India’s power sector is undergoing a period of strong growth, marked by rising demand, record renewable capacity additions, evolving market mechanisms and rapid digital transformation. Demand continues to be driven by increasing electrification, expanding commercial and industrial (C&I) activity, and new loads such as data centres and electric vehicle (EV) charging. On the supply side, renewables are dominating capacity additions, while thermal power is witnessing new capacity additions. Additionally, transmission expansion, distribution reforms, and measures such as digital public infrastructure (DPI) for the power sector are gaining momentum.
Power demand trends
Power demand in India has been rising steadily, backed by rapid electrification, increasing cooling loads, and growing power demand from C&I consumers. During 2024-25, the sector witnessed a peak power demand of 227 GW (April 29, 2024) and reached an all-time high peak power demand of 250 GW in May 2024. In 2025-26 (till September), it recorded a peak power demand of 231 GW (June 9, 2025), reflecting the impact of cooler temperatures and unseasonal rains.
Peak demand typically occurs in the afternoon and early evening, at around 3 p.m. during solar hours and between 9 p.m. and 11 p.m. during non-solar hours. Evening peaks have been rising consistently and are now matching daytime peaks, reflecting a pronounced duck curve pattern. India’s per capita electricity consumption at 1,395 kWh recorded in 2023-24 remains relatively low, presenting significant scope for demand expansion. Overall, power demand is expected to continue on an upward trajectory. While demand growth is structural in nature, it continues to be weather-sensitive. New loads, primarily from EV charging, data centres and process electrification, will further accelerate the increase in demand.
Draft Electricity (Amendment) Bill, 2025
On the policy front, a major development has been the issuance of the Draft Electricity (Amendment) Bill, 2025. On October 9, 2025, the Ministry of Power issued the draft bill proposing amendments to the Electricity Act, 2003 to strengthen and reform the power sector. Stakeholders have been invited to submit their comments within 30 days. The key proposals of the bill are summarised below:
- Financial viability: The draft focuses on improving the financial sustainability of the sector, promoting ease of doing business and ease of living, and enhancing regulatory accountability. It mandates cost-reflective tariffs, while allowing state governments to extend advance subsidies to targeted consumer categories. To address delays in tariff revisions, the bill proposes to empower state electricity regulatory commissions (SERCs) to determine tariffs suo motu, ensuring implementation from April 1 each year and improving financial discipline.
- Economic competitiveness: The amendments aim to rationalise tariffs, unlock demand and reduce logistics costs. It proposes that the SERCs may exempt distribution licensees from universal service obligations (USOs) for open access consumers, with one licensee designated to supply power at a premium if other arrangements fail. The railways, metro railways and manufacturing enterprises are proposed to be exempt from cross-subsidies within five years, lowering transport and logistics costs. For captive generation, it is proposed that the central and state governments be empowered to frame rules to provide regulatory clarity and encourage industrial investment in self-generation and cleaner energy.
- Energy transition: The bill proposes to empower the Central Electricity Regulatory Commission (CERC) to introduce market-driven instruments to attract investment, foster competition and accelerate renewable capacity addition. It also proposes to align the Electricity Act with the Energy Conservation Act, 2001 by introducing enforceable non-fossil capacity obligations, supporting the goals for reliable, affordable and clean energy.
- Ease of living and doing business: The bill proposes uniform minimum service standards nationwide to improve supply quality and enhance the accountability of distribution licensees. It caps the assessment period for unauthorised use at one year to reduce discretion and lowers the mandatory appeal deposit from half to one-third of the assessed amount, with provision for a waiver in cases of hardship.
- Regulatory strengthening: To strengthen accountability, the bill proposes to empower the central and state governments to refer complaints against the CERC and SERC members, with expanded grounds for removal to include wilful violation and gross negligence. A 120-day timeline for the disposal of adjudicatory matters is proposed. The number of APTEL members will be increased from three to seven to clear the backlog and boost investor confidence.
