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GS Paper: GS3-13.Infrastructure: Energy, Ports, Roads, Airports, Railways etc:

  • Geothermal Energy

    Why in News

    A PIB Backgrounder on geothermal energy set out the resource, its potential in India, and its place in the clean energy transition.

    Core facts

    1. Definition: Geothermal energy is heat stored within the earth. It is drawn from hot rocks and hot water reservoirs below the surface and used for power generation and direct heating.
    2. Nature of the resource: Geothermal energy is a renewable and baseload source. It supplies power around the clock, unlike solar and wind, which vary with weather and time of day.

    Static Context

    1. India’s potential: The Geological Survey of India (GSI) has identified about 340 geothermal hot spring sites. The estimated geothermal power potential is placed around 10,600 megawatts (MW).
    2. Key geothermal provinces: Major sites include Puga and Chhumathang in Ladakh, Tattapani in Chhattisgarh, Manikaran in Himachal Pradesh, and the Godavari and Cambay basins.
    3. How it works: A geothermal plant taps steam or hot water from a well. The steam drives a turbine. The turbine drives a generator to produce electricity.
    4. Uses beyond power: Direct use includes space heating, greenhouse warming, aquaculture and cold storage. Ladakh has seen pilot efforts for geothermal power and heating.
    5. Nodal ministry: The Ministry of New and Renewable Energy (MNRE) is the nodal ministry for renewable energy sources, including geothermal.
    6. Global comparison: Countries with high geothermal output include the United States, Indonesia, the Philippines, Iceland and Kenya. India’s geothermal capacity remains at an early stage.

    Prelims angle

    1. The location of Puga, Tattapani, Manikaran and other geothermal sites, and the role of the Geological Survey of India in resource mapping.
    2. The classification of geothermal as a renewable and baseload source, and the nodal ministry. Site to state matching is a common format.

    Mains angle

    1. GS Paper 3, infrastructure and energy, and India’s renewable energy mix.
    2. A question can ask how baseload renewable sources such as geothermal complement variable solar and wind in the path to energy security.

    Matching Previous Year Question

    “[2022, GS3, 15] Do you think India will meet 50 percent of its energy needs from renewable energy by 2030 ? Justify your answer. How will the shift of subsidies from fossil fuels to renewables help achieve the above objective? Explain.”

  • Geothermal Energy

    Geothermal Energy

    Why in News

    The Press Information Bureau (PIB) published a thematic Backgrounder on Geothermal Energy on 4 September 2026. The piece is a subject explainer written for exam and public awareness value.

    Core facts

    1. Definition: Geothermal energy is heat stored inside the Earth. This heat is tapped through wells at sites with high underground temperature gradients.
    2. Nature of the source: Geothermal power is a renewable and baseload source. It generates around the clock, unlike solar or wind.
    3. Nodal ministry: The Ministry of New and Renewable Energy (MNRE) is the nodal ministry for geothermal energy in India.
    4. Verification note: The release body did not resolve on the source page this run, so release-specific figures are not quoted. The static estimates below come from standard reference data.

    Static Context

    1. India’s first project: India commissioned its first geothermal wells at Puga Valley in the Changthang region of Ladakh. A 1 Megawatt (MW) pilot geothermal plant is planned as the first demonstration scale project.
    2. Implementing agency: The ONGC Energy Centre, a body of the Oil and Natural Gas Corporation (ONGC), leads the Puga project with the Ladakh Administration.
    3. Estimated potential: India’s geothermal potential is estimated at about 10,600 MW (standard reference figure).
    4. Survey base: The Geological Survey of India (GSI) has documented about 381 hot springs. India has ten geothermal provinces, including the Himalayan, Son Narmada Tapi (SONATA), West Coast, Cambay and Godavari belts.
    5. Key sites: Notable geothermal sites include Puga and Chumathang in Ladakh, Manikaran in Himachal Pradesh, Tattapani in Chhattisgarh, and Bakreshwar in West Bengal.
    6. Policy frame: A National Policy on Geothermal Energy was notified in 2025, with the MNRE as the promoting authority.

    Prelims angle

    1. Nodal ministry: MNRE. Lead agency for Puga: ONGC Energy Centre.
    2. First site: Puga Valley, Ladakh. Survey body: GSI, with about 381 hot springs mapped.
    3. Source character: Renewable and baseload, driven by internal Earth heat.
    4. Geothermal provinces: Himalayan, SONATA, West Coast, Cambay, Godavari and others.

    Mains angle

    GS Paper 3, energy and infrastructure. A question can ask how geothermal energy can add firm renewable baseload capacity to India’s energy mix, and can weigh the high exploration cost and site concentration in the Himalayas against the round the clock output advantage.

    “[2013] Consider the following :

    (1). Electromagnetic radiation

    (2). Geothermal energy

    (3). Gravitational force

    (4). Plate movements

    (5). Rotation of the earth

    (6). Revolution of the earth

    Which of the above are responsible for bringing dynamic changes on the surface of the earth?

    (a) 1, 2, 3 and 4 only

    (b) 1, 3, 5 and 6 only

    (c) 2, 4, 5 and 6 only

    (d) 1, 2, 3, 4. 5 and 6.

  • Thermal sector grapples with coal stock management

    Why in the News

    Thermal power generators that hold adequate coal inventories are disadvantaged when limited domestic supply is redirected to plants that have fallen below their prescribed stock norms. Those norms are plant specific and have run under the Central Electricity Authority (CEA) framework that took effect on 6 December 2021. The revised Scheme for Harnessing and Allocating Koyala (Coal) Transparently in India (SHAKTI) policy, approved by the Central Government in May 2025, streamlined coal linkage allocation into two windows. Emergency redistribution keeps a low stock plant running and protects grid reliability. Repeating it removes the reason for any generator to carry stock at or above its norm, since the surplus is what gets moved.

    How is coal allocated to a thermal power plant?

    1. The linkage: A coal linkage is a long term assurance of supply from a specified source to a specified plant.
    2. The contract: A Fuel Supply Agreement (FSA) gives that linkage contractual form, fixing the quantity the coal company owes the generator.
    3. Window I: Central government owned generating companies and State utilities receive linkages at notified prices.
    4. Window II: Other eligible producers, including plants running on imported coal, procure coal through auctions at a premium over the notified price.

    Why does redistribution penalise the generator that stocked adequately?

