The pattern in one line: refineries don't burn hydrogen — they react it with crude-oil fractions to strip out sulphur and stabilise heavier molecules, and India's 10 ppm BS-VI diesel standard makes that reaction non-negotiable. Almost all of that hydrogen today comes from steam methane reforming (SMR), a fossil-gas process. A handful of Indian refineries are now under contract to buy a small slice of their hydrogen as electrolysis-made green hydrogen instead — at roughly three times the price — and the arithmetic of what that costs per kilogram of hydrogen translates, transparently, into a real but currently small number of paise per litre of diesel.

Crude oil, as it comes out of the ground, carries sulphur, nitrogen, and aromatic compounds bound into its molecules. Before diesel can leave a refinery, those impurities have to come out — not by burning or filtering them away, but by chemically reacting them off with hydrogen gas, in a process called hydrotreating (the sulphur-specific version is called hydrodesulphurisation, or HDS). The diesel fraction is mixed with hydrogen, heated to roughly 290–430°C, and passed through a fixed-bed reactor operating at 7–180 bar over a cobalt-molybdenum or nickel-molybdenum catalyst. Inside that reactor, organic sulphur compounds are converted to hydrogen sulphide gas (H2S), which is then stripped out and typically converted into elemental sulphur or sulphuric acid as a saleable byproduct. The same reactor also saturates some of the aromatic ring compounds and removes nitrogen, both of which improve the diesel's combustion quality and stability.

This is why refineries need hydrogen at all: it isn't an additive to diesel, it's the reagent that does the cleaning, and it gets consumed (converted into H2S and other byproducts) rather than recovered. The tighter the sulphur specification a country sets, the more hydrogen has to be reacted per barrel to hit it — hydrogen consumption for the aromatic-saturation and deep-desulphurisation part of the reaction rises sharply as the target sulphur level falls, even though the more basic nitrogen- and metal-removal part of the reaction stays roughly constant regardless of how deep the sulphur cut goes.

India's Bharat Stage VI standard, equivalent to Euro 6, caps diesel sulphur at 10 parts per million — down from 50 ppm under the outgoing BS-IV standard — and took effect nationwide on 1 April 2020. Hitting 10 ppm instead of 50 ppm meant Indian refiners had to raise hydrotreating severity across the board, and state-run oil marketing companies spent roughly ₹35,000 crore upgrading their refineries, pipelines, and distribution networks to supply it — ₹17,000 crore of that by Indian Oil Corporation alone. That capital cost showed up at the pump: reporting at the time put the BS-VI-linked component of the April 2020 fuel price increase at roughly ₹1 per litre, separate from the state VAT changes that were layered on top of it in the same window.

Within the hydrotreating unit itself, hydrogen is not a minor input. An AIChE overview of hydrotreating economics puts typical unit operating costs at roughly $1.7 per barrel, of which producing and compressing the hydrogen accounts for 60–70 per cent — call it roughly $1.0–1.2 per barrel in hydrogen cost alone, before a single litre of that diesel has left the refinery gate. On the technical side, one refining-industry estimate puts the hydrogen actually reacted (as opposed to circulated as excess treat gas) at around 200 standard cubic feet per barrel for typical diesel hydrotreating — which converts, at standard conditions, to roughly half a kilogram of hydrogen consumed per barrel of diesel. That consumption figure is the one this piece uses for the cost estimate in Section 4.

Almost all of India's refinery hydrogen today is made on-site by steam methane reforming (SMR), the same process that supplies roughly 48 per cent of global hydrogen production and remains the cheapest industrial method available. SMR reacts natural gas with high-temperature steam (roughly 700–1,000°C) over a catalyst to produce a mixture of hydrogen and carbon monoxide, then runs a second water-gas-shift reaction to convert more of that carbon monoxide into additional hydrogen plus CO2. It is a mature, Technology-Readiness-Level-9 process running at 70–85 per cent efficiency, and it is what refining-industry sources mean when they describe hydrogen demand in "most Indian refineries" as "predominantly met through captive steam methane reforming units."

SMR's advantage is cost: a commonly cited global range puts SMR-produced ("grey") hydrogen at roughly $1.3–1.5 per kilogram. Its drawback is carbon intensity — producing one kilogram of hydrogen this way releases an estimated 9–12 kilograms of CO2, because the process both burns natural gas for process heat and converts more of it into CO2 as feedstock. That emissions profile, not the process economics, is the reason India's refining sector is now under policy pressure to source at least part of its hydrogen a different way.

The green bid price sits roughly 1.7 to 3.2 times above grey hydrogen depending which grey benchmark is used — global natural-gas SMR pricing at the low end, India's own higher domestic grey-hydrogen cost estimate at the high end.

Phase I of India's National Green Hydrogen Mission explicitly names refining, alongside non-urea fertiliser production, as a near-term priority sector for the switch from grey to green hydrogen. In practice, that has so far translated into four specific, competitively bid contracts under the SIGHT (Strategic Interventions for Green Hydrogen Transition) scheme's Mode-2B round: Indian Oil Corporation's Panipat refinery and Numaligarh Refineries' own facility were each awarded 10,000 tonnes per year of green hydrogen production, while Bharat Petroleum's Bina refinery and Hindustan Petroleum's Vizag refinery were each awarded 5,000 tonnes per year — 30,000 tonnes per annum (30 KTPA) in total. The price discovered through that competitive bidding, previously covered on this blog, was ₹397 per kilogram including GST for supply to Indian Oil's refineries — consistent with the roughly $4.11–4.21/kg SIGHT figures this piece uses in Figure 1.

