand be, and are we prepared to meet that?
We are prepared to meet the growing power demand in the country, as we are planning capacity additions 5 to 10 years in advance. The demand reached 240 GW this year in August, which is unprecedented – this does not happen in August, generally. If we had not been prepared, we would have defaulted in meeting this demand. Even at 240 GW, the shortfall was less than 1,000 MW (or less than 1 per cent). This happened because of the existence of 70 GW of solar plants in the system. Solar contribution matches with the demand profile of the country. So, we shall continue adding solar while simultaneously trying to shift the evening peak load to day hours. This would suit the solar profile, helping us go green and aiding energy transition, while ensuring that the demand is met during solar hours.
What are the unresolved issues in the power sector?
The biggest challenge is to make the entire sector viable, with the current focus being distribution. We will certainly achieve our goals, with reforms and measures – the RDSS, rules for cost-reflective tariffs (also mandating a proper governance system), potential norms for loans, etc.
What is your outlook for the power sector in the near to medium term? According to you, what are the top trends that are going to dominate, going forward?
We seek faster energy transition, with the addition of more renewables. For India, the development of hydropower and hydro pumped storage is crucial. The new hydro policy is out; we have expedited the concurrence process for hydropower projects to 90 days, under Section 8 of the Act. The first project – at Upper Sileru in Andhra Pradesh – was concurred by the CEA in 75 days under this rule. We have multiple teams and have implemented single-window clearance under the CEA, supported by the Central Water Commission, the Geological Survey of India, etc.
We now have a pumped storage plant (PSP) capacity of 4,700 MW (of which 1,200 MW is non-operational). Thus, achieving the target of over 40 GW in seven years will be a challenge. About 2,700 MW will be commissioned next year. About 30,000 MW is at advanced stages of detailed project report preparation and concurrence. We are targeting about 8 GW by 2026-27, and at least another 30 GW by 2030, with about 50 GW (including the above) under survey and investigation. Out of the 50 GW, tapping even 35-40 GW should be sufficient, reducing battery storage requirements. The latter has several nuances, such as import, regular investments and disposal. We shall add battery storage for system reliability and security, but our preference should be hydro PSP.
What is your outlook for the power market?
In the power market, there is a need for holistic integration. Security constrained economic despatch (SCED) is already operational. The Central Electricity Regulatory Commission and Grid-India are working on expanding the current intra-day SCED to a day-ahead basis. Essentially, the role of such mechanisms (power market, SCED, power purchase agreements, PUShP and DEEP portals, etc.) is optimisation – maximising generation and meeting demand. Ultimately, I would like to see everything being integrated. We are also looking into the development of the renewable energy market. The concept is with the MoP, and we intend to implement it soon after getting approval. Numerous renewable players are now keen on banking on the market, requiring a counterparty so that investments are not stressed or stranded.
What have been the key initiatives that the CEA has taken in the last one year or so?
The first is the concurrence process for hydro. We now have several hydro projects already kicking. Previously, the private sector would not enter the hydro business. But all the PSPs mentioned earlier are private, reflecting stakeholders’ confidence in the CEA’s reforms. Second, we have transformed the transmission business and given it greater visibility. Third, in an unprecedented move, the CEA has undertaken resource adequacy (RA) planning, along with state-specific renewable energy plans. From next year, every discom should have RA plans, which are essential for 24×7 electricity supply. We have also started monitoring renewable energy. The post of member (renewable energy) is likely to be operationalised soon, along with a renewable energy vertical, to ensure specific focus on solar, wind, storage, green hydrogen, etc. We have also constituted an Advisory Committee for the first time at the CEA, and intend to leverage the expertise of the committee and explore new concepts and areas of development.
What are some of the upcoming studies and initiatives of the CEA?
One of them is the RA Plan. For the National Electricity Plan, the generation chapter has already been published; the draft transmission chapter has been sent to the ministry. We are in the middle of building the National Distribution Plan. The previous one could not be published, but was used for preparing the RDSS. So, with generation, transmission and demand finalised (the 20th Electric Power Survey is already out), our focus is on distribution.
What are the key priorities and focus areas of the CEA?
Our priority is the RA Plan, as we do not want to recede into a power-deficit era from the current power-surplus state. We have reassessed our rapidly growing demand and would like to see commensurate capacity addition. Hence, monitoring of power projects has become a priority for us. Second, we must ensure grid security with increasing renewable energy integration and resultant variability. The third priority is hydro addition, and a vibrant electricity market is the fourth.
All the resources in the country should be optimally utilised. The CEA recently launched the PUShP portal, where any entity with surplus power can submit its intent for it to be deployed by any buyer or seller, at a price already fixed by the commission. So, these capacities are now getting utilised by power-deficit states; some power-surplus states are also gaining from this by shifting their fixed charge liabilities to other entities. Several states, such as Telangana, Assam, Meghalaya, Mizoram and smaller states, use this portal and have benefited from it. We are likely to expand the portal, incorporating banking provisions to facilitate power banking for interested entities with surplus electricity.