    1. Compliance is measured plant by plant: The revised norms set a stocking level for each plant, so a generator is judged against its own requirement rather than a common one.
    2. Scarce coal moves toward the shortfall: When domestic supply is limited, deliveries are redirected to plants below their norms, and the generator that planned surrenders tonnage it had secured.
    3. The incentive runs backwards: Repeated redistribution removes any reason to carry stock above the norm, because the surplus is precisely what is taken.
    4. The proposed correction: A former Managing Director of PTC India, earlier the Power Trading Corporation of India, argued that coal inventory should be recognised as a system reliability service. Generators holding adequate or higher than normative stocks would be incentivised, and repeated shortfalls without genuine external cause would carry consequences.

    When is emergency redistribution justified?

    1. Grid stability and consumer supply: Assistance to plants at critically low stocks is defensible where consumer interests and grid stability are at risk.
    2. The distinction that decides it: Support must separate a genuine supply chain disruption from a persistent shortage caused by inventory mismanagement.
    3. The causes that qualify: Mine side constraints, railway bottlenecks, force majeure events and unexpected spikes in electricity demand are the genuine disruptions for which redistribution is meant.
    4. Where the framework came from: The Ministries of Coal, Power and Railways coordinate to monitor supplies and move coal, and the revised supply framework followed the COVID-19 pandemic, when all modes of transport came to a standstill.

    Is the problem a shortage of coal or a failure of logistics?

    1. Production has crossed a billion tonnes twice: Output reached 1,047.52 million tonnes in 2024-25 and 1,040.08 million tonnes in 2025-26.
    2. The current year’s run rate: Cumulative production through July stood at 302.04 million tonnes, and dispatches rose about 6 percent year on year to 354.7 million tonnes.
    3. Stock exists but sits in the wrong place: Thermal power plants held 34.55 million tonnes, with another 113 million tonnes at pitheads or in transit, a combined stock of about 148 million tonnes.
    4. Availability at the mine is not availability at the plant: Fuel security depends on the whole chain of production, loading, railway availability, transit, unloading and stockyard management.
    5. The binding constraint: The difficulty is how supplies are allocated, transported and converted into plant level inventories, not the national quantity of coal.

    Challenges to coal stock management in the thermal sector

    1. Rail capacity sets the replenishment ceiling: Coal moves mainly by rail, so rake availability decides how quickly a plant below its norm can be refilled. Eg. Passenger services were cancelled in 2022 to free rakes for coal movement to power stations.
      The Fix: Expand corridor capacity on the mine to plant routes and publish rake allocation in advance, so a generator can plan against a known schedule.
    2. Distance from the pithead is not priced into the norm: A plant far from its linked mine carries a longer transit and needs a larger buffer to hold the same days of cover. Eg. Plants in the western and southern States drawing from the Talcher and Mahanadi coalfields run multi day rail transits.
      The Fix: Set stocking levels by transit distance rather than by a uniform days of cover, so a distant plant is not judged on a pithead plant’s buffer.
    3. Grade slippage erodes the stock that is counted: A gap between the declared grade and the delivered grade means a tonne in the yard carries less heat than the norm assumes. Eg. Third party sampling of coal supplies was introduced after persistent grade slippage complaints from generators.
      The Fix: Express stocking norms in days of energy rather than days of tonnage, so quality shortfalls appear in the compliance number itself.
    4. Imported coal blending is abandoned when landed costs rise: Plants designed to blend imported coal cut back when the rupee weakens, which increases their draw on domestic supply. Eg. Blending directions issued to State generators in 2022 were resisted on cost grounds.
      The Fix: Allow the incremental fuel cost of a directed import to pass through in tariff automatically, so a blending direction does not sit on the generator’s balance sheet.
    5. Payment stress travels back up the chain: A generator owed money by distribution companies delays its own coal payments and cannot fund a larger inventory. Eg. Accumulated dues from State distribution companies prompted the Late Payment Surcharge Rules, 2022.
      The Fix: Enforce the existing payment security mechanism strictly, so working capital is not the reason a plant slips below its norm.

    Conclusion

    The dispute is not about how much coal the country digs out. It is about who absorbs the cost when a scarce delivery is moved from a plant that planned to one that did not. The tension is unresolved, because the authority that must keep a low stock plant running has no instrument to compensate the generator whose coal is diverted to it. Until a stocking norm carries a payment on one side and a consequence on the other, redistribution will keep shifting the cost of poor planning onto the generators that planned.

    Back2Basics: Central Electricity Authority

    1. What it is: The Central Electricity Authority is the technical advisory body of the Ministry of Power.
    2. Statutory basis: It functions under the Electricity Act, 2003, continuing the body first constituted under the Electricity (Supply) Act, 1948.
    3. Advisory role: It advises the Central Government on national electricity policy and prepares the National Electricity Plan.
    4. Technical role: It sets technical standards for the construction and operation of electrical plants and lines, and monitors daily coal stock positions at thermal stations.

    [2019] Consider the following statements:

    1. Coal sector was nationalized by the Government of India under Indira Gandhi.

    2. Now, coal blocks are allocated on lottery basis.

    3. Till recently, India imported coal to meet the shortages of domestic supply, but now India is self-sufficient in coal production.

    Which of the statements given above is/are correct?

    (a) 1 only

    (b) 2 and 3 only

    (c) 3 only

    (d) 1, 2 and 3

  • No takers for govt’s ₹37,500-crore coal gasification scheme

    Why in the News

    The coal ministry’s ₹37,500 crore financial incentive scheme for surface coal and lignite gasification has drawn no application from any private or public player. The last date for submission is 7 September 2026, fixed by a Request for Proposal issued on 7 July 2026. The Union Cabinet had approved the scheme to gasify 75 million tonnes of coal and lignite and to cut imports of liquefied natural gas, urea and methanol. The ministry attributes the absence of bids to the time a project proposal of this scale takes to prepare. An incentive of this size drawing nothing at its first deadline points at the economics of a gasification project rather than at the paperwork.

    How does coal gasification work?

    1. From solid fuel to gas: Dry fuel is converted into synthetic gas, known as syngas.
    2. What syngas is used for: Syngas serves as an alternative fuel and as the feedstock for methanol, fertilisers, hydrogen and chemicals.
    3. The stated emissions gain: Converting coal into gas rather than burning it directly is counted as a reduction in carbon emissions.