- Infrastructure, cybersecurity and governance: The bill proposes right-of-way (RoW) provisions to retain legal authority for laying electric lines, with state governments to set fair compensation frameworks. The Central Electricity Authority (CEA) will be empowered to frame cybersecurity regulations for integrated power system operations. Distribution network sharing is proposed to be enabled to avoid duplication and reduce costs, subject to regulatory oversight. An electricity council, chaired by the union power minister with state ministers as members, is proposed to be established as a high-level platform to build consensus on reforms and align efforts towards Viksit Bharat@2047.
Renewables dominate capacity additions
Capacity additions continue to be driven by renewables, supported by a strong project pipeline and favourable market conditions. In FY 2026 (till August 2025), renewable capacity additions reached 20 GW, a 123 per cent increase over the 9 GW added during the corresponding period of the previous year. In comparison, thermal capacity additions stood at 3,600 MW, while hydro and nuclear contributed 2,380 MW and 700 MW respectively. In FY 2025, renewable additions stood at 28.7 GW, up from 18.5 GW in FY 2024, aided by falling solar PV prices and the expiry of the interstate transmission system (ISTS) charge waivers in June 2025. Total capacity additions during the year stood at 33.4 GW, of which renewables (including large hydro) accounted for 29.5 GW – the highest ever.
According to ICRA Research, this growth was underpinned by a strong tendering pipeline, with 40.2 GW of renewable capacity auctioned in FY 2025. However, activity has moderated in the first half of FY 2026, with only 3.4 GW being auctioned so far due to delays in the signing of purchase sale agreements (PSAs) by state utilities, which have, in turn, held up PPAs with developers. Another key challenge is the growing mismatch between renewable capacity and transmission infrastructure. As of June 2025, over 50 GW of renewable capacity was stranded nationwide due to inadequate evacuation connectivity. Accelerated transmission expansion and the timely signing of PPAs and PSAs will be crucial to sustain the current growth momentum.
Alongside capacity expansion, the market is witnessing a clear shift in procurement preferences. Utilities and C&I consumers are increasingly turning to wind-solar hybrids and firm and despatchable renewable energy (FDRE) projects to meet round-the-clock power needs and reduce dependence on conventional sources. The hybrid segment has expanded rapidly, supported by new projects, tenders and partnerships.
Hybrid tariffs have been highly competitive – on par with solar and significantly lower than wind – spurring investor interest. Since 2024-25, 12 hybrid auctions have been held, with tariffs ranging from Rs 3.19 per kWh in SJVN Limited’s 1,200 MW (III) auction (November 2024) to Rs 3.43 per kWh in the Solar Energy Corporation of India’s 1,200 MW (VIII) auction (June 2024), averaging Rs 3.25-Rs 3.60 per kWh. In FDRE auctions, a key milestone was achieved in September 2025, when Madhya Pradesh’s maiden solar-plus-storage tender discovered a tariff of Rs 2.70 per kWh – the lowest for an FDRE-type project in India.
Thermal additions regain pace
After a long hiatus, the thermal power segment is seeing a revival in capacity addition. During FY 2026 (up to August), about 4.4 GW of the 10 GW target has already been added. In comparison, around 4.5 GW of capacity was added in FY 2025 and 5.4 GW was added in FY 2024. In the near to medium term, coal-based power is expected to continue meeting India’s baseload needs, with peak demand projected to reach about 366 GW by 2031-32. The thermal (coal and lignite) capacity requirement by 2034-35 is estimated at 307 GW (against an installed capacity of 212 GW as of March 31, 2023). To bridge this gap, the Ministry of Power (MoP) plans to add at least 97 GW of new capacity. Since April 2023, around 11.7 GW has been commissioned, while another 39 GW (including 5.7 GW of stressed assets) is under construction. Contracts for 15.4 GW were awarded in 2024-25, and about 35.5 GW of candidate capacity is at various stages of planning.
