We had planned a different piece for this week.
But on Thursday, the Petroleum Minister stood up and announced something that, if it plays out the way the geology hints, could be one of the most important energy stories of the decade for India. The headlines covered it as a single news item. The actual ramifications stretch across multiple sectors, hundreds of listed companies, and at least 5 to 10 years of follow-on capex and infrastructure spending.
So we are setting aside this week’s regular Sunday Read to walk through it properly. Not as breaking news, but as the kind of analysis that actually tells you what to do with the information.
Pour the coffee. This one is detailed.
The Headline Event
On 5 June 2026, Union Petroleum and Natural Gas Minister Hardeep Singh Puri announced that state-run Oil India Ltd (OILINDIA) had established the presence of natural gas in the Sri Vijayapuram 3 exploratory well in the Andaman Sea. The well sits about 15 kilometres off the east coast of the Andaman Islands in a water depth of 355 metres.
To picture that depth: 355 metres is roughly the height of the Eiffel Tower laid sideways below the ocean surface. That is where the drilling is happening.
It is the second gas-bearing well in the same block. OILINDIA has now established the presence of hydrocarbons in two of the three exploratory wells drilled so far at Block AN-OSHP-2018/1, awarded under the Open Acreage Licensing Policy (OALP), after the first find at Vijayapuram 2 in September 2025.
The technical detail that matters: testing was carried out at a depth of over 1,900 metres in the Eocene formation, and natural gas was established through continuous flaring. After perforation, the well recorded a rapid pressure build-up and began producing, pointing to encouraging reservoir characteristics. OILINDIA is now running gas sampling to assess composition and calorific value, plus isotope studies to understand the gas’s origin. Two hits out of three wells drilled is a notably high strike rate for frontier deepwater exploration.
The One Caveat to Read Before Anything Else
This is a “presence of hydrocarbons” announcement. Not a confirmed, sized, commercially recoverable reserve.
A discovery is only the first step. The next phase involves appraisal drilling, reservoir studies, and commercial viability assessments. It can take several years (sometimes close to a decade) from discovery to commercial production.
Treat the numbers below as a spectrum: from hard facts (well depth, location) to the minister’s aspiration (the “several Guyanas” framing). We have labelled which is which throughout. All dollar-denominated source data has been converted at ₹94.93 to the US dollar.
Units at a Glance: Read This First
TCFTrillion Cubic Feet: a total volume of gas. 1 TCF ≈ 28.3 BCM. Think of it as a “how much is in the ground” number.
BCMBillion Cubic Metres: same idea, metric version. India consumes ~70 BCM of gas per year.
mmscmdMillion Metric Standard Cubic Metres per Day. A flow rate: how fast gas comes out of the ground each day. Like litres-per-minute, but for a gas pipeline.
MMSCMMillion Metric Standard Cubic Metres: a yearly volume total. Divide by 365 to get the daily flow rate (mmscmd). OILINDIA’s 3,252 MMSCM/yr ÷ 365 ≈ 8.9 mmscmd.
mmbtuMillion British Thermal Units: the energy content unit used to price gas globally. ₹759/mmbtu is India’s government-regulated gas price for domestic producers.
MMTMillion Metric Tonnes: used for crude oil (oil is measured by weight, gas by volume).
How Much Gas Has Actually Been Found?
No official volume has been put on the find yet. Composition and calorific value are still being assessed. What we have are regional analogues and political framing.
Before we get to the numbers, one quick frame so the units make sense. 1 TCF (trillion cubic feet) of gas is roughly half a year of India’s entire natural gas demand. Keep that yardstick in mind as you read.
