Introduction
The contemporary account of India’s oil and gas industry begins with an explicit caveat: the source material (dated August 2025) incorporates text from a large language model and may contain hallucinated details or unverified references, so assertions and citations should be critically assessed and any copyright or unverifiable claims removed before reuse.
Commercial petroleum activity in India dates to the late nineteenth century, with the first commercial oil discoveries at Digboi, Assam (1889). The natural gas sector developed later, from major field discoveries in the 1960s in Assam and offshore Maharashtra (notably the Mumbai High complex). These historical foundations underpin a sector that remains heavily import-dependent despite decades of domestic activity.
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Reserve estimates have shown modest change over recent years: as of 31 March 2018, India’s proved crude oil reserves were about 594.49 million tonnes and natural gas reserves about 1,339.57 billion cubic metres; by 31 March 2024 proved crude reserves were estimated at roughly 569.77 million tonnes and natural gas at about 1,246.49 billion cubic metres. Persistent import dependence has been a defining feature of India’s hydrocarbon economy—historically about 82% of crude requirements were imported and, in 2019, total oil and product imports amounted to some 205.3 million tonnes, making India one of the world’s largest net importers.
Policy goals set earlier in the decade aimed to reduce crude import dependence (a target of 67% by 2022) through intensified exploration, expansion of renewables, and greater use of indigenous ethanol. In practice import reliance has risen in recent years: the 2024–25 fiscal year recorded a record import share of 88.2% (up from 87.8% the prior year), underscoring the challenge of substituting imports with domestic supply.
Domestic production trends have been uneven. In fiscal year 2020–21 crude output fell by about 5.2% to approximately 30.49 million tonnes, and natural gas production declined by about 8.1% to roughly 28.67 billion cubic metres. Shorter-term movements within 2021 illustrate divergent trajectories: for example, August 2021 saw crude production decline by about 2.3% while domestically produced natural gas rose by some 20.2%.
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Two structural constraints limit India’s ability to close the supply gap. First, economic incentives and price signals for domestic gas and oil development remain imperfect; reported market price levels and the global variation in exploration and production costs affect project viability. Second, technical recovery factors constrain output: current oil recovery factors in many Indian fields are typically only 30–35%, whereas application of advanced recovery technologies can substantially raise ultimate recovery—potentially on the order of doubling yields in suitable reservoirs. Together, these economic and technological limitations highlight the scope for policy, fiscal and technological interventions to improve domestic production, while underlining the need to treat reported figures with scrutiny given the source caveats.
History
The origins of India’s petroleum industry lie in the late 19th century when oil was first identified near Digboi in Assam (1889), initiating commercial extraction and establishing the northeastern region as the cradle of the country’s oil activity. Over the following decades the industry remained regionally concentrated and gradually developed in scale and infrastructure.
Commercial exploitation of natural gas emerged much later, with significant gas discoveries in the 1960s in both Assam and Gujarat that introduced geographically distinct gas resources into the national energy mix. The strategic importance of gas grew further in the 1970s after the Oil and Natural Gas Corporation (ONGC) located substantial reserves in the South Basin fields; these finds materially expanded commercially recoverable gas supplies and reinforced natural gas as a central component of India’s energy system.
Reserves
As of 31 March 2024 India’s proven crude-oil endowment was estimated at 569.77 million tonnes, a figure reported as lower than in the previous year, indicating a year‑on‑year reduction in proven crude reserves. Crude resources are highly concentrated geographically: the Western Offshore contains 39.0% of the national crude inventory (≈222.21 Mt) and the Assam onshore province holds 26.3% (≈149.85 Mt). Together these two provinces account for approximately 65.3% of India’s crude-oil reserves, reflecting a heavy reliance on a limited number of producing basins.
On the gas side, total proven natural‑gas reserves were estimated at 1,246.49 billion cubic metres (BCM) on the same reference date. Gas reserves are predominantly offshore: the Eastern Offshore comprises 39.5% of the national gas resource (≈492.36 BCM) while the Western Offshore contains 23.1% (≈287.89 BCM). These two offshore sectors together represent about 62.6% of India’s gas reserves, underscoring the dominant role of offshore basins in the country’s gas supply.