    What was the scheme designed to achieve?

    1. A volume target: The programme is built around gasifying 75 million tonnes of coal and lignite.
    2. Import substitution: The scheme is aimed at reducing dependence on imports of liquefied natural gas, urea and methanol.
    3. Insulation from external shocks: Domestic production of these inputs is intended to shield the country from global price volatility and supply chain disruption.
    4. The instrument: A financial outlay of ₹37,500 crore was approved for surface coal and lignite gasification projects.

    How has the coal ministry explained the empty first round?

    1. Proposal preparation takes time: Given the scale of funds each project involves, the preparation of pre-feasibility reports and project proposals runs long.
    2. Interest without applications: Several industries have communicated their interest in participating, and none has filed.
    3. The count is not final: The number of applications cannot be stated before the deadline passes, since submission is entirely online.
    4. The window reopens: Application rounds are envisaged every two months, giving industry repeated opportunities to enter.

    Challenges to the coal gasification incentive scheme

    1. High ash domestic coal raises the cost: Indian coal carries a high ash content, which lowers gas yield per tonne and raises the capital cost of the gasifier. Eg. Gasifier designs proven on low ash imported coal need modification before they run on Indian coal.
      The Fix: Tie the incentive to a gasifier configuration demonstrated on high ash domestic coal, rather than to project cost alone.
    2. The output price is set by policy, not by the market: Urea sold to farmers carries a maximum retail price fixed by the Centre, so a coal based producer’s revenue depends on the subsidy regime. Eg. Urea remains outside the Nutrient Based Subsidy regime and continues to be sold at a controlled price.
      The Fix: Offer a long term offtake price for coal based urea and methanol, so a project’s revenue is known before financial closure.
    3. No assured buyer for the other outputs: Lenders fund a plant only where a committed purchaser exists for its methanol or hydrogen. Eg. India has no binding methanol blending obligation comparable to the dated targets under the ethanol blending programme.
      The Fix: Notify a methanol blending obligation with dated targets, so demand exists independently of the capital subsidy.
    4. A coal based route to a fuel sold as clean: The process begins with coal, so the emissions case rests on capturing the carbon dioxide the process concentrates. Eg. Coal to methanol carries higher lifecycle emissions than natural gas based methanol.
      The Fix: Make carbon capture capability a condition of the incentive rather than an optional addition.
    5. Clearances have to be assembled before a bid: A promoter needs a coal linkage, land and water in place before a proposal is fileable, and the incentive supplies none of them. Eg. The Talcher Fertilizers coal to urea project in Odisha has run well past its original commissioning timeline.
      The Fix: Bundle a coal linkage and a land allotment with the incentive award, so a bidder is not chasing clearances and funding at the same time.

    Conclusion

    The obstacle here is not the size of the incentive but the absence of a price and a buyer for what a gasification plant would make. A capital subsidy lowers the cost of building the plant. It does not tell the promoter what the output will sell for, or who is obliged to buy it. The marker to watch is whether the next round is paired with an assured offtake price or a blending obligation, and whether a public sector energy company files before any private promoter does.

    Back2Basics: Lignite

    1. What it is: Lignite is the lowest rank of coal, high in moisture and low in fixed carbon, also called brown coal.
    2. Why it is used near the mine: Its calorific value is lower than that of bituminous coal, so transporting it long distances is uneconomic and it is burned or gasified close to the pithead.
    3. Where India’s reserves lie: The bulk of the country’s lignite sits in Tamil Nadu, with further deposits in Rajasthan, Gujarat and Jammu and Kashmir.
    4. Who mines it: NLC India Limited, a central public sector enterprise under the Ministry of Coal, is the largest lignite producer in the country.

    [2025] Consider the following substances:

    I. Ethanol

    II. Nitroglycerine

    III. Urea

    Coal gasification technology can be used in the production of how many of them?

    (a) Only one

    (b) Only two

    (c) All three

    (d) None

  • Private players seek ‘green energy’ status for N-power to raise funds

    Private players seek ‘green energy’ status for N-power to raise funds

    Why in the News

    Private players have sought green energy status for nuclear power so that nuclear projects can access green bonds, green loans and blended financing. The demand was made at a stakeholder consultation held by NITI Aayog, attended by around 150 participants from 60 organisations. India opened its tightly regulated civil nuclear sector to private participation last year and targets 100 gigawatt electric (GWe) of nuclear capacity by 2047, a target that needs at least $228 billion of investment. The instruments that supply the cheapest climate capital are closed to the technology, because the Ministry of Finance’s Sovereign Green Bond Framework does not include nuclear energy.

    What are India’s green finance frameworks?

    1. Sovereign Green Bond Framework: Maintained by the Ministry of Finance, it defines which project categories the proceeds of a sovereign green bond may be applied to, and nuclear energy is not among them.
    2. RBI framework for green deposits: It sets the conditions under which a bank or deposit taking institution may raise and deploy deposits labelled green.
    3. SEBI framework for green debt securities: It governs disclosure and use of proceeds for green bonds issued in the Indian securities market.

    Why do private players want nuclear classified as green energy?

    1. Access to a cheaper pool of capital: Green status would open green bonds, green loans and blended financing schemes to nuclear projects, which is the specific relief sought.
    2. The three frameworks are the gatekeepers: Industry participants asked for a review of all three, because exclusion from any one of them closes a distinct funding channel.
    3. The multilateral position is already moving: The World Bank and the Asian Development Bank are reviewing their own restrictions on nuclear investments, which is the precedent cited for a domestic review.

    What is the infrastructure status demand, and where does it stand?

    1. The demand: Private players separately suggested that nuclear power projects be accorded infrastructure status.
    2. The official reading: In NITI Aayog’s view nuclear power is already covered under the infrastructure framework, because the Harmonised Master List of Infrastructure Sub-sectors maintained by the Department of Economic Affairs includes electricity generation.
    3. What is actually being asked for: The gap is one of certainty rather than of category, and a clarification in this regard may be needed.

    What else must fall into place for the 100 GWe target?

    1. The rules are not final: The final rules under the SHANTI Act, the statute governing the opening of the sector, are likely to be ready in the next two to three months, with stakeholder consultations on the draft rules currently underway.
    2. Project timelines: The gestation period of nuclear power projects in India needs to be reduced if capacity is to be added at the pace the target implies.
    3. Site selection is a binding constraint: Identifying sites will be a major challenge as capacity scales, and site selection committees are working with the States.
    4. Fuel security beyond uranium: Thorium based technologies need to be developed to strengthen India’s long term energy security.