There has, moreover, been an uptrend in PPA signing as states plan to meet growing power demand in a reliable manner. Several states have issued and awarded new thermal PPAs in the past three to four months, while more are at various stages of approval. Recent PPAs include Adani Power’s agreement with Uttar Pradesh Power Corporation Limited for its upcoming Mirzapur plant (May 2025); the Damodar Valley Corporation’s PPA with Karnataka discoms for 300 MW from Koderma Phase II (June 2025); NTPC Limited’s PPA with the Government of Goa for Sipat Stage III (July 2025); and Adani Power’s 25-year PSA with Bihar State Power Generation Company Limited (BSPGCL) for 2,400 MW from the Pirpainti project at a tariff of Rs 6.075 per kWh (September 2025).
Policy push for nuclear power
As a clean and reliable source of electricity, nuclear power is expected to play a pivotal role in India’s energy mix and its journey towards net zero. The country currently operates 25 nuclear reactors with an aggregate capacity of 8.8 GW, while another 13.6 GW is at various stages of construction. The government has set an ambitious target of installing 100 GW of nuclear capacity by 2047. In support of this, it has launched a dedicated Nuclear Energy Mission with a Rs 200 billion allocation for research and development, aimed at designing and operationalising at least five indigenous small modular reactors (SMRs) by 2033.
More recently, in October 2025, the CEA has issued a road map for achieving the goal of 100 GW of nuclear capacity by 2047, outlining a comprehensive strategy to expand nuclear power as a core element of India’s clean energy transition and net zero pathway. The road map highlights that achieving 100 GW will require more than a tenfold capacity expansion over the next 22 years – around 4.14 GW of capacity addition annually. The suggested strategies for reactor technology include the continuance of pressurised heavy water reactor technology as the mainstay for nuclear capacity addition over the next decade, expedited adoption of pressurised water reactor technology, indigenisation of imported reactor technologies, adoption of technologies and fuel that can hasten the utilisation of thorium, deployment of large reactors for grid applications and small reactors for captive use. It also suggests that future reactor designs should support flexible operation.
The road map proposes key policy and legislative changes, including greater private sector participation and amendments to the Atomic Energy Act and Civil Liability for Nuclear Damage (CLND) Act – such as capping supplier liability, rewording Section 46 to avoid overlapping liabilities and narrowing the definition of supplier to critical equipment providers. The road map notes that accelerating capacity addition will require project timelines to be reduced through fast-tracking pre-project activities, land acquisition, quality assurance and regulatory processes. Improving public perception and communication is also critical, given that amplified safety concerns often delay projects. The road map estimates the total investment requirement at Rs 19 trillion, necessitating innovative financing models and greater private participation, as government funding alone will not be sufficient.
Battery storage market accelerates
Over the past year, the government has taken a series of policy and regulatory measures to accelerate grid-scale battery energy storage system (BESS) deployment. In June 2025, the MoP expanded the viability gap funding (VGF) scheme to support 30 GWh of BESS projects, providing grants of up to 30 per cent of capital costs. The revised scheme also introduced more stringent quality and domestic energy management system requirements. Further, the ISTS charge waiver for co-located BESS and pumped hydro projects has been extended until June 2028, significantly improving project economics. The Central Electricity Regulatory Commission (CERC) has amended the connectivity and general network access (GNA) regulations to formally integrate storage into the connectivity and scheduling framework.
A key milestone in the segment was achieved in April 2025 with the commissioning of India’s first utility-scale standalone BESS by IndiGrid (KKR backed). The 20 MW/40 MWh Kilokari project in Delhi was contracted by BSES Rajdhani Power Limited to provide four-hour peak support. The project has a levellised capacity tariff of Rs 5.76 million per MW per year (approximately Rs 480,000 per MW per month), about 55 per cent lower than previous benchmarks.