The spatial pattern of hydrocarbons has clear sectoral and policy implications. The Western Offshore functions as a strategic dual‑purpose basin with leading shares in both crude and gas, Assam remains the principal onshore crude province, and the Eastern Offshore is the single largest gas province. This concentration shapes priorities for exploration, dictates investment in offshore platforms and regional pipeline networks, and influences regional energy‑security planning and logistical arrangements for processing and transport.
The dataset (status as on 1 April 2024) records India’s conventionally assessed crude oil reserves at 671.40 million tonnes and natural gas reserves at 1,094.19 billion cubic metres (bcm), with crude reported in million tonnes and gas in bcm. Reserve distribution is presented by State/UT/region, distinguishing onshore provinces, offshore basins (Western and Eastern Offshore) and coal‑bed methane (CBM) categories; values are shown to two decimal places with percentage shares of the national totals.
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Offshore basins are the principal holders of India’s gas inventory and together dominate national gas capacity. The Western Offshore is the single largest repository of both hydrocarbons, containing 213.26 Mt of crude (31.76% of national crude) and 342.29 bcm of gas (31.31% of national gas). The Eastern Offshore has a pronounced gas focus, with 263.34 bcm (24.07%) but only 40.67 Mt of crude (6.06%), underscoring its importance as a gas province rather than a major crude source.
Among onshore provinces, Assam is the foremost dual hydrocarbon province, holding 145.41 Mt of crude (21.66%) and 165.68 bcm of gas (15.16%). Rajasthan (131.50 Mt, 19.60%) and Gujarat (118.86 Mt, 17.70%) are the next largest crude holders but have considerably smaller gas shares (Rajasthan 63.96 bcm, 5.85%; Gujarat 56.60 bcm, 5.18%). Other onshore crude contributors include Andhra Pradesh (11.11 Mt, 1.66%), Tamil Nadu (8.54 Mt, 1.27%), Arunachal Pradesh (2.88 Mt, 0.43%), Nagaland (2.38 Mt, 0.35%) and Tripura (0.07 Mt, 0.01%); West Bengal and several CBM‑only regions report zero conventional crude.
Natural gas holdings beyond the two offshore basins are concentrated in Assam (165.68 bcm, 15.16%), with smaller but notable volumes in Rajasthan, Andhra Pradesh (59.27 bcm, 5.42%), Gujarat and Tamil Nadu. CBM is treated separately and, although it contributes no conventional crude, it supplies measurable gas volumes: Jharkhand (CBM) 11.53 bcm (1.05%), Madhya Pradesh (CBM) 3.34 bcm (0.31%) and West Bengal (CBM) 0.73 bcm (0.07%). Tripura exemplifies a region with negligible crude yet a significant gas endowment (0.07 Mt crude, 28.93 bcm gas), whereas Nagaland shows small crude and minimal gas (2.38 Mt; 0.09 bcm). West Bengal (conventional) is recorded with no conventional crude or gas.
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The spatial pattern indicates a dichotomy between crude‑rich onshore provinces (notably Rajasthan, Gujarat and Assam) and offshore basins that underpin the country’s gas supply. This distribution has implications for exploration priorities, infrastructure siting and regional energy planning, with offshore development critical to national gas availability and onshore basins remaining central for crude production.
Crude oil reserves (1 April 2024)
As of 1 April 2024 India’s proven crude oil reserves stood at 671.40 million tonnes, a net increase of 1.93 million tonnes (≈0.29%) from the same date in 2023. Regionally, the Western Offshore area constitutes the largest share, holding roughly 32% of the national total (≈214.85 million tonnes), while onshore Assam accounts for about 22% (≈147.71 million tonnes) and Gujarat for about 18% (≈120.85 million tonnes). The remaining 28% (≈187.99 million tonnes) is dispersed among other producing states, notably Rajasthan, Tamil Nadu, Arunachal Pradesh, Nagaland and Tripura. Overall, the spatial pattern reflects a dual emphasis in India’s resource base: a major offshore concentration in the western margin complemented by significant onshore reserves in northeastern and western/northwestern basins, with smaller contributions from southern onshore fields.