    Challenges to green energy status for nuclear power

    1. Taxonomies elsewhere have attached conditions rather than granting blanket inclusion: Where nuclear has been admitted to a green classification, it has come with waste and safety conditions that projects must meet continuously. Eg. The European Union’s taxonomy admitted nuclear only as a transitional activity with disposal facility and accident tolerant fuel conditions.
      The Fix: Draft any Indian inclusion as a conditional category tied to disclosed waste management and decommissioning provisioning, so the label survives investor scrutiny.
    2. Green bond investors price on verifiability, not on carbon content alone: A large share of green mandates screen out nuclear by policy, so a taxonomy change does not by itself create demand. Eg. Several sovereign and pension fund mandates exclude nuclear on exclusion lists set independently of national taxonomies.
      The Fix: Pair inclusion with a certified external review of use of proceeds, so a nuclear tranche can be assessed on the same evidence as a renewable one.
    3. Liability exposure sits ahead of the financing question: Supplier liability under India’s civil nuclear liability law has deterred private and foreign participation for over a decade. Eg. The Civil Liability for Nuclear Damage Act, 2010 gives the operator a right of recourse against the supplier, which foreign vendors have cited as a barrier.
      The Fix: Settle the recourse position by statute or by a capped insurance pool before private capital is asked to price a project.
    4. Long gestation makes debt tenors mismatch: Nuclear construction periods run well beyond the tenor of most Indian debt instruments, so refinancing risk sits with the developer. Eg. Domestic bank lending to power projects is typically structured over tenors far shorter than a nuclear build cycle.
      The Fix: Create a dedicated long tenor refinancing window for nuclear projects, on the model used for other long gestation infrastructure.
    5. Public acceptance decides sites, not policy: Land acquisition and local consent have delayed nuclear sites regardless of the financing available. Eg. Protests at Kudankulam in Tamil Nadu delayed commissioning of the plant by years.
      The Fix: Build a statutory local benefit sharing entitlement into site notification, so host districts hold a stake before construction begins.

    Conclusion

    The nuclear expansion has moved past the question of whether private capital is allowed in and reached the question of what that capital will cost. A taxonomy is the cheapest lever the government holds, because reclassification requires no new outlay and changes the interest rate on every subsequent rupee borrowed. Two decision points are dated and worth watching: the final rules under the SHANTI Act in the next two to three months, and whether the Ministry of Finance, the RBI and SEBI open their frameworks for review together or separately.

    Back2Basics: Harmonised Master List of Infrastructure Sub-sectors

    1. What it is: A list maintained by the Department of Economic Affairs in the Ministry of Finance that defines which activities count as infrastructure for policy purposes.
    2. Why the label matters: Inclusion gives a project access to infrastructure lending norms, longer tenor bank finance and easier external commercial borrowing.
    3. How it is organised: Activities are grouped under broad categories such as transport, energy, water and sanitation, communication and social and commercial infrastructure.
    4. How it changes: An institutional mechanism under the Department of Economic Affairs reviews and updates the list, with electricity generation already among the listed sub sectors.

    [2018, GS3, 15 marks] With growing energy needs should India keep on expanding its nuclear energy programme? Discuss the facts and fears associated with nuclear energy.”

  • India’s data centre boom is colliding with its climate reality

    Why in the News

    India’s data centre capacity is set to grow from about 1.5 gigawatts (GW) today to 6.5 GW by 2030, a fourfold expansion in four years, on investment the government estimates at nearly $200 billion over the coming decade. Google, Meta, Amazon and Microsoft have committed billions to build facilities, and States are competing for them with tax exemptions, cheap land and duty waivers. No policy document at the Central or State level has assessed what guaranteed power costs a grid already strained under 45 degree Celsius heat, where cooling water will come from, or what the thermal load of thousands of servers does to regions already near dangerous temperatures. The tension is that the facilities are clustering in exactly the regions where water and grid stress are most acute, and State policies attach almost no conditions to the incentives they offer.

    Why is the scale of the build-out itself the problem?

    1. A fourfold expansion in four years: Capacity nearly tripled from 520 megawatts (MW) in 2020 to nearly 1.5 GW today. The 6.5 GW projected for 2030 compresses the next round of growth into four years.
    2. Electricity demand more than quadruples: Demand from data centres is expected to rise from about 13 terawatt-hours (TWh) in 2024 to roughly 57 TWh by 2030. The Union Ministry of Power estimates that artificial intelligence alone will add 26.3 GW of new demand by 2031-32.
    3. States compete on incentives, not conditions: Maharashtra wants to be the data centre capital. Telangana has declared data centres “essential services”. Karnataka is reviewing its policy to attract more, and Rajasthan is offering tax exemptions and cheap land.

    Why does data centre water use collide with groundwater stress?

    1. The volume per facility: A 100 MW data centre consumes about 2 million litres of water daily, equal to the daily use of roughly 6,500 households. India’s data centres consumed an estimated 150 billion litres in 2024-25, projected to more than double to 358 billion litres annually by 2030.
    2. Clustering in the most stressed regions: Rajasthan extracts 147.11 per cent of its annual groundwater recharge, the second highest rate in the country. Several groundwater assessment units in Maharashtra are classified as semi-critical. Telangana’s Irrigation Minister confirmed in May 2026 that 16 districts were under groundwater stress.
    3. Cities already rationing: Hyderabad’s surface water supply dropped 20 per cent in the summer of 2024 on poor monsoon recharge, forcing the water board to ration supply. Mumbai’s reservoirs stood at 44.5 per cent of capacity in March 2026.
    4. Unaccounted in every State policy: No State policy requires public disclosure of daily water consumption. None requires a hydrogeological assessment before approval. None mandates that water sourcing must not compete with agriculture or municipal supply.

    Why can the grid not deliver the power the boom needs?