Putting Andaman’s Potential in Perspective
1 TCF ≈ roughly 6 months of India’s entire natural gas demand
India annual gas demand (FY25 baseline)
~2 TCF / yr (70 BCM)
Full-year demand reference
Conservative Andaman estimate (1 TCF, unconfirmed)
~6 months of demand
Optimistic Andaman estimate (5 TCF, unconfirmed)
~2.5 years of demand
5 TCF (optimistic, not confirmed)
Regional belt analogue: Myanmar / Indonesia (proven)
20+ TCF combined
20+ TCF geological belt (proven)
Hover over each bar for context. TCF = Trillion Cubic Feet. 1 TCF ≈ 28.3 BCM. India FY25 demand ~70 BCM (~2 TCF/yr). Andaman recoverable volumes unconfirmed; no reserve has been published. Regional analogue data from IEA and public upstream operator disclosures.
To translate: a 1 to 5 TCF Indian find would equal anywhere from six months to two and a half years of India’s entire current natural gas consumption , all from one basin. The 20+ TCF already pulled from the wider belt across Indonesia and Myanmar adds up to roughly 10 years of India’s gas demand, sitting in geology that the Indian side has barely tested.
What It Could Mean for India’s Import Dependency
This is where the strategic stakes are clearest. The dependency numbers are solid.
India’s Gas Gap: Why Every Domestic Find Matters
FY25 domestic supply vs. national requirement
Gas: Domestic Production vs. Total Demand (FY25)
70 BCM needed
Domestic: ~34 BCM
Imports: ~36 BCM (51%)
034 BCM (49%)70 BCM (100%)
₹14.24L Cr
Total energy import bill (FY25)
~88%
Crude oil import dependency
5-10 yr
Realistic timeline before any import saving
Hover over segments and cards for context. BCM = Billion Cubic Metres. FY25 data from PPAC and MoPNG. Crude import dependency from MoPNG annual report.
To put ₹14.24 lakh crore in perspective: that is more than India’s entire defence allocation (₹7.85 lakh crore) plus the railway capital outlay (₹2.93 lakh crore) plus the entire road and highways budget (₹3.10 lakh crore) added together, and you would still have money left over.
India currently imports ~51% of its natural gas needs and ~88% of its crude oil. The gap between ~34 BCM of domestic gas production and ~70 BCM of demand is the hole a basin like Andaman could partly fill. A successful Andaman gas province could cut import dependence, improve energy security, reduce exposure to global price shocks, and pull in billions in upstream investment. One think tank scenario put the potential LNG import cost saving at 20 to 30%, but that assumes commercial-scale production that has not been confirmed.
The realistic read: even in an optimistic case, this dents gas import dependency gradually over 5 to 10 years. It does little for the ~88% crude dependency, which is a separate barrel entirely.
How Will They Get the Gas Out?
This is the real engineering and commercial story. The gas is roughly 1,200 km from the Indian mainland across deep water, and it has to reach India’s east coast gas spine. The Krishna Godavari basin / Kakinada hub in Andhra Pradesh already feeds GAIL’s national grid.
To picture 1,200 km: that is roughly the distance from Ahmedabad to Kolkata, or Delhi to Mumbai. Now imagine running a steel pipe across that entire stretch. Underwater. That is the engineering scale of the pipeline option.
There are two ways to do this, and the choice determines which companies get paid. No route, length, or contract has been sanctioned yet. Evacuation decisions come after appraisal confirms commercial volumes.
“The steel orders alone, in either scenario, represent a capex number that Indian pipe manufacturers have never seen from a single domestic project.”
Scenario A: Subsea Trunk Pipeline
Scenario A: Subsea Trunk Pipeline
Illustrative only. No route or contract has been sanctioned. Decisions follow appraisal confirmation of commercial volumes.
| Segment | Listed Beneficiaries | Why They Win |
| Large diameter line pipe | Welspun Corp, Jindal SAW, Man Industries, Ratnamani Metals | A 1,000+ km deepwater line needs LSAW/HSAW pipe with concrete weight coating. Welspun’s Anjar plant has supplied offshore work in Indonesia, Australia, Norway, and the UAE. Jindal SAW is India’s capacity leader in large-diameter SAW pipe. |
| Offshore EPC / pipe lay | Larsen & Toubro Energy Hydrocarbon | The only Indian listed player that fabricates and installs offshore platforms and subsea lines at scale. Foreign specialists (McDermott, Saipem, Subsea7) partner or compete. |
| Trunk transmission + grid | GAIL (India) | Would own and operate the line into the national grid. Its core toll-revenue business. |
| Coating / services | Welspun Corp, Ratnamani Metals | Anti-corrosion and concrete weight coating is a high-margin add-on to the pipe supply contract. |
📏 The Scale of the Pipe Order
A ~1,200 km deepwater trunkline would need roughly 3.5 to 11 lakh tonnes of coated steel pipe, depending on diameter. To make that real: 11 lakh tonnes of steel is roughly 15 times the weight of the Eiffel Tower, or enough steel to build about 4 modern aircraft carriers.