As of 1 April 2024, India’s proven natural gas endowment is estimated at 1,094.19 billion cubic metres (BCM). This national resource base is unevenly distributed, with a pronounced offshore concentration and a network of onshore basins and coal‑bed methane (CBM) provinces that together determine regional development priorities.
The largest single concentration occurs in the Western Offshore (Arabian Sea) province, which contains 338.20 BCM (31.0% of the national total). The Eastern Offshore (Bay of Bengal) basin is the second major offshore province with 262.60 BCM (24.0%). Collectively, these two offshore provinces account for 55.0% of India’s gas reserves, underscoring the predominance of marine basins in the country’s gas inventory.
Onshore resources are dominated by the northeastern sedimentary basins and several inland basins. Assam’s onshore fields (extending into parts of Arunachal Pradesh) hold 164.13 BCM (15.0%), while Gujarat’s Cambay and associated basins contribute 54.71 BCM (5.0%). Rajasthan’s onshore fields and the Cauvery province adjacent to Tamil Nadu and Puducherry each supply about 32.83 BCM (3.0% each). The Assam–Arakan Basin in Tripura accounts for 27.36 BCM (2.5%).
Coal‑bed methane represents a distinct component of the reserve structure: Madhya Pradesh and Jharkhand are each attributed 21.88 BCM (2.0% each), and West Bengal holds 16.41 BCM (1.5%). A residual “Others” category—comprising numerous smaller and dispersed fields across states—aggregates to 221.36 BCM (20.0%). Together, these regional and typological components sum to the reported national total and reflect a resource landscape in which offshore havens coexist with important onshore and unconventional gas provinces.
Strategic petroleum reserves
For an oil‑importing country such as India, holding emergency crude stocks is a core element of energy security and of negotiating leverage in global markets that can see sharp price spikes when supply fails to meet demand. Strategic reserves may be housed in underground caverns, conventional above‑ground tanks, or maintained as producible in situ fields—fully developed oilfields kept ready for rapid exploitation—which provide differing trade‑offs in cost, response time and permanence.
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India’s formal Strategic Petroleum Reserve (SPR), managed by Indian Strategic Petroleum Reserves Limited (ISPRL), currently comprises 5 million tonnes (≈31.5 million barrels; 5.0 million m3) of crude, roughly equivalent to ten days of national consumption. Phase I SPR facilities are sited at underground storage caverns in Mangalore, Visakhapatnam and Padur (Udupi district, Karnataka), locations chosen to afford prompt access to major refining centres on both the east and west coasts and thereby facilitate rapid coastal distribution in an emergency. Under Phase II, additional capacity—located at Chandikhol (Odisha) and through further development at Padur—will add the equivalent of 12 days’ consumption, bringing the cumulative SPR coverage to 22 days once complete.
When commercial refinery crude inventories (currently estimated at about 65 days of crude) are combined with the SPR total (22 days when both phases are commissioned), India’s aggregate crude storage reaches approximately 87 days, approaching the International Energy Agency’s 90‑day benchmark for member countries; this aggregate excludes separate stocks of refined petroleum products held by marketing companies and large consumers. To augment security cost‑effectively and to diversify options, India is also considering holding strategic crude in foreign storage facilities and using the low‑cost strategy of reserving producible fields that can be cycled into production when global prices exceed predefined thresholds.
Production
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Over the past decade India’s upstream output has shown divergent trajectories for oil and gas. Domestic crude petroleum production contracted at a compound annual growth rate (CAGR) of −1.9% between 2013–14 and 2023–24, although 2023–24 recorded a small recovery with output rising 2.3% year‑on‑year to 29.88 million tonnes (Mt). Natural gas production followed a modest upward trend, posting a 0.4% CAGR over the same period and reaching 35.18 billion cubic metres (BCM) in 2023–24, up 3.8% from 2022–23.
