India’s domestic crude output has fallen for a decade. The new policy stack of the Oilfields Amendment Act, the Samudra Manthan deepwater mission, and ten OALP rounds is the most ambitious attempt to reverse the slide. The arithmetic still does not close.
When Prime Minister Narendra Modi used his Independence Day address on 15 August 2025 to announce the National Deep Water Exploration Mission, branding it Samudra Manthan, a Sanskrit phrase meaning “Churning of the Ocean”, drawn from the Hindu mythological epic in which gods and demons churn the cosmic sea to extract the elixir of immortality, the rhetoric was characteristic. The arithmetic was unforgiving.
India’s domestic crude oil production fell to 28.7 million metric tonnes (MMT) in fiscal year 2024-25 (the Indian financial year runs from April to March), the lowest in almost two decades, against a peak of 36.96 MMT in 2015-16. Self-sufficiency in crude, the share of national consumption met from domestic wells, stood at 12.3% in FY25, against an import dependency that climbed to 88.2%, up from 87.8% the previous year. For an economy whose oil consumption is projected by the International Energy Agency (IEA), the Paris-based body that coordinates energy security among advanced economies, to grow from 5.5 million barrels per day in 2024 to 8 million by 2035, the largest absolute increase of any country in the world, the gap between what India consumes and what it produces is widening at speed.
The government’s response is the most ambitious restructuring of the Indian upstream sector since the New Exploration Licensing Policy (NELP) of 1997, which first opened acreage to private and foreign bidders. It rests on three pillars: a new legal framework, a frontier exploration mission, and a continuous bidding model. Whether they add up to a credible reversal of decline is the question now confronting Delhi.
What the sector looks like today
India’s exploration and production (E&P) sector is dominated by two state-owned companies. Oil and Natural Gas Corporation (ONGC), a Maharatna public-sector enterprise, the top tier of Indian state-owned companies, with operational autonomy and enhanced investment powers, accounts for roughly two-thirds of national crude output. Oil India Limited (OIL), a smaller Maharatna concentrated in Assam and the northeastern states, accounts for most of the balance, alongside private operators led by Cairn India, now part of Vedanta Limited, the Anil Agarwal-controlled mining and metals conglomerate, and Reliance Industries Limited, the Mukesh Ambani-led conglomerate that operates the KrishnaGodavari D6 gas block with BP plc, the British oil major.
The structural problem is geological. ONGC’s main producing assets, including the Mumbai High offshore field in the Arabian Sea and legacy onshore fields in Assam and Gujarat, are mature: their natural decline rates exceed the rate at which enhanced oil recovery can offset them. The Petroleum Ministry’s Hydrocarbon Outlook 2024-25 report attributes the FY25 decline of 2.2% to “depletion of reserves and limited contribution from new discoveries”. Between April 2025 and January 2026, the national crude target was missed by 10.54% and even fell short of the previous year’s output, indicating that the problem has worsened despite three rounds of policy reform.
ONGC, under Samudra Manthan, has set targets of doubling India’s hydrocarbon reserves by 2032 and tripling national output by 2047. Those numbers cannot come from the current asset base. They require frontier exploration in geological provinces India has barely touched.
The 2025 Amendment Act
The first pillar is the Oilfields (Regulation and Development) Amendment Act, 2025, which received Presidential assent on 28 March 2025 and came into force on 15 April. The original 1948 Act, drafted before independence and largely unchanged for seven decades, was structured around colonial mining law and treated petroleum leases as a subset of mineral leases, focused on royalty collection rather than exploration encouragement.
The 2025 Amendment makes five substantive changes. It broadens the statutory definition of “mineral oils” to include coal bed methane (CBM), methane extracted from coal seams, shale gas, shale oil, tight gas, natural gas trapped in low-permeability rock, tight oil, oil shale, and gas hydrates, the ice-like methane compounds found on deep-sea floors. It introduces a “petroleum lease” category distinct from a mining lease, with simpler procedures for assignment, transfer, and sub-leasing. It permits cross-jurisdictional unitisation (the joint development of an oil or gas reservoir straddling two or more lease boundaries, a long standing source of dispute). It empowers the Central Government to regulate decommissioning, infrastructure sharing, carbon emission reduction, and renewable energy projects within oilfield areas. And it stiffens penalties for violations.
The Act has been paired with the Petroleum and Natural Gas Rules, 2025, currently in draft consultation. Petroleum Secretary Pankaj Jain framed the reform in commercial terms at an October 2025 industry event: “It will become more and more difficult for us to make a case to believe in India and believe that India has the ability to discover something.” Without a major discovery soon, even the best-designed contract framework will struggle to retain international interest.