The benchmark is Nord Stream, the longest large-diameter subsea gas line ever built (Russia to Germany). 1,222 km, 48-inch diameter, 38 mm wall thickness, ~11 lakh tonnes of steel. Almost exactly the Andaman-to-mainland distance. A more typical 30” to 36” Andaman line would need ~5 to 7 lakh tonnes. At bare line pipe pricing of ~₹1.9 lakh per tonne, that is a ₹9,500 to ₹13,300 crore steel order for a typical line, up to ~₹21,000 crore for the largest 48” case, before coating.
Scenario B: Floating LNG, Shipped by Sea
The alternative to a pipeline is floating LNG (FLNG): liquefy the gas offshore and move it by ship. That avoids the enormous trunk line capex but adds liquefaction and shipping cost, and it needs somewhere on the mainland to land.
Scenario B: Floating LNG
Liquefaction offshore; LNG shipped by tanker to East Coast terminals. FLNG technology licensed from global players; Indian content in fabrication and downstream.
| Segment | Listed Beneficiaries | Why They Win |
| FLNG / liquefaction EPC | Larsen & Toubro (fabrication scope) | Liquefaction technology is mostly foreign licensed (Shell, Technip, Baker Hughes), but module fabrication and marine hook-up can land with L&T. |
| LNG shipping | GAIL (India), Shipping Corporation of India, Great Eastern Shipping | Carriers to move LNG from the field to the terminal. GAIL already charters LNG tonnage; SCI operates LNG carriers via JV. |
| Regas terminals (East Coast) | Indian Oil (Ennore), Adani group (Dhamra), Petronet LNG | The gas has to land on the East Coast. Ennore (IOC, near Chennai) and Dhamra (Adani, Odisha) are the natural receipt points for sea-borne Andaman gas. |
| Downstream marketing / CGD | GAIL, GSPL, IGL, MGL, Gujarat Gas, Adani Total Gas | More molecules in the grid means feedstock for city gas networks and industrial consumers. |
The honest fork: a pipeline is far cheaper per unit over a 20-year field life but carries huge up-front capex and stranding risk if reserves disappoint. FLNG is costlier per unit but modular and removable, better suited to an unproven frontier basin. For a first development of uncertain size, FLNG or early production is often the rational opening move, with a pipeline justified only once volumes are proven.
📌 Scenario-Agnostic Basket
A pipeline outcome is unambiguously bullish for the pipe trio (Welspun Corp, Jindal SAW, Man Industries). An LNG outcome shifts that upside to shipping and the East Coast terminals (SCI, Great Eastern, IOC, Adani). But OILINDIA (operator), ONGC (significant Andaman acreage), GAIL (infrastructure owner), and L&T win either way. They are the names that benefit regardless of how the gas moves.
What It Could Do to Oil India’s Revenue
First, the Baseline You Are Measuring Against
Before running any scenario, establish the yardstick, because the numbers are frequently misquoted in social media commentary on this story.