Refining and product availability have expanded despite weakening crude volumes. Total petroleum products production in 2023–24 amounted to 257.25 Mt, a 3.2% increase on the previous year and a decade‑long CAGR of 2.0%. The product slate remains dominated by transport fuels, with high‑speed diesel (HSD) constituting roughly 40% and motor gasoline about 15% of production.
Recent upstream developments and regional shifts underpin the modest improvements in hydrocarbon output. ONGC’s development of the KG‑DWN‑98/2 block in the Krishna‑Godavari basin involves capital expenditure of approximately US$5.07 billion (≈₹340 billion) and is associated with projected recoveries on the order of 25 Mt of oil and 45 BCM of gas. Onshore fields in Rajasthan have emerged as important oil producers, while commercial gas production from Krishna‑Godavari fields by Reliance BP has contributed to strengthening indigenous gas supplies.
Policy measures also aim to diversify domestic fuel supply and lower import dependence. A national target to produce 15 Mt/year of compressed biogas (CBG) is intended to substitute for compressed natural gas (CNG)—currently largely supplied by imported liquefied natural gas (LNG)—thereby enhancing energy security and reducing net emissions.
As of 31 March 2024 India’s refining sector comprised 23 crude oil refineries—18 state‑owned, three private and two joint ventures—with an installed capacity of 256.8 Mt/yr, up from 248.9 Mt in 2020–21 and ranking the country as Asia’s second‑largest refiner after China. In the 2023–24 refining year Indian refineries processed 256.1 Mt of crude, implying an aggregate capacity utilisation of about 99.7%. The sector is led by Indian Oil Corporation (IOC), whose installed capacity is approximately 80.55 Mt/yr and whose crude throughput in 2023–24 was about 77.6 Mt; other major players include BPCL (≈35.3 Mt/yr) and HPCL (≈20.6 Mt/yr).
India is a significant net exporter of refined products, recording net exports in excess of 62 Mt in 2023–24. The export slate is dominated by middle distillates—diesel, naphtha and aviation turbine fuel (ATF)—reflecting both domestic surplus refining throughput and deep integration with international product markets. Many Indian refineries are configured to maximise distillate yields by processing heavier, higher‑sulphur residual oils through vacuum distillation and coking units; this upgrading pathway increases production of light transport fuels while generating petroleum coke (petcoke), a high‑calorific but high‑sulphur solid by‑product.
The international regulatory change embodied in the IMO/MARPOL 2020 sulphur cap (0.50% m/m globally; 0.10% in designated Emission Control Areas) markedly reduced demand for high‑sulphur fuel oil (HSFO). Prior to 2020 the maritime sector consumed nearly 38% of global residual fuel oil, so the sulphur caps materially contracted that end‑use market, depressed HSFO prices and reallocated demand pressures within refining and alternative‑fuel pathways. Well‑equipped refineries, including several in India, were able to economically reprocess HSFO into lighter, compliant fuels and to produce petcoke; in contrast, jurisdictions that restricted direct combustion of high‑sulphur residuals accelerated technological adaptation or market exit for those fuel streams.
In response to regulatory signals and changing market economics, a number of Indian refiners have invested in residue‑conversion technologies. Gasification and methanation processes are being used to convert high‑sulphur residual oils and petcoke into synthetic natural gas (SNG) and methanol, thereby creating higher‑value, lower‑emission products from refinery residues and supporting downstream petrochemical integration. Large downstream projects—exemplified by Reliance’s gasification initiatives at Jamnagar—illustrate strategic moves toward residue conversion and product diversification.