    1. Record peaks and interconnection queues: Maharashtra’s peak demand hit 27,230 MW in April 2026, the highest ever handled by the State utility. Two-year waits for 220 kV grid interconnections across the country are lengthening project timelines.
    2. Renewable power is being thrown away: India curtailed 300 gigawatt-hours of renewable energy in the first quarter of 2026 alone because the grid could not carry it, per an Ember Energy analysis of Central Electricity Authority data. Over five years India has met only about 80 per cent of its annual transmission targets, one in four major transmission schemes runs a year or more behind schedule, and 20 GW of renewable capacity faces connectivity delays of more than four months.
    3. Wires lag panels: Rajasthan and Gujarat house the bulk of utility-scale solar and wind. Both face the longest queues at pooling stations (substations where several renewable plants aggregate output before it enters the transmission grid). Solar projects are being built faster than the lines to carry their power.
    4. The coal default: Data centres need reliable, uninterrupted electricity. If renewable power cannot reach them, the power comes from coal, adding to the emissions India is trying to curtail.

    How do data centres make their surroundings hotter?

    1. The satellite evidence: A March 2026 University of Cambridge study of 20 years of NASA satellite data found that data centres raise land surface temperatures by an average of 2 degree Celsius within a 10 km radius, with extreme cases reaching 9.1 degree Celsius. About 340 million people globally live within these affected zones.
    2. Indian cities are already at the edge: Mumbai’s land surface temperature rose from 40.9 degree Celsius in 2003 to 47.3 degree Celsius in 2023, driven largely by urbanisation and heat-trapping infrastructure. Hyderabad’s urban heat island intensity ranges from 5.74 to 6.82 degree Celsius, its urban area doubled between 2001 and 2020, and it recorded temperatures above 43 degree Celsius in the summer of 2024.
    3. The feedback loop: Data centres generate heat, and that heat raises ambient temperature. Higher ambient temperature increases cooling demand. Higher cooling demand raises electricity consumption. Unless that electricity is fully renewable, emissions rise and feed the climate change that is making India hotter.

    Do State policies ask for anything in return for their incentives?

    1. Generous on incentives: State policies offer electricity duty exemptions, transmission charge waivers, stamp duty relief and fast-track clearances.
    2. Silent on conditions: None of the major State policies requires a grid impact assessment before commissioning, mandatory renewable energy sourcing, or a thermal load assessment for surrounding communities.
    3. Telangana guarantees power in a stressed State: The “essential services” classification guarantees data centres uninterrupted power even during shortages, in a State where 16 districts face groundwater stress and temperatures have reached 47 degree Celsius.
    4. Maharashtra diluted its own mandate: The State’s policy originally required 100 per cent renewable energy for core operations. In June 2026 it cut the requirement to 51 per cent, framed as improving project viability.
    5. The exceptions, and their limit: Gujarat’s Data Centre Policy 2026-29 mandates at least 51 per cent green energy sourcing. Karnataka’s IT Minister told the Assembly in March 2026 that the State was reviewing its policy over water and energy concerns, and Tamil Nadu has linked incentives to renewable compliance. Even where mandates exist, enforcement and verification remain weak.

    Why is the constraint market design rather than generation capacity?

    1. Capacity is not the bottleneck: The Union Ministry of Power holds that India’s generation pipeline can absorb the additional demand from data centres. The constraint is market design and transmission infrastructure.
    2. Price grid services separately: The Council on Energy, Environment and Water (CEEW) argues for climate-intelligent power markets in which short-term markets pay separately for ramping, storage and demand response.
    3. Storage at the pooling station: Ember calculates that roughly 3 to 4 GW of two-hour battery storage at renewable pooling stations could have absorbed most of the generation curtailed in early 2026. The technical pieces exist; the gap is regulatory and commercial.

    What should a national sustainability framework contain?

    1. Enforceable use standards: CEEW proposes phased power and water use standards with enforceable benchmarks, and a national AI Energy Star rating that lets buyers and regulators compare how energy efficient a facility or model actually is.
    2. Who pays for the grid: The Institute for Energy Economics and Financial Analysis (IEEFA) warns that a significant part of the associated infrastructure cost could be socialised. Where wider grid infrastructure is required, government support or dedicated financing should stop the cost being passed to consumers through higher tariffs.
    3. Siting away from stressed hubs: IEEFA points to coastal locations. These offer proximity to near-shore wind and solar, and seawater cooling without desalination. Most facilities instead cluster around Mumbai, Hyderabad, Bengaluru and the National Capital Region, where water and grid stress are most acute.
    4. Four minimum standards: A national framework would set minimum standards for renewable energy sourcing, water consumption disclosure, grid impact assessment and thermal load evaluation. It would give investors one set of expectations and consumers one set of protections, on the premise that environmental constraints are economic constraints.

    Challenges to a national data centre framework

    1. Split jurisdiction: Water is a State List subject and electricity sits on the Concurrent List, so a Central standard on water sourcing or grid impact binds no State unless the State adopts it. Eg. The Ministry of Electronics and Information Technology’s draft National Data Centre Policy of 2020 addressed infrastructure status and single-window clearance, not resource standards.
      The Fix: Route the standards through the Central Electricity Authority’s technical standards and the Bureau of Energy Efficiency, which already bind connected consumers, and tie Central incentive money to State adoption.
    2. Mandates without metering: A renewable sourcing mandate is only as good as the verification behind it, and discoms already miss the obligations they carry. Eg. State distribution companies have missed Renewable Purchase Obligation targets for years, forcing the Ministry of New and Renewable Energy to renotify trajectories.
      The Fix: Require third-party audited reporting of power usage effectiveness and water usage effectiveness (ratios of total facility energy and water to that used by computing equipment) as a condition of every incentive.
    3. Cooling technology is a trade-off, not a free fix: Liquid and immersion cooling cut water use but raise capital cost and still dump heat locally. Eg. Evaporative cooling, the cheapest option at 45 degree Celsius, is also the most water intensive.
      The Fix: Set the water standard by climate zone rather than one national number, so a coastal seawater-cooled site and an inland Rajasthan site face different limits.

    Conclusion

    The data centres will be built, and the only open question is on whose terms. The unresolved tension is between States competing on incentives and a resource base that no State policy has been made to account for. What to watch is whether the Centre converts the four standards, renewable sourcing, water disclosure, grid impact and thermal load, into an enforceable national framework before the projected capacity is locked in. The nearer marker is whether Karnataka’s policy review produces conditions or only more incentives.