The reform package also includes two earlier moves. In late 2024, the windfall tax on domestically produced crude, a special additional levy introduced in July 2022 to capture super-profits during the price spike, was abolished, removing what international oil companies (IOCs) had identified as a key uncertainty in their India project economics. Royalty has been waived entirely for exploration in Category-II basins, areas with known hydrocarbon presence but no commercial production, and Category-III basins, geologically promising but unexplored, including the Andaman offshore zone. A 20% premium for gas from new wells generated Rs 3,352 crore of additional revenue for ONGC in the first half of FY26 alone.
Samudra Manthan and the Andaman gamble
The second pillar is the National Deep Water Exploration Mission. Codenamed Samudra Manthan, it targets more than 1 million square kilometres of offshore acreage, principally in the Andaman and Nicobar Islands offshore basin in the Bay of Bengal, the ultra-deepwater zones of the Krishna-Godavari (KG) Basin off Andhra Pradesh, and the Cauvery Basin off Tamil Nadu. The unlocking of these areas was made possible by a 2022 decision opening approximately 1 million square kilometres of formerly “No-Go” zones, offshore areas previously restricted on defence and environmental grounds, for exploration bidding.
The Andaman bet is the boldest. The basin sits at the tectonic confluence of the Indian and Burmese plates, geologically analogous to producing basins in Southeast Asia, but until recently was almost entirely unexplored by Indian operators. In late 2025, Oil India confirmed the discovery of natural gas at its Sri Vijayapuram-2 well in the Andaman deepwater block AN-OSHP-2018/1, awarded under the Open Acreage Licensing Policy Bid Round II in 2019. Petroleum Minister Hardeep Singh Puri said “initial production testing of the well in the range of 2,212 to 2,250 meters has established the presence of natural gas with intermittent flaring, with approximately 87% methane”. ONGC separately announced the Konark and Utkal discoveries in the Mahanadi Basin off Odisha. The ANDW-7 wildcat well in the East Andaman Back Arc has shown traces of light crude and condensate.
ONGC’s capital expenditure reached Rs 62,000 crore (about $7.4 billion) in FY25, much of it directed toward offshore drilling. The company has tendered for up to $20 billion of deepwater drillship and semi submersible rig contracts over a five-year exploration programme. ONGC and OIL are now drilling at water depths of up to 5,000 metres, beyond the operational experience either company had two years ago, and have signalled partnerships with BP plc, ExxonMobil, TotalEnergies, and Petrobras (Brazil’s state oil company, with the world’s deepest commercial production track record in the Brazilian pre-salt). Oil India signed a memorandum of understanding with Petrobras at India Energy Week 2025.
The deepwater bet has obvious risks. Geological complexity is high; dry holes (exploration wells that find no commercial hydrocarbons) at these depths cost hundreds of millions of dollars each. Environmental sensitivity in the Andaman ecosystem is acute, and any spill would carry political costs beyond commercial ones. And the economics depend on sustained high oil and gas prices, which the current Iran crisis has delivered but which the broader energy transition is likely to erode over the 2030s.
OALP and DSF
The third pillar is the Open Acreage Licensing Policy (OALP), introduced in 2016 under the Hydrocarbon Exploration and Licensing Policy (HELP). OALP replaced the earlier system, in which the government pre-identified blocks for auction, with a continuous Expression of Interest (EoI) regime: companies propose any area they wish to explore and the government then puts those areas to bid. The contract structure shifted from production-sharing, in which the government took a share of physical output, leading to chronic disputes over cost recovery, to revenue-sharing, the government takes a defined percentage of operator revenue regardless of cost.
Ten OALP rounds have been concluded or launched since 2018. The most recent completed round, OALP IX, awarded 28 blocks in April 2025 covering 1.36 lakh square kilometres across eight sedimentary basins. ONGC was the largest winner with 15 blocks, 11 alone, three with Oil India, one with Reliance and BP. Oil India won nine blocks, taking its exploration acreage from 60,000 to 110,000 square kilometres, an 85% expansion in a single round. Vedanta won seven. A notable milestone was the first-ever joint bid by Reliance, BP, and ONGC for a Saurashtra Basin offshore block in Gujarat.
OALP-X, launched at India Energy Week 2025 in February, is the largest round yet by acreage: 25 blocks across 1.92 lakh square kilometres in 13 sedimentary basins, with one block in deepwater and 12 in ultra deepwater. OALP-XI has been announced to follow with 21 more blocks. Parallel to OALP, the Discovered Small Field (DSF) policy targets smaller, already-discovered but unmonetised fields with simpler contractual terms. DSF Round IV launched alongside OALP-X with 55 discoveries across nine contract areas and estimated reserves of 258.59 million metric tonnes of oil equivalent (MMTOE).