Demand shocks such as the COVID‑19 pandemic temporarily depressed refinery throughput, particularly for ATF and petrol, reducing utilisation during the crisis; subsequent recovery of transport and industrial demand contributed to the near‑full utilisation observed in 2023–24. Domestically, industries such as cement continue to be significant consumers of petcoke, sustaining demand for that residue in India even as some developed markets restrict its direct combustion. The combined effect of strong export demand, advanced conversion capacity and targeted residue‑processing investments characterises India’s contemporary refining landscape.
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Consumption
India is a major global petroleum consumer, ranking third after the United States and China. Petroleum-product demand is diversified across transport and household fuels: high‑speed diesel accounts for the largest share (≈37%), followed by petrol (≈16%), liquefied petroleum gas (LPG) (≈15%), petroleum coke (≈7%) and naphtha (≈6%). Urban household dependence on LPG for cooking—illustrated by routine cylinder deliveries in cities such as Hyderabad—underscores LPG’s role within the national energy mix.
Aggregate crude‑oil consumption increased from 204.12 Mt in 2011–12 to 221.77 Mt in 2020–21, equivalent to an annualized growth rate of about 0.93% over that period. However, the pandemic induced a pronounced short‑term shock: crude consumption in 2020–21 fell by roughly 12.8% relative to 2019–20. Natural‑gas use exhibited more modest variation, with estimated consumption of 60.64 BCM in 2020–21—a year‑on‑year decline of about 0.67%.
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Following the pandemic downturn, consumption rebounded: crude‑oil use rose to an estimated 233.3 Mt in 2023–24 (up ≈5.4% year‑on‑year), while natural gas recovered to around 64.1 BCM. Natural‑gas consumption is concentrated in a few sectors, notably fertilizers (≈28%), power generation (≈18%) and transportation (≈15%); overall, roughly 60% of gas is used for energy services and about one‑third (≈33%) for non‑energy industrial applications.
Electricity generation
Crude oil and natural gas occupy only a marginal position in India’s power-generation hierarchy, overshadowed by coal, large‑scale hydropower and the rapidly expanding shares of solar and wind. By 31 March 2024 gas‑fired plants accounted for 24,665 MW of installed capacity — roughly 5.7% of the national total — yet many of these facilities operate well below their technical potential because of limited domestic gas availability. Thus, although the power sector remains one of the larger consumers of natural gas, the sectoral share of gas has been eroded over time as renewables have grown and coal continues to be widely deployed, shifting the overall fuel mix away from gaseous hydrocarbons.
Liquid fuels make a negligible contribution to utility‑scale grid supply: diesel‑based generation in the utility sector amounted to only 510 MW in March 2024 (under 0.1% of installed capacity). At the same time, diesel plays a prominent role outside the grid: an estimated 90,000 MW of diesel generator (DG) capacity above 100 kVA is installed for backup purposes, an aggregate comparable to roughly one‑third of the country’s utility‑scale capacity. Countless additional sub‑100 kVA sets serve residential, commercial, agricultural and telecom users, reflecting widespread, decentralized dependence on small‑scale diesel generation for reliability. Together these patterns underscore the limited role of oil and gas in centralised generation alongside their substantial importance for distributed and emergency power provision.
India’s energy trade is characterized by a pronounced dependence on foreign hydrocarbons: it is the world’s second‑largest crude importer after China, reflecting substantial reliance on overseas supplies to meet domestic demand. Net crude imports climbed from 171.73 Mt in 2011–12 to 226.95 Mt in 2020–21 and about 232.5 Mt in 2022–23, exposing the economy to international price and supply fluctuations. Natural gas imports, largely in the form of LNG, rose from 18 BCM in 2011–12 to 32.86 BCM in 2020–21 and to 35.5 BCM in 2022–23, registering a compound annual growth rate of roughly 9.4% over the decade and signalling rapid growth in gas consumption and LNG infrastructure.