Recent standalone BESS auctions have revealed distinct tariff patterns, driven largely by VGF support and system design. For two-hour storage systems, tariffs have ranged between Rs 208,000 and Rs 280,000 per MW per month for NHPC Limited’s VGF-backed 500 MW/1,000 MWh tender and Gujarat Urja Vikas Nigam Limited’s non-VGF 500 MW/1,000 MWh tender respectively. Longer-duration (four-hour) systems have attracted higher tariffs due to the doubling of storage requirements. Tariffs in this category have ranged between Rs 359,000 and Rs 444,000 per MW per month for SJVN Limited’s 375 MW/1,500 MWh VGF-backed auction and BSPGCL’s 125 MW/500 MWh tender respectively.
Transmission build-out
India’s transmission sector has been growing rapidly, marked by network additions and the deployment of advanced technology solutions. The transmission network stands at 495,405 ckt km of lines and over 1,359 GVA of capacity (as of June 2025). In 2024-25, the grid added 8,830 ckt km of transmission lines and 86,433 MVA of transformation capacity. The interregional transfer capacity has progressively expanded and now stands at 118,740 MW.
On the policy and regulatory fronts, key measures have been introduced to strengthen the transmission framework. The August 2025 GNA amendment improves developer flexibility, grid utilisation and cost efficiency, and integrates storage – crucial for scaling hybrid and FDRE projects. The Central Electricity Authority’s (CEA) revised RoW compensation guidelines set rates at 30 per cent of land value in rural areas and 60 per cent in urban areas for ISTS lines, easing land issues and speeding up execution. The CEA’s phasor measurement unit (PMU) placement guidelines (March 2025) standardise phasor deployment, enhancing real-time visibility and grid stability in a high-renewables system.
Looking ahead, as per the National Electricity Plan (Volume II, 2023-32), the addition of 191,474 ckt km of transmission lines and 1,307,435 MVA of transformation capacity (including high voltage direct current [HVDC] bipole/back-to-back) between 2022 and 2032 is planned with an estimated investment of Rs 9.1 trillion. A key priority is renewable energy evacuation, supported by greater HVDC deployment, which enables bulk power transfer over long distances, integration of remote renewable resources and enhanced grid stability. Advanced technologies such as wide area measurement systems and PMUs are also being scaled up to improve efficiency and reliability. However, challenges persist. Rising HVDC costs have raised concerns about financial viability and affordability. While interstate networks have expanded significantly, intra-state systems continue to lag, underscoring the need for greater state participation. Supply chain readiness and investment mobilisation remain additional hurdles to achieving planned targets.
Discom performance remains weak
The distribution sector’s performance continues to lag, with persistent operational inefficiencies and financial stress. Aggregate technical and commercial losses rose to 16.12 per cent in 2023-24 from 15.11 per cent in the previous year, ranging from 1.31 per cent for Dakshin Gujarat Vij Company Limited to 47.11 per cent for the Nagaland Power Department. Power availability has improved to near 24 hours, averaging 21.57 hours in rural areas and 23.53 hours in urban areas.
Financially, the sector debt increased to Rs 7.5 trillion as of March 2024 from Rs 6.8 trillion a year earlier. The Late Payment Surcharge Rules helped liquidate nearly Rs 500 billion of dues to central gencos and transcos in FY 2023 and enforced greater payment discipline. About Rs 1.4 trillion of legacy dues have been converted to EMIs, with full clearance targeted by mid-2026. Operational losses have nearly halved, from Rs 729 billion in FY 2023 to Rs 319.7 billion in FY 2024, driven by better tariff realisation, targeted subsidies and higher state grants.
Smart metering is picking up pace under the Revamped Distribution Sector Scheme, with over 44 million meters installed as of October 2025 and a daily installation rate exceeding 100,000. Early adopters such as Bihar and Assam are already reporting loss reductions. To meet the 250 million target, a two-year extension of the scheme to FY 2028 is being considered.
