How can India Meet Peak Power Demand With Clean Electricity?

REPORT

How can India Meet its Rising Power Demand?

Pathways to 2030

12 March, 2025 | Power Markets

Disha Agarwal, Arushi Relan, Rudhi Pradhan, Sanyogita Satpute, Karthik Ganesan, and Shalu Agrawal

Suggested citation: Agarwal, Disha, Arushi Relan, Rudhi Pradhan, Sanyogita Satpute, Karthik Ganesan, Shalu Agrawal. 2025. How can India Meet its Rising Power Demand? Pathways to 2030. New Delhi: Council on Energy, Environment and Water.

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Supporting Document

Overview

India’s electricity demand is growing fast with rapid economic development, urbanisation and climate-induced heat stresses. Since FY21, India’s electricity consumption has risen at ~9% per annum, compared to an average of 5% annually in the preceding decade. This study assesses various pathways that India can take to reliably meet the electricity demand in 2030. For this, the study models India’s power system despatch for every 15 minutes in 2030 with existing and planned generation capacities, and interstate and interregional transmission constraints to answer two critical questions. One, can India meet its projected 2030 power demand with existing and planned capacities? Two, if the demand grows faster than projected, what will be the cost-effective pathway for India to meet the demand reliably? Based on an assessment of current grid and on-ground challenges, it then provides a seven-point agenda for the Ministry of Power (MoP), Ministry of New and Renewable Energy (MNRE), and other central and state agencies to realise the benefits of the most desirable pathway.

Key highlights

India’s existing, under-construction, and planned generation capacities, with 500 GW non-fossil capacity, will be adequate to meet the EPS projected power demand for 2030. However, the country may face power shortages if we fall short of meeting our RE targets.
- If India reaches only 400 GW of non-fossil capacity by 2030, 0.26% of the demand will not be met. It will need an additional 10 GW of coal capacity and significant transmission enhancements by 2030 to meet the reliability criteria.
If demand grows faster (at a CAGR of 6.4% instead of 5.8% between 2023 and 2030), existing and planned capacities will be inadequate.
- Even with 500 GW, India will face significant power shortages throughout the year (0.32% demand not met) and will need to add new resources to meet the demand reliably. This will include 6 GW of new coal-based capacity (beyond 27 GW already under construction in 2022).
A high RE pathway will be most cost-effective in meeting higher demand despite increased flexibility requirements. We modelled three different generation mixes (with 400 GW, 500 GW, and 600 GW of non-fossil capacity in 2030). We found that:
- 600 GW of non-fossil capacity distributed across states will help deliver reliable supply at lower costs (by 6-18 paise per unit) and save INR 13,000 - 42,400 crore in procurement costs in 2030. Most of the savings will accrue because of higher shares of cheaper RE generation in the mix.
- Adding 100 GW of RE will also yield higher social and health benefits, including 53,000-1,00,000 more jobs and 13-23% lower emissions of carbon dioxide and air pollutants (PM2.5, PM10, etc.), compared to 500 GW and 400 GW pathways.
- With 600 GW, the system will have 4-6% higher supply margins to deal with uncertainties. The margins will be critical to reliably meeting demand in stress months.
- If India achieves only 400 GW, the system will face major power shortages. It will need to add 16 GW of new coal capacity. The system will also need significant transmission enhancements: 50 GW of interregional and 16 GW of interstate capacities.
Several challenges restrict the pace of RE deployment, integration, and offtake. These include delays in land procurement, the slow pace of transmission expansion, delays in grid connectivity, and supply-chain constraints. It is urgent and possible to overcome these bottlenecks through continuous innovation in policy, bid designs and contracting structures for procurement of RE and energy storage, market design reforms, and other strategic interventions.
Integrating 500-600 GW of clean energy capacity by 2030 will increase the system ramping requirement by 5-6 times over 2022, indicating the need for more flexible resources. Despite the high flexibility needs, flexible options (like energy storage, transmission, and frequent starts of coal units) will make up only 2-7% of the overall system cost.
Effective maintenance of the existing coal fleet is essential to meet demand reliably and provide the desired flexibility. With 500 GW of non-fossil capacity, coal will continue to play a major role in meeting the higher demand reliably. Around 60 per cent of the generation during non-solar hours will be coal-based. The months of higher unavailability of coal (October and November) coincide with the months where coal dependency is high (75–78% share in generation). Thus, timely maintenance and preventive measures can help prevent technical outages.
Harnessing demand flexibility will lower the need for battery storage and save costs. We quantify these benefits in one scenario, with 600 GW non-fossil capacity and EPS-projected demand. We find that a 24 GW demand shift in 10 states from peak net load hours to non-peak net load hours can help avoid the requirement of 30 GW of BESS capacity and thus lower system costs by INR 14,000 crore (USD 1.6 billion).

