There is a need to expand the transmission infrastructure in order to support the growing renewable capacity. However, the shorter gestation period of renewable energy projects vis-à-vis transmission projects is a key challenge. A more coordinated transmission planning approach will facilitate the ongoing energy transition. In the session “Future of Power Systems and Grid”, sector experts discussed the transmission constraints being faced, possible solutions and the way forward. The speakers included K.V.S. Baba, chairman and managing director, Power System Operation Corporation Limited; Pankaj Batra, chair, Working Group 4, India Smart Grid Forum; Rajesh Kumar Mediratta, director, strategy, Indian Energy Exchange and J.N. Swain, managing director, Solar Energy Corporation of India. An overview of the discussion…
Transmission constraints for renewables
A key concern for renewable energy developers is transmission constraints. While a renewable energy project typically takes 18 months to get commissioned, the evacuation infrastructure takes about 36 months. When renewable energy developers or aggregators like the Solar Energy Corporation of India (SECI) seek transmission connectivity from the central transmission utility (CTU), the latter asks developers for long-term access (LTA). But LTA is typically applied for only when the tenders are finalised and contracts are awarded. Also, when the CTU approaches the regulator for approval of transmission schemes, it has to justify the power demand. But demand is latent in most cases. So this creates a chicken-and-egg situation where the transmission network provider or planner waits for projects to come up in a firm way before building transmission lines. However, renewable energy developers, when bidding for a tender, look for the availability of associated transmission infrastructure before they commit funds. Since some transmission infrastructure has been built under the Green Energy Corridors project, SECI’s initial bidding rounds saw a good response, but now more and more bidders are facing connectivity problems.
At present, SECI has PPAs for about 25 GW of solar and wind capacity. A significant part of it is connected to the CTU network and the remaining to the state transmission utility network. However, each state has different policies for evacuating renewables. For rooftop solar, certain states have stringent limits on how much electricity can be injected into the grid. As per the system operator, the actual problem is not building the transmission network but paying for it because the states do not want to bear the point of connection (PoC) charges. So, technically, renewable energy integration is not an issue, it only depends on transmission charges and the concurrence of states (to pay for those charges). In order to address this issue, the PoC formula is being reviewed by the government and it is likely to be replaced by a new formula, which will be more acceptable to the states. Further, in order to overcome the transmission constraints, the central government has planned a phase-wise development of the transmission network for evacuation of 66.5 GW of capacity, in Rajasthan, Gujarat, Maharashtra, Karnataka, Andhra Pradesh and Tamil Nadu. The first phase is already over and approvals are being sought for the second phase, while the third phase is under planning by the Central Electricity Authority.
In the past, similar transmission-related issues were faced by NTPC Limited and Power Grid Corporation of India Limited. While a thermal power plant takes 48 months for completion, a transmission line is ready in 36 months. So the transmission operator (Powergrid) and NTPC entered into indemnity agreements to protect the interests of the party whose project is completed first yet unutilised owing to delay by the second party. Similar agreements can be signed between renewable energy developers and transmission companies to tide over these issues in the short term. Also, the CERC’s Tariff Regulations 2019-24 have a provision that if there is a mismatch in the commercial operation date of the generation and transmission projects, then the defaulting entity will pay transmission charges to the entity whose project is ready.
India has a unique set of challenges with regard to the evacuation of renewable power. Such issues were not encountered in the Americas or Europe. In continental Europe, the grid is quite dense and the transmission network is deeply interconnected so connectivity issues did not arise. In other countries, the grid is huge and is driven by a strong policy. If a project is required to be commissioned in a certain time frame, the transmission system operator will establish it by the due date or the stakeholders will be compensated in an appropriate manner.
Future energy market
Transmission has been a key enabler for power market development. Grid curtailment is no longer an issue in the interstate transmission system (ISTS) though it arises sometimes at the intra-state level. In the day-ahead market (DAM), grid curtailment stands at about 0.5 per cent at present as compared to 5-10 per cent three years ago. This has been made possible with the addition of significant transmission capacity at the interstate and interregional levels. Also, reserve regulated ancillary services are implemented in case of any issues of demand or supply imbalance. In the coming years, ancillary services will be upgraded to a more market-based model. Further, the grid’s frequency profile has improved as the frequency is within the stipulated 49.50-50.05 Hz band almost 80 per cent of time. There are no plans to further tighten the frequency band because that makes real-time grid operations harder. With the growing focus on decarbonisation, the power market requirements will change. The share of renewables in the energy mix is expected to increase from 8 per cent to 15 per cent by 2022. When the power exchanges started functioning, the consumers used trading platforms to meet only their residual power demand. However, the scenario has changed in the past five years. Now, consumers depend on the power market to optimise their power purchase costs. Going forward, there are plans to introduce a real-time market, which will provide more options to discoms and other consumers to manage their power mix depending on the intermittency of renewable sources.
Role of distribution
Distribution reforms are imperative as this is the most problematic segment in the sector. Most of the problems are due to governance issues. Many grid-related issues can be resolved if the distribution segment is robust. For instance, implementation of demand response initiatives by discoms can help deal with the variability and intermittency of renewable generation. Automatic demand response provides incentives to consumers to reduce demand. The use of ancillary services to support the grid can be halved if demand response initiatives are introduced. Some advanced countries are already implementing demand response.
Discoms are also hampering the adoption of rooftop solar as there is a perception among discoms that they will lose their high-paying consumers. That said, distributed generation through rooftop solar is the way forward for the sector. The discoms should see it as an opportunity rather than a challenge. Steps must be taken to create awareness among prosumers, install right metering systems and provide appropriate incentives/tariffs. Further, distribution networks need to be strengthened to be able to absorb the growing renewables. At present, discoms are not accountable and if something goes wrong, they simply cut power supply. This will change if the amendments to the Tariff Policy, 2016 are approved, which will penalise discoms for unnecessary power cuts. Given the increased focus on reliability and flexibility, there is a need for decentralised control and technology intervention. A few private discoms are undertaking renewable energy forecasting. With growing rooftop solar, digitalisation will be crucial for all discoms. At the transmission level, renewable energy management centres are being set up and similar initiatives are required at the distribution level as well.
The way forward
Going forward, energy storage is expected to come up in a big way. The price of electrochemical batteries has reduced by over 70 per cent in the past seven years and is likely to reduce further by 10 per cent by 2020. A lot of research is under way in this field and the cost of batteries is expected to reduce to $100 per kWh. On the transmission planning front, general network access is expected to help resolve the current issues and pave the way for the growth of the power sector.