    Back2Basics

    1. Urban heat island: An urban heat island is the difference in temperature between a built-up city and its rural surroundings, caused by concrete, asphalt and roofs absorbing and re-emitting heat that vegetation and soil would have released through evaporation.
    2. Intensity: Its intensity is that temperature gap in degrees, so Hyderabad’s 5.74 to 6.82 degree Celsius means the city runs that much hotter than its surroundings at the same hour.
    3. Why data centres add to it: Servers convert almost all the electricity they draw into heat, and cooling systems reject that heat into the surrounding air or water, so a large facility acts as a fixed heat source inside the island.

    “[2026] Which of the following statements with regard to Green Hydrogen is/are correct?

    1. It is decarbonized hydrogen obtained from natural gas reforming combined with carbon capture and storage (CCS).

    2. It is produced using electrolysis of water with electricity generated by renewable energy.

    3. National Green Hydrogen Mission of India aims for abatement of nearly 50 MMT of annual greenhouse gas emissions by 2030.

    (a) 1 only (b) 2 and 3 only (c) 2 only (d) 1, 2 and 3

  • ‘No material price hit on CBG on revised offtake framework’

    Why in the News

    The Union Petroleum Ministry has said that the revised compressed biogas (CBG) offtake price will not translate into a material price increase for gas consumers. The assurance answers concerns raised after the Union Cabinet cleared a revised Galvanizing Organic Bio Agro Resources Dhan (GOBARdhan) scheme on 6 August, which introduced a CBG offtake price of Rs 2,110 per metric million British thermal unit (MMBtu). The Ministry states that the full offtake price will not be recovered from consumers, since a government funded affordability cushion and a much larger gas pool absorb the difference. The contested point is whether a producer facing price is being set well above the consumer facing price, and who carries the gap between the two.

    What does the revised offtake framework fix?

    1. A single administered offtake price: The revised scheme sets the price at which compressed biogas is picked up from producers at Rs 2,110 per MMBtu, replacing case by case commercial negotiation.
    2. The stated purpose is producer viability: The Ministry describes the framework as giving CBG producers a “stable and viable” price so that plants can operate “sustainably”.
    3. Two prices, not one: The offtake price and the price billed at the burner tip are set by separate mechanisms, so a movement in one does not carry through to the other.

    How is the consumer insulated from the offtake price?

    1. A direct affordability cushion: The government provides a cushion of Rs 10 per kilogram of CBG, funded from the exchequer rather than recovered in tariffs.
    2. Stacking against a wider gas pool: The biogas volume is blended into a substantially larger pool of natural gas, so its higher unit cost is diluted across the whole pool before reaching the burner tip.
    3. The two work together, not separately: The Ministry’s position rests on the cushion and the pooling operating at the same time, not on either one alone.

    Challenges to the compressed biogas offtake framework

    1. The subsidy is an open ended fiscal commitment: An affordability cushion fixed per kilogram grows in direct proportion to volume, so success in scaling the sector raises the annual outgo rather than reducing it. Eg. The blending obligation for compressed biogas in city gas networks is designed to rise year on year. Fix. Publish a declining glide path for the cushion alongside the offtake price, so producers plan against a known taper.
    2. Pooling only dilutes cost while the biogas share stays small: The wider gas pool absorbs the price difference precisely because compressed biogas is a small fraction of it, and that cushion thins as the mandated share rises. Eg. Domestic gas allocation to city gas distribution is already rationed against demand. Fix. Tie each upward revision of the blending obligation to a reassessed pooled price so the dilution assumption is tested rather than assumed.
    3. Feedstock aggregation remains the binding constraint: Plant economics turn on assured daily supply of cattle dung, press mud and agricultural residue, which no offtake price by itself organises. Eg. Several commissioned compressed biogas plants run below rated capacity for want of steady feedstock. Fix. Contract feedstock aggregation through dairy cooperatives and sugar mills at the plant approval stage, so supply is committed before capital is sunk.
    4. Fermented organic manure has no assured market: A biogas plant produces a large byproduct stream that is only viable when the manure sells, and its offtake is not covered by this price framework. Eg. Fermented organic manure competes against heavily subsidised urea on farm gate price. Fix. Extend the market development assistance already notified for organic manure to the full output of registered compressed biogas plants.

    Conclusion

    The framework sets a producer facing price and leaves the consumer facing price to be settled elsewhere, which is what the Ministry’s assurance rests on. That assurance holds only while compressed biogas remains a small share of the gas pool. The next test is the scheme’s operating guidelines, which will show whether the support is open ended or tapered and how feedstock supply is to be secured.

    Back2Basics: GOBARdhan

    1. What it is: An initiative to convert cattle dung, agricultural residue and other organic waste into biogas, compressed biogas and organic manure.
    2. Where it sits: It runs as a unified registration and monitoring framework across ministries, with the Department of Drinking Water and Sanitation operating its central registration portal.
    3. What it targets: Village level cleanliness, a rural income stream from waste, and a domestic substitute for imported natural gas.
    4. How it links to fuel policy: Compressed biogas produced under it feeds the Sustainable Alternative Towards Affordable Transportation (SATAT) offtake route into city gas distribution networks.

    Matching Previous Year Question

    “[2020] According to India’s National Policy on Biofuels, which of the following can be used as raw materials for the production of biofuels? 1. Cassava 2. Damaged wheat grains 3. Groundnut seeds 4. Horse gram 5. Rotten potatoes 6. Sugar beet Select the correct answer using the code given below: (a) 1, 2, 5 and 6 only (b) 1, 3, 4 and 6 only (c) 2, 3, 4 and 5 only (d) 1, 2, 3, 4, 5 and 6 ANSWER: (a)”

  • Problem with ethanol blending isn’t sugar — it’s reliance on grains; the way forward (Op-ed by Harish Damodaran)

    Why in the News

    India’s ethanol blended petrol (EBP) programme, an arrangement under which oil marketing companies blend ethanol into petrol to progressively raise the blending ratio, was designed primarily to help sugar mills earn an additional revenue stream so they could pay cane farmers on time. For the current supply year ending October 2026, grain based feedstock accounts for 759.8 crore litres, or 72.5 percent, of the 1,048.3 crore litres of ethanol allocated among distilleries, against 288.5 crore litres, or 27.5 percent, from sugarcane based feedstock. What began as a sugar-support programme has become a grain-dependent one, and the article argues this reversal, not sugar diversion, is the programme’s real problem.

    What is the Ethanol Blended Petrol (EBP) programme?