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Disha Agarwal

Senior Programme Lead

[email protected]

“India already has the third-largest operating renewable energy fleet globally. Now is the time to collaborate, innovate and shape a new electricity system to make India the world’s fastest-growing green economy”

Executive summary

Since 2014, India has simultaneously improved access to electricity, addressed energy security concerns, and laid the foundation for a clean energy transition. India’s power system has evolved significantly since the 1990s (Figure ES1). India became the world’s third- largest producer of electricity in 2019 (IEA 2021). By 2020, 96 per cent of the households were electrified (Agrawal et al. 2020). The country saw a fivefold increase in solar and wind power capacities between 2013 and 2022, making it amongst the top four renewable energy (RE) installers globally (PIB 2024a). Notwithstanding these achievements, India faces the unique and complex challenge of decarbonising its expanding power system while providing reliable and affordable electricity to meet rising demand.

The Central Electricity Authority (CEA), in its 20th Electric Power Survey (EPS), projects that India’s FY30 electricity requirement and peak demand will both grow by 6.4 per cent per annum, from FY22 (CEA 2022a). However, recent trends show ~9 per cent annual growth in the electricity requirement since FY21, compared to an average of 5 per cent per annum in the decade before (CEA, n.d.-d). The EPS demand estimates for 2030 consider baseline projections for green hydrogen production, rooftop solar penetration, electric vehicles, and other sectors based on extant policies. One-third of this electricity demand is likely to be consumed by the industrial sector. Considering the push to decarbonise the industrial sector through electrification, the industrial electricity demand is expected to grow faster than anticipated. This would result in a higher electricity demand than that projected by the EPS. For instance, the impact of producing 5 million tonnes (MT) of green hydrogen in the context of an interconnected grid system could result in a 13 per cent higher electricity requirement than that projected in the EPS for 2030 (Pradhan et al. 2024). Additionally, economic growth, urbanisation, and climate–induced extreme weather events are likely to influence demand growth and make it more uncertain.

While the supply side has responded to the growing demand, capacity addition has been slow in recent years due to a combination of domestic and extraneous factors. For instance, as of August 2024, over 30 GW of coal capacity is under-construction, 19 GW of which was awarded before 2019 (CEA 2024c). Simultaneously, India has deployed only 3 GW of hydro and nuclear capacities and about 90 GW of RE capacities between 2019 and 2024, resulting in around 218 GW of total non-fossil based capacity (CEA, n.d.-b).1 The country still needs to deploy around 56 GW of non-fossil based capacity every year between 2025 and 2030 to meet its 500 GW of non-fossil capacity target by 2030 (CEA, n.d.-b, PIB 2023d).

These trends raise a critical question: how should India plan for adequate resources to meet its energy and peak power requirements by 2030? Answering this question requires an assessment of alternative scenarios the country may face and be prepared for such possibilities. For instance, would India be able to reliably meet its 2030 power demand with its existing and planned generation and transmission capacities? If the country faces higher demand than that projected by the EPS, what might be some cost-effective strategies to enhance the capacities? Further, if India does not meet its 2030 non–fossil capacity target of 500 GW, how much new thermal capacity would be required? In choosing a desirable pathway to ensure energy security, how can India maximise the social and environmental outcomes while limiting the financial burden on its already strained electricity sector? Finally, what kinds of policy signals and market mechanisms are needed to achieve the energy trilemma of securing clean, affordable, and reliable electricity access by 2030?