Oil India Baseline (Latest Available)
Gas production at a historic high for OILINDIA. The relevant comparison is mmscmd (daily flow rate), not the headline revenue.
| Metric | Figure |
| Revenue (FY26) | ₹33,946 crore |
| Net profit (FY26) | ₹7,551 crore |
| Crude production (FY25) | 3.458 MMT |
| Gas production (FY25) | 3,252 MMSCM (~8.9 mmscmd), Highest ever |
| 2P reserves (FY25) | 53.733 BCM |
| Market capitalisation | ~₹78,600 crore |
Hold on to one number: OILINDIA’s entire gas business today is ~9 mmscmd. To make that tangible, that is roughly enough natural gas to power 50 to 60 million Indian homes every day. That is the yardstick. Any Andaman volume should be read against that, not against the ₹33,946 crore top line, much of which is the Numaligarh refinery business.
The Analogs: What Happened When Others Struck Frontier Hydrocarbons
1. KG-D6 (Reliance Industries / BP). Discovery in 2002, first gas in April 2009 (a seven-year lag). And KG-D6 was on the East Coast mainland shelf, far simpler logistically than a remote island location. Peak output at ~80 mmscmd made Reliance India’s largest gas producer overnight. The subsequent decline (to ~6 mmscmd by 2013) taught India that frontier gas basins can disappoint as sharply as they impress. The recovery programme took another decade.
2. Cairn India / Rajasthan Mangala. The “one find transforms the company” archetype. Discovered in 2004, first oil in August 2009 (a ~5-year lag). Peak output is close to 25% of India’s oil production. In its first year, it saved roughly ₹5,000 crore in forex, equivalent to the entire annual budget of a state like Goa. Cairn held a 70% working interest, ONGC 30%. This is the template for what a single basin does to a producer. It built Cairn’s entire valuation.
3. Guyana / ExxonMobil and Hess. The minister’s own benchmark. Guyana drilled 46 dry wells before striking on the 47th. The find lifted its economy from roughly ₹38,000 crore toward a projected ~₹1.9 lakh crore. Relevant as a “frontier basin can be nation-changing” data point, but it is a country transformation, and the company-level winner was a foreign major.
The common thread: a 5 to 7 year gap from discovery to first production, and revenue that arrives as a steep ramp, not a step. A 2031-2035 first-revenue window is the realistic planning assumption for Andaman, not a pessimistic one.
The OILINDIA Ballpark: Illustrative Scenarios
No recoverable reserve has been published, so this is a sensitivity, not a forecast. Assumptions stated openly: gas price ~₹759 per mmbtu (the energy unit used to price gas, equivalent to roughly the heat in 1,000 litres of gas burned), recoverable volume produced over a ~15-year average field life, and 1 TCF ≈ 28.3 BCM. At those inputs, 1 mmscmd of sustained output ≈ ~₹1,000 crore of annual gross revenue.
Illustrative Revenue Scenarios: If Andaman Delivers
Subject to PSC cost recovery, evacuation tariffs, and OILINDIA working interest (may shrink if farm-in partners are added).
| Recoverable Gas | Avg. Plateau Output | Annual Gross Revenue | vs OILINDIA’s ~9 mmscmd Gas Base | As % of FY26 Revenue |
| 1 TCF | ~5.2 mmscmd | ~₹5,200 cr/yr | +~58% to gas volumes | ~15% |
| 3 TCF | ~15.5 mmscmd | ~₹15,500 cr/yr | ~2.7x gas volumes | ~46% |
| 5 TCF | ~26 mmscmd | ~₹26,000 cr/yr | ~3.9x gas volumes | ~77% |
What these numbers actually mean against OILINDIA’s current gas base:
Right now, OILINDIA pumps out roughly 9 mmscmd of gas every single day from all its existing fields in Assam, Rajasthan, and offshore areas combined. That entire operation (decades of drilling, thousands of wells, hundreds of kilometres of pipelines) produces 9 mmscmd. That is the baseline.
Even the modest 1 TCF case adds 5.2 mmscmd on top of that: a 58% expansion of OILINDIA’s entire gas business from a single new field. Not 5%, not 10%. More than half again on top of everything they already have.
The 3 TCF case adds 15.5 mmscmd: that is 172% more than the current base, meaning OILINDIA’s gas volumes would nearly triple. At that point, gas stops being a secondary business alongside crude oil and becomes the dominant revenue driver. The company’s identity changes.
