This blog’s piece on India’s exploration licensing found that the Open Acreage Licensing Programme had awarded about 172 blocks and $4.36 billion of committed work since 2017, for 14 discoveries and one marginal producing field. On 31 July 2026 the Cabinet approved a different approach for the hardest acreage. Samudra Manthan, the National Offshore Exploration Scheme, puts Rs 84,084 crore of public money into surveying the seabed, sharing the cost of deepwater wells and building shared offshore infrastructure, up to 2030-31.

This piece sets out what the money buys, what a deepwater well costs, what the reserve target means against India’s output, and what the country’s last deepwater bets suggest about the step after a discovery.

What the money buys

About half the outlay pays for drilling, a third for data. The seismic share of Rs 28,534 crore splits into Rs 12,000 crore of basin-wide 2D surveys, Rs 12,534 crore of 3D and other geophysics, and Rs 4,000 crore to reprocess data already in the National Data Repository. The four components reported sum to Rs 83,734 crore, Rs 350 crore short of the total; the reports do not say what the rest is for.

The drilling arithmetic has a gap too. The government will pay up to half the eligible cost of each deepwater well, capped at Rs 675 crore (some reports say Rs 650 crore). Sixty wells at the cap is Rs 40,500 crore, but the drilling line is Rs 43,200 crore, or Rs 720 crore a well. The Rs 2,700 crore difference could pay for about 4 more wells at the cap, or may cover drilling costs outside the per-well support; the release as reported does not explain it.

What a deepwater well costs

The cap binds on any well costing more than Rs 1,350 crore, about $142 million. That is at the top of the range now quoted for Indian deepwater wells. The petroleum minister put a typical deep-sea well at about $100 million in September, with rigs leasing at around $250,000 a day; Swarajya put wells in the scheme’s target areas at $120–145 million; and the cost of each well in the earlier stratigraphic drilling campaign was reported to have risen from Rs 800 crore to about Rs 1,200 crore. At those costs the scheme pays close to half, which is the intention: it turns a $100–145 million bet into a $50–75 million one for the company drilling.

What 600 MMTOE means

The scheme aims to add more than 600 million tonnes of oil equivalent (MMTOE) of reserves. The government puts the hydrocarbon potential of the eastern and western offshore basins at over 5,600 MMTOE, so the target is about 11% of that potential turned into proved reserves. India produced about 28.0 million tonnes of crude and 34.3 billion cubic metres of gas in 2025-26, provisionally, or about 62 MMTOE on the oil-plus-gas convention the Directorate General of Hydrocarbons uses. 600 MMTOE is therefore about 10 years of current domestic output, a meaningful addition but well short of replacing the 88% of crude that India imports.

The step after a discovery

India’s deepwater record is not short of discoveries. KG-D6 and ONGC’s neighbouring KG-DWN-98/2 were both large finds. The trouble came after: complex reservoirs that produced well below plan, development that ran years late, and output that peaked early. ONGC’s block, approved at $5.07 billion of capital spending in 2018, began producing oil in January 2024 instead of 2021, and was reported in 2026 to be producing well under half of its cut-down oil target. The OALP record points the same way: 14 discoveries, one producing field.

Samudra Manthan addresses the first step well. Better seismic data and shared drilling costs should mean more and cheaper wells, and the common hubs could make small finds worth developing. But the scheme’s published targets are counted in wells drilled and reserves added. Neither guarantees production, and the deepwater-and-ultra-deepwater part of OALP Round X, the acreage the scheme is meant to help, had its bid deadline extended for a sixth time, to 15 November 2026.

What would fix this

• The Ministry of Petroleum and Natural Gas should publish the full component-wise outlay, including the unitemised Rs 350 crore and how the drilling line relates to the per-well cap.
• Each supported well should be reported on completion with its cost, the support paid and the result, so the cost-sharing can be judged well by well.
• The scheme should add a production milestone, such as discoveries reaching a development plan within a set number of years, alongside its targets for wells drilled and reserves added.
• DGH should publish the time from discovery to first production for every offshore discovery since 2000, so delays like KG-DWN-98/2’s can be compared.

These are proposals from this blog, not recommendations any agency has adopted.

What this piece could not establish

The Cabinet release and the PIB background note could not be opened directly; figures come from their text as indexed by search engines and from news reports, which disagree on the per-well cap (Rs 675 crore or Rs 650 crore) and in one case describe about 150 wells rather than 60. The current output of KG-DWN-98/2 differs between reports, and no audited cost overrun was found. KG-D6’s production history is described qualitatively because no consistent annual series was found. Converting gas to oil equivalent at one billion cubic metres per MMTOE follows DGH’s convention and is approximate. Dollar figures use one exchange rate and ignore cost escalation to 2031.

Sources and caveats

About this article: Researched, written and edited by Umashankar Triplicane Dwarakanathan, with AI research assistance; every figure is meant to trace to the primary source cited. See the Editorial Policy for how sourcing, AI use and corrections work.