Despite upstream scarcity, India has built substantial refining capacity and is a net exporter of refined petroleum products: exports increased from 38.94 Mt in 2008–09 to 56.76 Mt in 2020–21 and were about 62 Mt in 2022–23. This contrast—high import dependence for feedstocks alongside strong downstream processing and product trade—illustrates a spatial and functional divergence between resource endowments and industrial capability. In 2022–23 import dependence was estimated at 87.3% for crude oil and 47.3% for natural gas, quantifying vulnerability to external disruption and underscoring the limited size of domestic reserves.
These trade patterns carry strategic consequences: elevated import dependence shapes foreign policy choices, constrains maritime logistics (terminal siting and exposure to chokepoints), and motivates investment in strategic petroleum stocks and diversified supply lines. Policy responses combine diversification of crude sources with accelerated deployment of renewables (solar, wind, hydro, biomass) to both lower exposure to concentrated import networks and reduce the local and regional environmental harms—particularly air pollution—associated with petroleum use. Together, these measures aim to lessen geopolitical and supply‑chain risk while mitigating the environmental footprint of India’s energy system.
India imported approximately 232.5 million tonnes of crude oil in 2023–24, making it the world’s second-largest crude-oil importer and underscoring the economy’s substantial import dependence. In monetary terms, the top suppliers were led by Russia (US$51.3 billion, 22.1% of India’s imports), followed by Iraq (US$28.6 billion, 12.3%), Saudi Arabia (US$19.3 billion, 8.3%), the United Arab Emirates (US$13.7 billion, 5.9%) and the United States (US$5.0 billion, 2.2%); the broader top-15 supplier group accounted for US$138.4 billion in imports. The listed suppliers span Eurasia, the Gulf, Africa, the Americas and East Asia, reflecting a deliberately diversified sourcing portfolio that nevertheless concentrates significant value in a few partners.
Regional sourcing shifted markedly in 2023–24. Crude originating from the Commonwealth of Independent States (principally Russia, Kazakhstan and Azerbaijan) rose to roughly 39% of India’s imports, while the West Asian/Gulf share (notably Saudi Arabia, Iraq, UAE and Kuwait) fell to about 46%, the lowest level recorded for that region. This realignment indicates both a reorientation toward Eurasian supplies and a partial retreat from historic dependence on West Asian producers.
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These patterns entail dual implications for energy security: on one hand, the geographic dispersion of suppliers reduces reliance on any single region; on the other, the large share sourced from Russia (22.1%) and the aggregated CIS proportion (≈39%) introduce concentration and geopolitical risk. Moreover, the varied provenance of supplies reinforces India’s exposure to cross-regional trade routes and maritime chokepoints, making import resilience contingent on both diplomatic relations and secure logistics.
Crude oil trading in India combines domestic financial hedging instruments with international benchmark pricing and regional supply dynamics. Refiners and downstream buyers of products such as petrol, diesel and jet fuel can manage their exposure to price volatility by using crude futures contracts listed on Indian exchanges (MCX, BSE). These contracts permit hedges settled in Indian rupees and calibrated to support procurement and domestic product pricing, thereby furnishing a local risk‑management tool linked to global crude movements.
Futures on MCX and BSE are settled in cash at expiry rather than by physical delivery; the cash settlement is determined with reference to internationally quoted benchmark settlement prices (principally WTI or Brent). Consequently, Indian market participants hedge against movements in those liquid global benchmarks even though they do not take delivery of the benchmark crudes themselves.
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The “Indian Basket” is the market shorthand for the typical quality mix India imports from the Persian Gulf — a weighted average that combines sour Middle Eastern streams (principally Dubai and Oman) with a sweet crude reference (Brent). Actual transaction prices, however, are set by exporters’ monthly Official Selling Prices (OSPs), which adjust the basket reference up or down via premiums or rebates according to supply, demand and freight considerations. Thus the theoretical basket serves as a reference point, while OSPs implement the practical monthly pricing for deliveries to India.
Together, these elements establish a hybrid price‑discovery and hedging framework: physical flows from Gulf producers and their monthly OSPs determine the cash market offered to India, while Indian exchange‑traded futures — cash‑settled against Brent/WTI — provide rupee‑denominated hedges. The system therefore links India’s domestic refining sector to both regional suppliers and global benchmark markets and operates on a dual cadence of monthly OSP declarations and futures contract expiries for risk management and price discovery.