The 5 TCF case adds 26 mmscmd, almost four times the current gas base. OILINDIA would no longer be primarily an oil company that also produces some gas. It would be one of India’s largest gas producers, full stop. To translate into something tangible: the 1 TCF case adds enough daily gas output to light up roughly 30 million additional Indian homes. The 5 TCF case adds enough to power 150 to 170 million additional homes, more than the entire population of Russia, from a single asset that does not yet exist on any production map.
Three Haircuts Before Getting Carried Away
Those revenue scenarios are gross at the wellhead. Three mathematical realities trim them significantly before they reach OILINDIA’s bank account.
Haircut One: The Cost of Getting Gas from the Middle of the Ocean to a Customer
Andaman is not a convenient onshore field in Assam with existing pipelines and processing infrastructure built over sixty years. It is approximately 1,200 kilometres offshore in deep water, meaning the gas reservoir sits beneath a kilometre or more of ocean before you even reach the seabed, and then the seabed itself is 1,200 kilometres from the nearest landmass with a meaningful gas market.
That gas cannot sell itself. It needs to travel. And travel in the energy business is extraordinarily expensive.
Haircut One: What Evacuation Does to Gross Revenue (3 TCF Case)
The journey from wellhead revenue to EBITDA arriving at OILINDIA’s books
Gross wellhead revenue (3 TCF, ~₹759/mmbtu)
₹15,500 Cr / yr
Less: transportation tariff + royalties + field operating costs
−₹11,000 Cr / yr (~71%)
Evacuation + opex (~₹285-475/mmbtu range)
= Field EBITDA reaching OILINDIA’s books
₹4,500 Cr / yr (~29%)
Illustrative for the 3 TCF scenario. Transportation estimate based on comparable deepwater pipelines and FLNG liquefaction/shipping costs. Actual costs depend on route and contractual terms, neither of which is sanctioned.
Haircut Two: OILINDIA Probably Will Not Own All of It
The revenue table assumes OILINDIA retains 100% of the economic interest in the discovery and therefore receives 100% of the revenue and profit. This assumption is almost certainly wrong.
Deepwater frontier appraisal is expensive. Each appraisal well can cost US$ 80-120 million (₹760-1,140 crore). To manage that capital burden and bring in technical expertise, OILINDIA will almost certainly need to farm out a portion of the block to a deepwater specialist. That means sharing both the cost and the upside.
Haircut Two: The Working Interest Reality
Farm-outs are standard practice in deepwater frontier blocks; every percentage point given up reduces OILINDIA’s revenue proportionally
Current (assumed)
100%
OILINDIA working interest
₹4,500 Cr EBITDA
More likely (65% farm-out example)
65%
OILINDIA retains after farm-out
₹2,925 Cr OILINDIA share
A 50% farm-out would halve every number in the revenue table. A 35% farm-out (retaining 65%) reduces EBITDA from ₹4,500 Cr to ₹2,925 Cr. The deepwater experience of the farm-in partner lowers technical risk but exits proportional revenue. That trade-off is almost always worth it at the appraisal stage.
Working interest scenario is illustrative. OILINDIA has not announced any farm-out. Actual terms depend on commercial negotiations that have not commenced.
Haircut Three: The Money Arrives Much Later Than You Think
This is the most mathematically ruthless of the three haircuts because it is not a negotiation or an estimation. It is arithmetic applied to time.
Using the KG-D6 and Cairn Mangala templates, first revenue is 2031 at the earliest and 2035 as a more realistic central estimate. That is 5 to 9 years from today. Now apply the time value of money, the foundation of every valuation. A rupee received seven years from now is worth less than a rupee today because you could have invested that rupee today and earned a return on it. For an Indian upstream oil and gas project carrying exploration risk, political risk, execution risk, and commodity price risk, a discount rate of 12% per year is conservative rather than aggressive.