Study methodology and model results

To answer these questions, we modelled India’s power system and performed national-level despatch simulations. We conducted the exercise using Plan OS’ production cost, a security- constrained linear optimisation model, in collaboration with GE Vernova’s Consulting Services.

We simulated six scenarios for 2030, considering two major factors: i) uncertainty in growth and, therefore, total demand, and ii) uncertainty in the rate of non-fossil capacity deployment. For the first factor, we modelled moderate demand scenarios (5.8 per cent and 5.1 per cent growth in the energy requirement and peak demand respectively, between 2023 to 2030) and high demand scenarios (6.4 per cent and 6.0 per cent growth in the energy requirement and peak demand respectively, between 2023 and 2030); the latter assumes that the energy requirement and peak demand projections from EPS for FY32 will manifest early in 2030. For the second factor, we modelled varying non-fossil capacities – stated (500 GW), high (600 GW), and low (400 GW) – along with operating and under-construction thermal capacity,3 assuming that the residual demand will be met with additional coal capacities and transmission enhancements. These simulations resulted in a combination of six scenarios, described in Figure ES2.

To facilitate comparison across scenarios, we constrained the model to meet the reliability criteria: (i) normalised energy not served (NENS) between 0.05–0.1 per cent, and (ii) vRE curtailment less than 5 per cent in 2030 (CEA 2023c). We used a four-step approach to meet these reliability criteria across all scenarios, as illustrated in Figure ES3. We also assumed the system would follow a Market-based Economic Despatch (MBED) scheduling framework in 2030. Once the reliability criteria were met, we evaluated the system costs. We considered the annualised capital costs for new coal units and enhanced transmission networks, the levelised costs of storage, and the production cost of electricity from all generating sources.4 Figure ES4 summarises the model results for all six scenarios.