The optics are strong; the bidder data are weaker. OALP-IX attracted only four bidders, with most blocks receiving only two bids. OALP-X’s closing date has been extended five times, from July 2025 to May 2026, signalling that international interest is thinner than the acreage on offer suggests. The structural problem is that India’s geological promise is unproven and its country risk premium remains material. Despite the windfall tax repeal and the new Act, IOCs are weighing India against opportunities in Guyana, Suriname, Namibia, and the US offshore Gulf, where reserve confirmation is higher and political risk lower.
The private-sector role
Indian E&P remains overwhelmingly state-dominated, but the 2025 reforms have widened the door for private and foreign capital in three ways. First, the Reliance-BP partnership in KG-D6, India’s largest private gas production story for two decades, has been extended into new acreage through the OALP-IX joint bid with ONGC. Second, Vedanta, which controls Cairn India, has been an aggressive OALP bidder, bidding on all 28 blocks in Round IX and winning seven. Third, the Andaman deepwater campaign explicitly invites foreign supermajors as technical and capital partners.
Critics, including the All India Central Council of Trade Unions (AICCTU), have argued that the 2025 Amendment Act amounts to a “gateway to privatisation”, reducing public-sector primacy and environmental safeguards. The historical pattern they cite is real, ONGC discovered hydrocarbons in the KG Basin in 1983, but Reliance and partners captured the bulk of commercial gains in the later production phase; in the Panna-Mukta fields in the Gulf of Khambhat, ONGC bore the exploration risk but the 1994 production-sharing contract gave it only a 40% stake. The reform debate is therefore not purely technical. It is also distributional, over who captures the upside when state-borne exploration risk translates into commercial output.
The strategic significance
The exploration push must be read against the strategic backdrop of the Iran conflict and the structural reorientation of global oil trade. India’s 88% import dependency, the fact that half its imports transit the Strait of Hormuz, the secondary-sanctions pressure on its Russian crude purchases, and the projected 5 percentage-point rise in import dependency by 2035 all argue for a domestic supply response of historic scale.
Even on optimistic assumptions, the arithmetic is uncomfortable. To merely arrest decline at 28.7 MMT requires successful exploration sufficient to offset natural depletion of mature fields, currently running at roughly 1.1% a year. To meaningfully reduce import dependency, output would need to rise to perhaps 60 MMT by 2035, implying roughly a doubling. Doubling output over a decade is feasible only if at least one major deepwater discovery in the Andaman or ultra-deep KG Basin moves to commercial production by the early 2030s, and if a meaningful share of OALP-IX through XI awards translates into actual wells drilled rather than awards held for option value.
The lead times are unforgiving. From a successful exploration well to first production typically takes seven to ten years in deepwater. The Andaman discoveries announced in late 2025 are unlikely to produce commercial volumes before 2032 at the earliest. The OALP-IX awards, signed in April 2025, will not contribute output until the early 2030s. India’s domestic supply response is structurally lagged. The current decade’s import bill is largely locked in.
What this means for India
The 2025 policy stack of the Oilfields Amendment Act, Samudra Manthan, and continuous OALP rounds is the most coherent attempt India has made to confront its upstream decline. It addresses the right diagnoses: an outdated legal framework, an unfilled deepwater frontier, and a bidding cycle that needed continuity rather than episodic auctions. It has produced early evidence of momentum, in the Andaman gas discovery, the doubling of Oil India’s acreage, and the first three-way bid by ONGC, Reliance, and BP.
But it does not yet close the import dependency gap. Even successful execution of every announced initiative leaves India importing 80% or more of its crude in 2035, against the IEA’s projection of 92%. The realistic strategic objective is not self-sufficiency but managed dependency: enough domestic supply to dampen the marginal effect of global crude shocks, enough policy credibility to keep international capital engaged through a long-cycle exploration programme, and enough discoveries to make the case that India is geologically worth the bet.
The deeper question Delhi must answer is whether oil and gas remain the right asset class to lead the response. The same capital ONGC is committing to deepwater drilling could plausibly accelerate green hydrogen, offshore wind, and grid storage, where India’s structural advantages of land, labour, and demand are clearer than its hydrocarbon endowment. The government’s position is that hydrocarbons will remain indispensable for decades even as renewables scale. That is true. But the marginal rupee allocation between drilling 5,000 metres beneath the Andaman seabed and building 10 gigawatts of offshore wind in the same basin is a judgement, not an inevitability. The Churning of the Ocean is, in that sense, a wager. The next decade will reveal what it has produced.