    1. About: The EBP programme requires oil marketing companies to blend ethanol into petrol at a rising target ratio, currently 20 percent under the E20 standard, to cut crude oil imports and support farm incomes.
    2. Feedstock: Ethanol can be produced from sugarcane derived molasses and juice, or from cereal grains such as maize and rice, through milling, starch extraction, fermentation, distillation and dehydration to 99.9 percent pure alcohol.
    3. Original design: The programme was conceived to give sugar mills a secondary revenue stream so they could clear cane payment dues to farmers, and was later extended to maize farmers as an additional demand source.

    How did the feedstock mix shift from sugarcane to grain?

    1. The molasses-only phase, till 2017-18: All ethanol supplied to oil marketing companies came from C-heavy molasses, the final byproduct of cane juice processing left after mills had recovered all economically extractable sugar.
    2. The B-heavy and direct-juice phase, from 2018-19: Mills began producing ethanol from intermediate B-heavy molasses and directly from cane juice or syrup, incentivised by higher government-set prices for ethanol from these routes, which let mills divert sucrose before it was even crystallised into sugar. Ethanol supplies to oil marketing companies rose from 38 crore litres in 2013-14 to 190 crore litres in 2018-19, and blending rose from 1.6 percent to 4.9 percent over the same period.
    3. The grain takeover, 2018-19 onward: Standalone grain-based distilleries, running on maize or on surplus and damaged rice sourced from the Food Corporation of India (FCI) or the open market, expanded independently of the sugar season. By 2023-24, grain-based feedstock supplied 402 crore litres, or 59.7 percent, of the 673 crore litre total that helped achieve 14.6 percent average blending, a reversal the article calls the tail wagging the dog.
    4. Current supply year, 2025-26: Of the 1,048.3 crore litres allocated to hit the E20 target, 759.8 crore litres, or 72.5 percent, is from grains and only 288.5 crore litres, or 27.5 percent, is from sugarcane-based feedstock, against a backdrop of September-ending sugar stocks projected at a 17-year low.

    Why is rice, not maize, now the likely mainstay feedstock?

    1. Maize supply risk: El Nino conditions are expected to persist through the first half of next year, raising doubts about maize availability for ethanol in 2026-27 even as sugarcane diversion is curtailed.
    2. Rising reliance on FCI rice: The government allocated 5.2 million tonnes of surplus FCI rice to ethanol distilleries for 2025-26, raised to 7.2 million tonnes in July; at 450 to 460 litres of ethanol per tonne, that yields only 325 to 330 crore litres, well short of the roughly 1,050 crore litres needed to sustain E20.
    3. Rice is water-intensive and underpriced for this use: FCI rice is sold to ethanol distilleries at Rs 23.2 per kg, with a reserve price of Rs 21 per kg for fully broken grains, against a retail market price of Rs 40 per kg for normal rice and Rs 30 per kg for broken rice, and rice is a water-guzzling crop to be diverting toward fuel at scale.
    4. Distillery capacity outpaces demand: Distillers have built an aggregate ethanol production capacity of nearly 2,000 crore litres, against 421 crore litres in 2014 and current annual offtake of 1,050 crore litres, and it is this installed capacity, not farmer need, that is driving the push for even higher blending standards such as E22, E25, E27 and E30.

    What effect has the programme had on maize farmers, and what is at risk if grain reliance deepens further?

    1. Maize price gains: With ethanol demand added to poultry and livestock feed demand, wholesale maize prices in India rose from a Rs 13.8 to Rs 17.8 per kg range in 2021 to a Rs 22.1 to Rs 24.5 range in 2024, benefiting maize growers the way the programme once benefited cane farmers.
    2. A rice-driven repeat of the same trade-off: Sustaining current blending targets without sugar or adequate maize would require earmarking still more FCI rice, a shift the article argues is difficult to justify given rice’s water footprint and its underpriced diversion from the food security stock.

    Way Forward

    1. Discourage standalone grain distilleries reliant on FCI rice: The government should end this diversion route and push distillers toward less water-intensive grains such as bajra and jowar, which carry 58 to 62 percent recoverable starch and can yield 380 to 400 litres of ethanol per tonne, comparable to maize, letting millet farmers gain the same price benefit maize growers have seen.
    2. Stop chasing blending targets ahead of schedule: The EBP programme was already succeeding at 10 to 15 percent blending, and the article notes the government’s own chief economic adviser has suggested reverting to the E10 standard, an argument the piece endorses as pragmatic rather than a retreat.

    Back2Basics: What is the E10/E20 standard?

    1. E10 and E20 denote the percentage of ethanol blended into petrol, so E20 petrol contains 20 percent ethanol against 80 percent petrol by volume.
    2. India crossed the E10 blending average in 2021-22 and reached the E20 national average in the current 2025-26 supply year, years ahead of the original 2030 target set for E20.
    3. Government notified fuel standards now extend beyond E20 to E22, E25, E27 and E30, reflecting distillery capacity built well beyond current ethanol offtake.

    Matching Previous Year Question

    “In the context of alternative sources of energy, ethanol as a viable bio-fuel can be obtained from:” (2009, Microtheme: Biofertilizers/Fuels, Subject: Environment)

  • Policy mistakes, not ethanol, behind sugar price rise (Editorial)

    Why in the News

    Retail sugar prices have risen from an average of Rs 45 to Rs 65 per kg within a month, and the increase is being widely blamed on the ethanol blended petrol programme. Only 27.5 percent of the ethanol supplied by distilleries to oil marketing companies in 2025-26 came from sugarcane juice and molasses, with the balance from cereal grains, and the roughly 3 million tonnes of sugar diverted for ethanol is close to a tenth of the year’s 30.9 million tonne gross production. Similar or larger diversions in the four preceding sugar years did not cause comparable price spikes, which places the blame elsewhere.

    Is ethanol actually responsible for the price spike?

    1. Small diversion share: The estimated 3 million tonnes of sugar diverted to ethanol production is close to a tenth of the 30.9 million tonne gross sugar output for the year ending September 2026.
    2. No precedent for a price link: The four preceding sugar years saw diversions of 3.5 million tonnes, 2.4 million tonnes, 4.3 million tonnes and 3.6 million tonnes respectively, all without triggering a comparable price spiral.
    3. Feedstock mix has shifted away from sugar already: Only 27.5 percent of ethanol supplied to oil marketing companies in 2025-26 came from sugarcane juice and molasses, with the rest from cereal grains, so the programme is no longer primarily a sugar diversion story.