Key insights

India’s existing, under-construction, and planned generation capacities will be adequate to meet its power demand, as per EPS projections for 2030. In the 500 GW-mod demand scenario, India will meet its demand reliably. To do so, it will use 776 GW of generation capacity, including 234 GW of coal, 230 GWh of storage, and 24 GW of additional interstate transfer capability enhancements.
Additional generation and transmission capacities will be needed to meet the EPS- projected demand for 2030 if India falls short of its non-fossil target. If India only achieves 80 per cent of its planned non-fossil target (i.e., 400 GW), it will face a power deficit of 2 GW or higher for 10 per cent of the time, with likely shortages of 6 billion units (BUs) overall in 2030 (0.26 per cent of total demand, which is higher than the allowed reliability level). To meet the demand reliably (0.05–0.1 per cent), the system will need an additional 10 GW of coal capacity beyond the 27 GW under construction. The system will also require significant additional interstate and interregional transmission enhancements. There will be negligible scope to cater to uncertainties in demand and supply, as more than 90 per cent of the available coal fleet5 will be despatched throughout the year.
In the high-demand scenarios, deploying an additional 100 GW of vRE capacity will help India meet the energy and peak demand reliably, cost-effectively, and with better social and environmental outcomes. The country could meet the additional demand through more renewables (100 GW) or new thermal capacities. As compared to the 500 GW-high demand scenario (with additional coal), the 600 GW-high demand scenario (with high RE) yields better social, economic, environmental, and sectoral outcomes, in the following ways:
A varied RE mix spread across states will help meet the demand reliably and at lower cost. The additional 75 GW of solar could be distributed across more states, such as Kerala, Bihar, Punjab, West Bengal, Odisha, and Telangana. Similarly, 25 GW of additional wind capacity can be installed in states such as Madhya Pradesh, Maharashtra, Tamil Nadu, Karnataka, and Rajasthan. Diversified vRE deployment will halve the unmet demand in the 600 GW-high demand scenario relative to the 500 GW-high demand one.9 Additionally, 6 GW of transmission enhancement across states could be avoided.10
Failing to meet the 2030 non-fossil target will lead to suboptimal outcomes. If India achieves only 400 GW of non-fossil capacity by 2030, and the demand grows more than anticipated (as modelled in the 400 GW-high demand scenario), the unmet demand will be 0.62 per cent, double of that projected in the 500 GW-high demand scenario. To meet the demand reliably, 16 GW of new coal capacity will be needed, beyond the existing and under-construction assets. This will likely take more than five years to build. However, in addition to the need for more coal-based generation assets, we also observe the following:
- Interstate and interregional import transmission limits will need significant enhancement (see Figure ES4).
- Overall system costs will be higher by INR 30,000–42,400 crore in 2030, relative to the 500 GW-high demand and 600 GW-high demand scenarios.
- Power sector emissions will go up by 17 per cent over FY24 levels.
- About 90 per cent of the available coal capacity will be despatched for more than 60 per cent of the time, leaving little room beyond the 5 per cent planned reserve margin to manage uncertainties and contingencies.
The system’s ramping requirements will increase multi-fold. Between 2022 and 2030, the system’s net load ramping requirements11 will grow five to six times in the 500 GW- high demand and 600 GW-high demand scenarios, indicating the need for more flexible resources. All resources, including coal, gas, hydro, PSH, and BESS, will need to be leveraged to meet flexibility needs. Our simulations show that BESS will provide most support to meet steep ramping requirements followed by PSH, hydro, coal, and gas.
Making select coal units more flexible can help integrate RE cost-effectively in both moderate- and high-demand scenarios. The CEA has published a plan to retrofit over 90 per cent of the installed coal-based capacity (191 GW) to operate at 40 per cent MTL by 2030 (CEA 2023d). However, our scenario modelling shows that selecting 71–145 GW of coal units to operate at 40 per cent MTL will be adequate and cost-effective for absorbing vRE during its peak generation hours.12 For instance, in the 500 GW-mod demand and 600 GW-high demand scenarios, operating select coal units will reduce vRE curtailment by 3–4 per cent, thus lowering system costs by 5–6 per cent. This will help avoid up to ~150 GWh of BESS capacity that would have otherwise been needed to absorb the curtailed RE. A lower MTL will also allow coal units to operate more consistently, even during low-demand periods. This will allow them to continue generating revenues and mitigate the risk of becoming stranded. There will be negligible additional gains from retrofitting additional coal capacity beyond this quantum. This indicates the need to critically re- evaluate the selection and prioritisation criteria for retrofitting power plants to improve flexibility by 2030.
Effective maintenance of the existing coal fleet will help meet demand reliably and provide the desired flexibility. In both the 500 GW-mod demand and 500 GW- high demand scenarios, coal comprises ~60 per cent of the generation during non-solar hours.13 This share increases during the post-monsoon months of October and November, reaching 75–78 per cent. However, our assessment shows that 15–28 per cent of the installed coal capacity was unavailable in October and November in FY23 and F24 for non-statutory reasons. This indicates that the system can be made more reliable with timely maintenance and preventive measures to prevent technical outages.
Faster deployment of energy storage is needed to integrate the desired levels of RE by 2030. In the 500 GW-mod demand scenario, India will need 132 GWh of BESS, along with 100 GWh of PSH, to meet the demand reliably. However, in the 600 GW-high demand scenario, the storage requirement will increase to 280 GWh of BESS and 100 GWh of PSH. This aligns with India’s energy storage obligation for 2030 (MoP 2022). As of January 2025, the operational BESS capacity stands at 360 MWh (Sen 2025). The gap between existing and required storage capacity indicates the urgent need to fast-track investments in energy storage.
Harnessing demand flexibility will lower the need for battery storage and save costs. In one of the scenarios – meeting moderate demand with high RE (600 GW-mod demand) – a 24 GW demand shift14 in 10 states will help avoid 30 GW of 4-hour BESS capacity. This will lower system costs by ~INR 14,000 crore (USD 1.6 billion). RE-rich states, such as Rajasthan and Gujarat, will collectively contribute one-fourth of this shift. For instance, in Rajasthan, about 2–3 GW of early morning agricultural load in the winter will need to shift to solar hours.