That 30 KTPA award is a small first step against a much larger stated ambition: Indian refiners are reported to be planning roughly ₹2 trillion (about $23 billion) of green hydrogen investment over the coming years, with broader SIGHT tender rounds for the refining sector said to cover roughly 42,000 tonnes per year of production once fully allocated. Part of the motivation is regulatory rather than purely domestic: hydrogen is one of the product categories explicitly covered by the European Union's Carbon Border Adjustment Mechanism (CBAM), alongside steel, aluminium, cement, fertilisers, and electricity, and India's refiners are large exporters of diesel and other gasoil products into European markets — one 2025 trade forecast put India's gasoil exports, much of it winter-heating-season diesel bound largely for Europe, at 560,000–630,000 barrels a day. CBAM's initial phase does not yet directly tax refined fuel exports the way it taxes hydrogen itself, but the mechanism's existence, and the general direction of EU carbon policy, is part of why refiners with export exposure are moving early rather than waiting for a domestic mandate to force the issue.

The transition is not simply a matter of swapping one hydrogen source for another at the plant gate. An industry technical overview of refinery hydrogen systems notes that existing refinery infrastructure is "optimised around the predictable operating characteristics of reformers," prioritising stability and availability, while electrolysers introduce short-term output variability — tied to when renewable power is actually available — that refinery hydrogen systems were never designed to absorb. Integrating electrolyser-based supply into a brownfield refinery, the same overview notes, brings a distinct set of engineering, safety, and system-integration challenges layered on top of "legacy infrastructure, tightly integrated process units, [and] limited operating margins."

The Panipat award has since moved from paper to procurement. L&T Energy GreenTech is building the plant on a Build-Own-Operate basis, with green hydrogen to be supplied to IOCL at a fixed, competitively discovered price over a 25-year term; the facility is slated for commissioning by December 2027, and IOCL's own R&D leadership has confirmed the project remains on that schedule. The electrolysers themselves — high-pressure alkaline units — are being manufactured domestically at L&T's Hazira facility in Gujarat, and in mid-2026 Statcon Energiaa secured the order to supply the plant's 4 MW power-rectifier blocks, using IGBT chopper-based technology licensed from Germany's AEG Power Solutions and liquid-cooled for the low-ripple DC output electrolysers need when running on variable renewable power. Once operational, the 10 KTPA plant is reported to be India's largest green hydrogen facility built specifically for a refinery, and is explicitly framed as only the first step toward IOCL's own stated target of 350 KTPA of green hydrogen production by 2030 — itself more than eleven times the entire SIGHT Mode-2B refining-sector award covered above.

No refiner has published a rupees-per-litre figure for what its green hydrogen contracts add to diesel cost, so this section builds one from public inputs, shows its working, and flags every assumption. Start from Section 2's consumption figure: roughly 200 standard cubic feet of hydrogen reacted per barrel of BS-VI diesel, which converts (at standard temperature and pressure, 1 kilogram H2 ≈ 11.2 normal cubic metres) to about 0.51 kilograms of hydrogen per barrel. At the global SMR benchmark of $1.50/kg, that hydrogen costs roughly $0.76 per barrel; at India's own higher domestic grey-hydrogen estimate of ₹150–200/kg (roughly $1.8–2.4/kg), it costs $0.91–1.21 per barrel. Both figures are consistent with the independently sourced AIChE estimate in Section 2 that hydrogen production and compression account for $1.0–1.2 of a hydrotreating unit's roughly $1.7/barrel operating cost — a useful cross-check that the 0.51 kg/bbl consumption figure and the resulting cost estimate are in the right range.

Running the same 0.51 kg/bbl through the SIGHT competitive-bid price of $4.16/kg gives a green-hydrogen-equivalent cost of roughly $2.12 per barrel — and, converting at the roughly ₹94.3-per-dollar rate implied by the SIGHT bid's own rupee/dollar quote and dividing by 158.99 litres per barrel, that's approximately ₹1.25 per litre of diesel, against roughly ₹0.45–0.72 per litre for the grey-hydrogen equivalent. The incremental premium — what switching a barrel's hydrotreating hydrogen entirely from grey to green would add to that litre of diesel, at today's SIGHT bid price — works out to roughly ₹0.55–0.80 per litre. That is a strikingly similar order of magnitude to the real, already-absorbed ₹1-per-litre BS-VI desulphurisation price increase from Section 2, even though the two are mechanically different: BS-VI's cost was mostly one-off refinery capex being amortised into the price, while this is an ongoing per-kilogram feedstock premium.

This is a 100-per-cent-substitution scenario built to show the ceiling, not a forecast: it is not what any refiner is currently doing, and it should be read as illustrating scale, not predicting a price move.

The scenario above assumes every kilogram of hydrotreating hydrogen a refinery uses is green — which is far from where India actually is today. The 30 KTPA committed under SIGHT Mode-2B is small against total sector demand: the refining industry consumes an estimated 2.5 million tonnes per annum (MTPA) of grey hydrogen today, projected to grow toward roughly 4.5 MTPA by FY2030 as capacity additions proceed, per a 2024 industry analysis of India's hydrogen market. Thirty thousand tonnes is well under one per cent of that 2030 figure. At current, real-world blending ratios, the pump-price effect of the SIGHT contracts alone is not something a consumer could plausibly notice; the ₹0.55–0.80/litre range above is the scale of the eventual challenge if green hydrogen were to fully displace SMR across the sector, not a change happening at the pump this year.