    What actually explains the price spurt?

    1. A large output shortfall: Gross sugar production for the year came in well below the initial 34.4 million tonne projection made at the start of crushing in November, a shortfall of 3.5 million tonnes.
    2. A late government response: Mills in Uttar Pradesh and Maharashtra were struggling to get cane and shutting down crushing operations by February, but the shortfall was not addressed until exports were banned only in mid-May.
    3. Panic measures after prices soared: From July, as a deficient June monsoon raised concerns about cane yields for 2026-27, the government imposed a 400 tonne stock limit with a 30 day holding cap on all dealers and ordered mills to furnish details of bulk buyers who purchased 500 tonnes or more.

    What should the government have done instead?

    1. Keep the import window open: Rather than banning exports, the government could have cut the tariff on raw and white sugar imports from 100 percent to zero by April, when most mills had stopped crushing.
    2. Rely on market intelligence over controls: The sugar industry runs on government-set controls, from cane pricing to how much a mill may sell in a given month, a control structure this crisis exposed as failing to anticipate and balance supply and demand.

    Conclusion

    The editorial’s central claim is that the sugar price rise is a policy failure, rooted in a delayed response to an anticipated output shortfall and a subsequent set of panic controls, not a consequence of the ethanol blending programme. The remedy it points to, opening the import window through tariff cuts rather than export bans and stock limits, remains untested by the government to date.

    Matching Previous Year Question

    “Statement I: Of the two major ethanol producers in the world, i.e., Brazil and the United States of America, the former produces more ethanol than the latter. Statement II: Unlike in the United States of America, where corn is the principal feedstock for ethanol production, sugarcane is the principal feedstock for ethanol production in Brazil.” (2025, Microtheme: Biofertilizers/Fuels, Subject: Environment)

  • Centre plans to cap number of airports a single bidder can win in next privatisation round

    Why in the News

    The Ministry of Civil Aviation plans to cap the number of airports a single private bidder can win in the third round of airport privatisation. The round covers 11 airports grouped into five bundles: Amritsar-Kangra, Varanasi-Gaya-Kushinagar, Bhubaneswar-Hubballi, Raipur-Aurangabad, and Tiruchirapalli-Tirupati. The first two privatisation rounds concentrated a large share of India’s privatised airport traffic in two private groups. The cap sets up a tension between preventing bidder concentration and keeping the auction attractive to the handful of infrastructure players with the balance sheet to run an airport.

    What does the third privatisation round cover?

    1. Bundled bidding across five circuits: The Airports Authority of India (AAI) (the statutory body that owns, manages and privatises Indian civil airports) has grouped the 11 airports into five bundles rather than auctioning each separately, so a bidder wins or loses an entire regional cluster in one bid.
    2. Mix of trunk and regional airports: The bundles combine a higher-traffic anchor airport with smaller regional airports, so an operator absorbs a loss-making regional airport as part of winning the more viable one.
    3. Continuation of the Public-Private Partnership route: The round extends the Operation, Management and Development Agreement (OMDA) (the concession contract structure under which AAI leases an airport’s operations to a private developer for a fixed term while retaining ownership) model used in the first two rounds.
    4. Follows two prior privatisation rounds: Six airports were privatised in the first round and further airports in the second, before this third round was structured.

    Why is the Centre capping bidder concentration?

    1. Two private groups dominate the privatised airport map: One conglomerate operates several of India’s highest-traffic privatised airports won across the earlier rounds, while a second group holds a smaller cluster, leaving few large private operators outside these two.
    2. Concentration weakens the Centre’s post-award leverage: Where one bidder holds most privatised capacity, AAI has fewer credible alternative operators to discipline service standards or renegotiate terms.
    3. A cap widens the bidder base for smaller circuits: Limiting how many bundles a single group can win is intended to draw in operators who would otherwise not bid against an incumbent with deeper resources.
    4. Precedent from other infrastructure sectors: Sector regulators in ports and telecom have used similar concentration limits to prevent a single operator from controlling bottleneck infrastructure across regions.

    Challenges to the airport bidder cap

    1. Fewer bidders may qualify at all: Airport concessions require large upfront capital and aviation operating experience, a pool already limited to a handful of Indian infrastructure conglomerates. Eg. Only two or three consortia bid seriously in each of the first two rounds. Fix. Allow joint ventures and foreign strategic partners to combine capital and aviation expertise so more consortia can qualify.
    2. Regional airports could go unsold: A bundle pairing a loss-making regional airport with a viable one may see no bidder if the cap forces bidders away from the bundles they actually want. Eg. Kushinagar and Gaya carry limited passenger traffic and depend on the Varanasi bundle for viability. Fix. Offer viability gap funding for the weaker airport in each bundle rather than relying on cross-subsidy alone.
    3. Cap design risks being circumvented through related entities: A promoter group can bid through separate subsidiaries or affiliates that appear unconnected on paper. Eg. Beneficial-ownership opacity has complicated concentration limits in the telecom spectrum auctions. Fix. Define the cap by ultimate beneficial ownership, not by the bidding entity’s name.
    4. Slower privatisation pace: Restricting the largest, most capable bidders could stretch out the time needed to complete the round, delaying the capacity upgrades the smaller airports need.
    5. Revenue realisation may fall: A cap that keeps the highest bidder from taking every bundle it wants could produce lower aggregate concession fees than an uncapped auction would.

    Conclusion

    The Ministry of Civil Aviation is finalising the bidding norms for the third privatisation round, with the airport-count cap intended to correct the concentration that followed the first two rounds. The bid documents for the five bundles are expected to be released once the cap’s exact threshold is settled.

    Back2Basics: Airports Authority of India

    1. Statutory body under the Ministry of Civil Aviation, constituted under the Airports Authority of India Act, 1994.
    2. Owns, develops, and manages the majority of India’s civil airports, and leases select airports to private operators through the OMDA route.
    3. Also provides air navigation services across Indian airspace, a function it retains even at privatised airports.
    4. Earns revenue from aeronautical and non-aeronautical charges at the airports it directly operates.

    Matching Previous Year Question

    “[2024, GS3, 15 marks] What is the need for expanding the regional air connectivity in India? In this context, discuss the government’s UDAN Scheme and its achievements.”