Challenges in RE deployment

Meeting the rising demand with a high-RE pathway is a reliable, affordable, and clean option. However, our analysis and stakeholder consultations reveal several challenges that can restrict the pace of RE deployment, integration, and offtake. These include the slow pace of transmission capacity addition, connectivity delays,15 complexities in land procurement, and supply-chain constraints (Figure ES5). However, it is possible to overcome these challenges through continuous policy innovation and strategic interventions.

A seven-point agenda for India’s power sector transition

Drawing from the results of the model simulations and extensive discussions with key stakeholders in India’s power sector, we recommend a seven-point action agenda. This plan will facilitate realising the socio-economic benefits and the desired power system outcomes of cost-effectively integrating renewables at scale.

To give a strong policy signal to the market, the Ministry of Power (MoP) must embed the target of achieving a 50 per cent share in generation from non-fossil capacity by 2030 in the National Electricity Policy. To achieve this target, the states may be provided with the flexibility to identify clean energy technology choices best suited to their needs. This is to ensure that India meets its net-zero target by 2070 and to delineate a pathway for the electricity sector until 2030.
The MoP must collaborate with the Ministry of New and Renewable Energy (MNRE) and other key institutions to build a technologically and geographically diverse RE portfolio. Our analysis shows that a technologically– and geographically–diverse mix of RE will help reduce the need for new transmission infrastructure and lower the need for flexible resources to manage grid operations. Two interventions could support this objective:
- Identify innovative deployment models and contract frameworks to support the co-location of wind and storage projects with existing solar capacities. This can diversify and accelerate the RE mix, and, in turn, increase the utilisation of the existing transmission infrastructure. One example is the proposed splitting of General Network Access (GNA) into solar and non-solar hours (CERC 2024b). To enable such implementation, associated commercial arrangements must be identified.
- Ensure the implementation of the Uniform Renewable Energy Tariff (URET), currently notified for solar, and extend the mechanism to include wind power (MoP 2023). Adopting the URET will help expedite offtake and encourage RE developers to tap locations across more states, even if doing so slightly increases bid tariffs relative to those of resource-rich sites only in select states. Alongside, the state and centre must identify incentive mechanisms to attract developers to add capacities in the state.
The MoP, in collaboration with the MNRE, must unlock new avenues for RE offtake. To enhance the deployment of RE at scale, new offtake avenues, besides long-term contracts, must be explored. We propose two potential interventions:
- Introduce bid guidelines to enable more RE developers to participate in the power exchange. This will help meet multiple objectives: (i) rapidly improving supply- side liquidity in power exchanges, (ii) creating an enabling environment for future investments in RE capacities, and (iii) creating conditions for cost-effective variability management in a RE-rich system.
- Encourage renewable energy implementing agencies (REIAs) to build their own generation portfolios. This can be accomplished by encouraging these entities to invest in standalone storage assets, direct RE procurement, and market trading to offer desired services to distribution utilities, system operators, and buyers in the short- and medium-term markets.
The Central Electricity Regulatory Commission (CERC) and Grid Controller of India (Grid India), in collaboration with states, must ensure fast-tracked deployment of energy-storage solutions. Our analysis shows that integrating high RE capacities will require 55–70 GW of 4-hour BESS and 12.5 GW of PSH. The current BESS capacity is only 360 MWh. Therefore, the CERC and Grid India must undertake the following:
- Conduct a robust analysis to identify strategic locations for siting BESS projects to optimise network operations.
- Evaluate short-term flexible contracts to allow shared capacity contracts among utilities and the system operator to maximise the utilisation of BESS assets.
- Publish a discussion paper on possible sharing and operations of BESS capacities to take advantage of arbitrage opportunities across utilities and to enable offtake and participation.
The MoP and CEA must enable states to ensure robust resource planning to meet the growing demand reliably and cost-effectively. This can be achieved through the following interventions:
- Institute a technical assistance programme for states to establish the necessary infrastructure, institutional frameworks for data management, and in-house expertise for simulation-based exercises.
- Earmark funds from the Power System Development Fund (PSDF) for states to strengthen capabilities to conduct planning studies.
- Constitute an expert group to publish informed inputs and assumptions for robust capacity expansion and resource adequacy planning exercises.
The Forum of Regulators (FoR), with support from the Bureau of Energy Efficiency (BEE) and Grid India, should nudge state regulators to assess the value of and market for tapping demand flexibility. Our analysis highlights the benefits of shifting the demand from peak non-solar hours to solar hours. Shifting 24 GW of demand daily can help avoid (i) 30 GW of 4-hour BESS, and (ii) the construction of 6 GW of additional interstate transmission infrastructure. Further, it would help the system save INR 14,000 crore (USD 1.6 billion) in 2030.
The coordinated efforts from the FoR and BEE can spur discussions and advance initiatives, such as that introduced by Maharashtra, which was the first to notify demand- side management (DSM) regulations in October 2024 (MERC 2024).
Grid India and CERC must help states adopt improved maintenance and scheduling practices. Our analysis of past data and simulations highlights that optimising the operational planning and scheduling mechanism has multiple benefits. Here, two interventions could be considered:
- FoR must conduct a knowledge-sharing programme for state, regional, and national load despatch centres (LDCs) to share best practices on operational planning and effective scheduling and promote the transition from MBED to Security Constrained Economic Despatch (SCED) as a uniform mechanism for despatch.
- CERC must revisit the existing merit order despatch (MoD) mechanism to enable the scheduling of flexible resources such as energy storage, hydro budgets, and flexible demand.

