Oil & Gas

This industry exists because, even after a century of alternatives, nothing else humanity has found packs as much usable energy into as small and easily transportable a space as crude oil and natural gas. A litre of petrol can push a two-tonne car for over ten kilometres; the equivalent in batteries, even today, weighs and costs dramatically more. That single fact, energy density per rupee and per kilogram, is why oil and gas still power the overwhelming majority of the world's transport, and why an entire industry exists purely to find it, move it and refine it.

The second reason is that crude oil is not just a fuel, it is a raw material. Naphtha from a refinery becomes the plastic in a water bottle; other fractions become fertiliser feedstock, synthetic fibres and thousands of everyday chemical products. Even a world that fully electrified its cars tomorrow would still need this industry for the petrochemicals it uniquely supplies.

Imagine everything that has to happen between geologists guessing there might be oil under a patch of seabed, and a two-wheeler owner filling up at a petrol pump in Nagpur. That entire chain, spanning a decade and hundreds of billions of rupees, is the oil and gas industry. It is conventionally split into three stretches of a river: upstream, where crude oil and natural gas are found and extracted; midstream, the pipelines, LNG terminals and storage that move it; and downstream, the refineries, petrochemical plants and retail network that turn it into fuel, cooking gas and thousands of everyday products.

India sits in an unusual position inside this global industry. It is the world's third largest consumer of oil, yet it produces only a small fraction of what it consumes, which makes energy security, not just energy business, the lens through which the government has approached this sector for decades.

Before any of the value chain can run, an explorer has to answer one question with real financial consequences: how much oil or gas is actually down there, and how confident are we? The industry answers this with a tiered classification system, most simply split into Proved, Probable and Possible reserves, often combined into 2P (Proved plus Probable) or 3P figures. Proved reserves are the volumes a company is reasonably certain, by international reporting standards, it can commercially recover under current economic and technical conditions. Probable and Possible reserves are progressively less certain estimates of what might additionally be recoverable.

This is not a bureaucratic technicality. A company's reported reserves are what banks lend against, what determines its reserve replacement ratio, and ultimately a large part of what investors are valuing when they price an upstream company's shares. Every OALP or DSF block win only becomes financially meaningful once exploration converts a geological guess into a properly classified, reported reserve figure.

It is easy to read "oil and gas" as one industry with one story, but gas behaves quite differently from oil at almost every level. Oil in India is overwhelmingly a transport fuel story; gas is a power, fertiliser feedstock, industrial heat and cooking fuel story, with transport (CNG) as just one user among several. And where India imports roughly 88% of the crude it consumes, domestic production still meets around half of India's gas demand, a meaningfully less import-dependent picture, though the gap is expected to widen as demand grows faster than domestic supply.

India is still a clear net importer of gas, not an exporter, importing the shortfall as LNG. In 2024, India imported roughly 36 billion cubic metres (bcm) of LNG, making it the world's 4th largest LNG importer, with the Middle East supplying about two-thirds of that. What is genuinely striking is how thin India's buffer is: total LNG storage capacity across the country is only around 1.9 bcm, a small cushion against a market where a single geopolitical disruption to a major supplier could bite quickly.

A natural follow-up question is whether residential and commercial gas are chemically different. They are not, in any meaningful sense; the same pipeline-quality natural gas reaches a home kitchen and a factory boiler. What genuinely differs is price and allocation priority, not molecular quality. Cheaper, government-administered APM gas is prioritised for CNG and domestic PNG under a 'no cut' policy, while industrial and commercial users typically pay market-linked or imported gas prices, which run considerably higher. That priority allocation has itself been tightening: APM gas's share of city gas distributors' total supply fell from roughly 51% to about 34% through 2024-25, pushing more of even the priority CNG and domestic PNG segment onto costlier gas.

Because India imports the large majority of the crude it refines, this is one of the few industries where a single global commodity price directly moves India's currency and trade balance, not just company earnings. In FY2025, India imported 234.3 million tonnes of crude oil at a total cost of roughly $137 billion, making crude oil consistently one of the single largest line items in India's entire import bill, well ahead of any other commodity.

The sensitivity is direct and quantifiable. A sustained $10 per barrel rise in the average crude price is estimated to add roughly $12-13 billion to India's net oil import bill over a year, widening the Current Account Deficit by about 0.3% of GDP on its own. India's full-year Current Account Deficit for FY2025 came in at $23.3 billion, or 0.6% of GDP, which puts that single $10 sensitivity in perspective: oil price moves alone can swing the CAD by an amount comparable to a meaningful share of its entire annual value.

One structural shift inside that import bill is worth flagging on its own. Russia's share of India's crude imports rose from just 1.7% in FY2020 to roughly 35.1% in FY2025, becoming India's single largest crude supplier over that period, largely on the back of discounted pricing after Western buyers pulled back post-2022.

Upstream companies earn on volume and reserves, essentially getting paid per barrel produced, so their fortunes move with global crude prices and how much they can pump, largely independent of how much of that barrel eventually becomes petrol versus diesel.

Downstream companies earn on the spread, the Gross Refining Margin, the gap between what a barrel of crude costs and what the finished products from that barrel sell for, a number that can stay healthy even when crude itself is expensive.

Midstream companies, pipeline and LNG terminal operators, generally earn a regulated tariff for moving product from one point to another, a steadier, lower-risk business than either end of the value chain.

It is tempting to describe this industry the way one might describe nuclear power, as a business where the cost is almost entirely upfront and running costs are an afterthought. That is only true for one half of it. Upstream genuinely fits that description: an exploration well can cost tens of millions of dollars to drill with a real chance of finding nothing commercially usable, and once a field is developed, the ongoing lifting cost of pumping each additional barrel is comparatively small next to that initial bet.

Downstream is close to the opposite. A refinery is certainly expensive to build, but that upfront cost is dwarfed, quarter after quarter, by the recurring cost of the crude oil it has to keep buying to run at all. Crude purchases routinely account for 80-90% of a refiner's total costs, which is exactly why Gross Refining Margin, the spread over that recurring input cost, matters so much more to a downstream investor than the refinery's original construction bill ever does.

So the honest summary is that this is a two-speed industry: an upstream half where the decisive cost is paid once, years before any oil flows, and a downstream half where the decisive cost is paid again every single day, in the form of the crude it never stops needing to buy.

Over the next five years, expect refining capacity to keep climbing toward the government's 310 MMTPA target for 2030, natural gas's share of the energy mix to keep rising toward the 15% goal, and OALP and DSF rounds to keep pushing into harder, more expensive geology like the Andaman basin as the easier blocks run out.

The new 2026 royalty framework is a direct bet that deepwater exploration, not shallow or onshore fields, is where India's next meaningful production growth has to come from, and its success will only be visible years from now given the multi-year lead time between a block award and first oil.