The Indian Gas Exchange (IGX) operates as the country’s organized online marketplace for natural gas, using a set of designated physical delivery hubs that serve as entry and exit nodes for traded volumes. Regulatory oversight for downstream gas-sector activities, including the trading, transmission and distribution arrangements that underpin venues such as IGX, is provided by the Petroleum and Natural Gas Regulatory Board (PNGRB), established in 2005 and endowed with the statutory framework for these functions.
IGX purchasers may take physical delivery of gas at the listed hubs and subsequently transport it to their consumption points via the national cross‑country pipeline network. This arrangement allows for short‑term scheduling and frequent nominations, so virtual transactions executed on the exchange can be converted into daily physical movements. Pipeline capacity and transportation services linking the hubs to end users are supplied by GAIL (Gas Authority of India Limited) and other pipeline operators for a fee, thereby connecting the exchange’s market transactions to the country’s physical infrastructure.
The five IGX delivery hubs are strategically located on India’s maritime margins to interface with coastal supplies and the transmission grid: Dabhol and Jaigad in Ratnagiri district (Maharashtra) on the western coast, Dahej and Hazira in Gujarat, and Kakinada in Andhra Pradesh on the eastern seaboard. This geographic spread enhances the exchange’s ability to reach consumers across regions by integrating coastal receipt points with the national pipeline system.
Taxation and pricing
India’s retail fuel market is deregulated and retail prices for petrol and diesel are adjusted daily to reflect international and domestic market movements. Nonetheless, a substantial fiscal overlay remains embedded in pump prices: combined central and state levies typically account for roughly 45–55% of the final consumer price. The central component, chiefly central excise duty, normally contributes about 24–26% of the retail price, while state-level taxation—collected largely as VAT—varies across jurisdictions but generally adds on the order of 20–25%.
Beyond these point-of-sale taxes, upstream fiscal charges such as royalties and the oil development cess applied to domestically produced crude and natural gas increase the overall tax burden that is ultimately reflected in retail fuels. In effect, nearly half of what consumers pay for petrol and diesel flows to government revenues when all statutory charges are aggregated.
Empirical examples illustrate this composition. In Bengaluru (May 2011) petrol sold at ₹71.09 per litre, with taxes amounting to about 47% of the pump price. A detailed breakdown from Delhi (April 2018) shows a dealer base price of ₹31.08/L, central excise of ₹19.48/L, state VAT of ₹15.70/L and dealer commission of ₹3.60/L, producing a retail price of ₹73.83/L. Fiscal choices can materially influence how international price movements reach consumers: during the 2020 COVID-19 downturn, the central government raised excise duties on petrol and diesel, a policy response that retained additional revenue rather than passing the full international price decline through to retail prices.
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Domestic natural gas prices for upstream producers (notably ONGC and Oil India) have been administratively determined by the Government of India on a semiannual basis through a formula that referenced international benchmark gas prices (including those in the United States, Russia, Canada and the United Kingdom). Imported liquefied natural gas (LNG), by contrast, is priced with reference to international crude-oil benchmarks rather than gas indices, producing a distinct pricing trajectory for imports relative to indigenous production.
Policy-driven interventions have produced pronounced volatility in recent years. In April–September 2020 notified domestic prices fell to about US$2.5 per MMBtu—the lowest level since the adoption of gas-pricing reforms—illustrating exposure to demand and global-price dynamics under the prior regime. In 2022 the government reformed this framework by introducing an Administered Price Mechanism (APM) that ties the domestic gas price to 10% of the Indian crude-oil basket, while explicitly imposing a floor and a ceiling to curb extreme downside and upside movements. The reform’s stated objective was to enhance price predictability and reduce risk for both producers and consumers by anchoring gas to a stable crude-basket share and by limiting excessive volatility through bounds.