FAQs

How is India's electricity demand growing and what are the key drivers?

“India’s electricity demand is rising faster at around 9% per annum since FY21, compared to an average of 5% in the previous decade. The Central Electricity Authority projects electricity demand to grow at 6% CAGR between 2022 and 2030. However, recent trends suggest that actual demand could surpass these estimates. Economic growth, urbanisation, industrial electrification, upcoming demand avenues (green hydrogen, electric vehicles, etc.), and rising temperatures are likely to influence the demand growth and make it more uncertain.”
Would India be able to meet its demand with existing and planned resources?

“Our analysis suggests that India can meet the electricity demand as projected by the Central Electricity Authority’s 20th Electric Power Survey, with existing and planned generation resources (i.e., with 500 GW non-fossil capacity) without any further coal addition in 2030. But if demand were to increase beyond these estimates, India will have multiple pathways, each with its own set of challenges to meet the demand reliably.”
What is the least-cost pathway for India to meet its rising electricity needs?

“Our analysis suggests a high-RE pathway, i.e., 600 GW non-fossil capacity without any further addition of coal to be the most cost-effective pathway for 2030 to meet the rising demand reliably (without any power shortages). ”
What is the main challenge for the grid as the share of renewables increases? And what are the potential solutions?

“Temporal mismatch between the demand and supply from the intermittent renewable generation (variable RE) sources like solar and wind is the main challenge. Integration of flexible resources such as battery energy storage systems, pumped hydro, flexible coal and hydroelectricity, and transmission enhancements, and demand side flexibility will help manage the demand-supply variations in a high-RE grid.”
What are the key barriers to RE deployment at the desired pace?

“There are four key barriers restricting the RE deployment at pace: (a) Transmission connectivity due to delays in granting connectivity, slow infrastructure augmentation and upgrades, process and permitting delays, and Right-of-Way issues; (b) Land, which includes non-availability of land in resource-rich areas, site accessibility issues, complexities in land aggregation, and escalation of land prices; (c) Tariff viability concerns, because of contract signing delays, ISTS waiver uncertainty, shrinking profit margins due to commissioning delays; and (d) Supply chain, including limited availability of specialised materials and components, lack of investments in standardising product designs, limited domestic manufacturing capacity to meet DCR requirements, and lack of skilled workforce”