States are also exploring private participation to improve efficiency. Chandigarh, Daman & Diu, and Dadra & Nagar Haveli have already privatised distribution operations, while Uttar Pradesh has initiated the process for two discoms. Privatisation is expected to strengthen operational discipline, customer service and accountability.
Building DPI for the power sector: India Energy Stack
The MoP has conceptualised the India Energy Stack (IES) – a unified, secure and interoperable DPI for the power sector. A key component of this initiative is the Utility Intelligence Platform (UIP), to be developed with select distribution utilities. Built on standardised, open APIs and protocols, the UIP will integrate data from various IT/OT systems to drive efficiency, innovation and smarter energy management. To steer the initiative, a task force comprising power, technology and regulatory experts has been constituted. The IES will feature unique IDs for consumers, assets and transactions; real-time, consent-based data sharing; open APIs for seamless integration; and tools for consumer empowerment, market access and innovation.
The MoP has launched a stakeholder mapping survey to assess solutions, innovations and ecosystem readiness. A 12-month proof of concept with select utilities will follow, piloting the UIP through real-world use cases to validate functionality and sector-wide benefits ahead of nationwide roll-out. Much like Aadhaar for identity and UPI for payments, the IES aims to create a digital backbone for the energy ecosystem – enabling secure, seamless and consumer-centric power services, improving discom efficiency, supporting renewable integration and ensuring grid stability.
Digital transformation and use of AI
The Indian power sector is undergoing rapid digital transformation to modernise infrastructure, enhance efficiency and integrate growing renewable capacity while maintaining grid stability. Artificial intelligence (AI) and advanced digital tools are emerging as key enablers of this shift.
Transmission utilities are leading adoption, using digital twins, drones, robotics and AI for site selection, route planning and real-time asset inspections – improving accuracy, safety and speed while reducing construction risks. In operations, AI-driven predictive maintenance, internet of things sensors, cloud dashboards and analytics are enhancing asset health monitoring, real-time visibility and risk management.
Discoms are deploying AI for fault detection, load forecasting, transformer health monitoring, predictive maintenance and theft detection to improve reliability, reduce losses, and optimise scheduling and restoration. These tools are also strengthening consumer interface and service delivery.
In generation, AI is being applied across the value chain to improve flexibility, reduce costs and support grid stability. Conventional plants are leveraging AI for operational insights, ramping optimisation, part-load efficiency and predictive maintenance, while renewable developers are using it for project planning, construction, operations and maintenance, forecasting and congestion management – critical for enabling the large-scale integration of variable resources.
Deepening of power markets
The share of power trading in India has been rising steadily, driven by increasing reliance on the short-term market to meet energy demand. With the introduction of new products focused on green power procurement, green energy trading is also gaining traction.
Within the short-term segment, the real-time market (RTM) has emerged as a key avenue for balancing variable renewable generation, now accounting for nearly 30 per cent of total exchange volumes. In May 2025, RTM prices on the Indian Energy Exchange fell to nearly zero on a Sunday, driven by unseasonal rains and thunderstorms that dampened demand, coupled with a surge in supply – highlighting the growing impact of renewable variability on market dynamics.
Further, the launch of electricity derivatives has marked a significant step towards deepening India’s power markets. These instruments are expected to enhance liquidity, enable better price discovery and provide effective hedging tools against price volatility in a renewables-heavy system. Additionally, the CERC issued a suo moto order in July 2025, outlining a phased road map for market coupling. Day-ahead market coupling will be rolled out by January 2026 through a round-robin market coupling operator model, with RTM coupling to follow. This is expected to unify prices across exchanges, optimise capacity allocation, reduce market fragmentation and provide a single price signal to support electricity derivatives and other advanced products.
To conclude, rising demand, accelerating renewable integration and deepening market reforms will shape the next phase of growth. Timely transmission build-out, stronger discom performance and expanded storage capacity will be critical to meeting future demand reliably.
Priyanka Kwatra