Operationally, the APM produced administered domestic gas prices in the range of roughly US$6.5–7.0 per MMBtu during 2023–24, a level that reflects the practical effect of the 10%-of-crude-basket linkage operating within the prescribed floor–ceiling corridor.
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City Gas Distribution
City Gas Distribution (CGD) is a national programme, overseen by the Ministry of Petroleum and Natural Gas, that builds organized pipeline networks to deliver natural gas within and between urban and peri‑urban areas. The scheme deploys hierarchical pipeline corridors—trunk, feeder and distribution lines—that are integrated with existing transport and utility infrastructure to connect multiple cities, towns and industrial zones.
The network serves two distinct end‑use systems: piped natural gas (PNG) for stationary users (household and commercial reticulation) and compressed natural gas (CNG) for vehicular refuelling. Infrastructure is therefore concentrated at spatial nodes where upstream supply (city‑gate stations, interconnection points) links to downstream PNG reticulation and CNG filling stations, enabling seamless transfer from bulk supply to end‑use delivery.
Siting and expansion of CGD facilities are driven by spatial demand indicators—residential density, commercial activity, industrial estates, traffic corridors—and by proximity to main pipelines. As a result, household and commercial access to PNG is extended through localized reticulation while CNG stations are preferentially located along arterial roads and transport hubs to serve vehicle fleets.
From a regional planning perspective, CGD alters patterns of energy accessibility by shifting distribution away from road‑borne fuel transport toward fixed pipeline corridors and distributed refuelling, promoting more continuous cross‑jurisdictional supply. The predictability of these corridors supports coordinated land‑use and transport planning, reduces dependence on centralized refuelling points, and facilitates integration of energy infrastructure into urban development strategies.
Petrol stations in India
As of August 2025 India’s retail fuel network comprised roughly 126,502 petrol stations, reflecting long‑term expansion driven by rising vehicle ownership, accelerating urbanization and broader economic growth. Infrastructure development has been accompanied by diversification of fuel services, notably growth in CNG filling points and electric‑vehicle charging stations.
The retail network is dominated by state‑owned oil‑marketing companies (OMCs) alongside several large private operators. Contemporary station counts approximate Indian Oil Corporation (IOCL) 26,849; Bharat Petroleum Corporation Limited (BPCL) 14,675; Hindustan Petroleum Corporation Limited (HPCL) 14,161; Nayara Energy ~6,386–6,500 (with additional openings planned in 2025); Reliance/Jio‑BP ~1,916; Shell ~350; and Essar ~2,225. Remaining outlets are supplied by other private and regional operators. Shell’s footprint is concentrated in the southern and western states (Tamil Nadu, Karnataka, Maharashtra, Telangana, Andhra Pradesh and Gujarat). Essar’s retail network has been integrated with its Vadinar refinery in Gujarat, which has a reported capacity of about 280,000 barrels per day.
Beyond conventional petrol and diesel outlets, specialised networks and targeted initiatives are notable. Indraprastha Gas Limited (IGL) has developed a dedicated CNG network with a strong presence in the national capital region. Several state OMCs have promoted low‑investment rural outlets that combine basic petroleum retailing with sale of agricultural inputs and household items to serve farming communities.
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Regional patterns show considerable variation. A historical snapshot (31 March 2016) records 56,191 petrol stations nationally and illustrates the distribution of ownership across states — IOCL 25,364; HPCL 13,802; BPCL 13,439; Others (including RIL/Nayara/Shell/ONGC) 3,586. In that snapshot the largest state totals were Uttar Pradesh (6,616), Maharashtra (5,419), Tamil Nadu (4,702), Karnataka (3,836), Rajasthan (3,736) and Gujarat (3,384). Punjab was reported to have roughly 3,300 stations (3,316 on 31 March 2016). The 2016 company‑level breakdown demonstrates the predominance of IOCL and the significant role of state‑owned OMCs in regional retail markets, while private players and specialised providers occupy strategic regional niches.