Haircut Three: What Waiting 7-9 Years Does to Value
At 12% discount rate, more than half the value evaporates simply due to the passage of time
Today (reference)
₹100
Present value = ₹100
2033 (7 years out)
₹45
₹100 ÷ (1.12)7 = ₹45.23 today
2035 (9 years out)
₹36
₹100 ÷ (1.12)9 = ₹36.06 today
So more than half the value evaporates simply due to the passage of time before the first rupee of revenue arrives, before a single other adjustment is made.
Discount rate of 12% is used as a conservative estimate for an Indian upstream frontier project carrying exploration, execution, and commodity price risk. First revenue window: 2031 (earliest) to 2035 (central estimate).
What All Three Haircuts Look Like Together
Applying all three haircuts to the 3 TCF scenario in sequence, here is what the math looks like from gross revenue to a realistic present value for OILINDIA’s share:
Combined Haircuts: 3 TCF Scenario Walkthrough
Each step is a sequential reduction. The final number is what OILINDIA’s share of the discovery is realistically worth in present-value terms today.
| Step | Item | Amount |
| Start | 3 TCF gross annual revenue | ₹15,500 Crore |
| Haircut 1 | After transportation costs, royalties, and field operating costs | ₹4,500 Crore EBITDA |
| Haircut 2 | After 65% working interest (farming out to deepwater partner) | ₹2,925 Crore OILINDIA share |
| Haircut 3a | Capitalised at 12% discount rate (₹2,925 ÷ 0.12) | ₹24,375 Crore perpetuity value |
| Haircut 3b | Discounted back 8 years at 12% (₹24,375 ÷ 2.476) | ₹9,845 Crore present value today |
That ₹9,845 crore is a real number. It is not pessimistic. It is what a disciplined investor should be willing to pay today for OILINDIA’s probable share of a 3 TCF Andaman discovery, assuming reasonable evacuation costs, a 35% farm-out, and an 8-year wait for first revenue. Compare it to OILINDIA’s current market cap of ~₹78,600 crore, and you can judge for yourself how much Andaman optionality the market is already pricing in.
The Strategic and Political Layer
Beyond the barrels, the discovery carries geopolitical weight. The Andaman and Nicobar Islands sit near the Strait of Malacca, one of the world’s busiest trade and energy corridors, through which approximately 80% of India’s crude oil imports transit by tanker. A producing energy province there strengthens India’s presence in the eastern Indian Ocean.
It is also contested. The find is being folded into the larger Great Nicobar mega-project, where the Congress party has raised concerns about the rights of the Shompen and Nicobari tribes. Any large-scale industrial activity in the Andaman and Nicobar Islands requires navigating the Andaman and Nicobar Islands Protection of Aboriginal Tribes Regulation. Regulatory timelines in sensitive ecology zones have historically been longer than in mainland frontier blocks. That debate will shadow any large-scale development here.
The Bottom Line
Three things are true at once.
The geology is improving fast. Two of three wells hitting hydrocarbons in a frontier basin is a real de-risking event. The Eocene formation is a proven gas-bearing interval across the region. The science is encouraging.
Nothing is commercial yet. No sized reserve, no calorific data, no evacuation route, and a 5-to-10 year runway to first gas, even in a good case. The “₹1,899 lakh crore economy” and “several Guyanas” lines from the minister’s statement are ambitious aspirations, not balance sheet items.
The trade, if you want one, is optionality. OILINDIA (operator), ONGC (acreage), and GAIL (infrastructure) rate on positive newsflow, with the pipe trio or the LNG shipping and terminal names layered on depending on which evacuation route firms up.
“Size it for a multi-year, headline-driven story. Not a 2026 earnings event.”
Want to think through how this fits your portfolio?
If you are wondering how a story like this fits in, whether you should be holding the operators, the infrastructure beneficiaries, or both, that is a conversation worth having. Getting position sizing right on long-duration optionality stories is the real work.
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Disclaimer: This article is for informational and educational purposes only and does not constitute investment advice, a recommendation, or a solicitation to buy or sell any securities. All data and scenarios are illustrative. Readers should conduct their own due diligence or consult a registered financial adviser before making any investment decision. Past performance and analogous cases are not a guarantee of future results.