India's crude oil production isn't just slipping—it's structurally declining at about 3% annually. The core culprit? Natural field depletion. Oil and Natural Gas Corporation's mature fields, particularly in the Western Offshore basin including the iconic Mumbai High field, experience natural decline rates of 7-8% per year. This aligns with global patterns where oil fields typically follow a 15-year lifecycle: peak in years 3-4, plateau for 7-8 years, then enter decline. Transcripts +2
The numbers tell the story. ONGC's Western Offshore production peaked at 39 MMTOE in 1995-96 but has since fallen to 26.18 MMTOE—a roughly one-third volume reduction over three decades. Aging infrastructure compounds the problem. The Joint Operated Velasquez field, for instance, is over 80 years old with approximately 85% water cut, meaning most of what comes up is water, not oil. Reservoir pressure depletion and increasing water production are fundamental physics that no amount of wishful thinking can reverse. Transcripts +1
The impact on ONGC's books is stark. Crude oil production fell from 21.14 MMT in FY24 to 20.89 MMT in FY25, though the company still accounts for over 73% of India's domestic crude output. Natural gas production has been flatlining despite substantial investments. The company's mature fields contribute approximately 60% of total production, making their decline rates critical to overall output. AnnualReports +2
Reserve replacement ratios reveal a tale of two Indias. Offshore India achieved 114.1% crude oil replacement and 130.7% gas replacement in FY25, while onshore India managed only 66.5% and 8.2% respectively. Aggregate India stood at 96.8% for crude—meaning the country produced slightly more than it replaced. ONGC has maintained a reserve replacement ratio above 1.0 for 19 consecutive years, but sustaining this gets harder each year as fields age. AnnualReports +2
ONGC isn't watching passively. The company has deployed Enhanced Oil Recovery (EOR) and Improved Oil Recovery (IOR) techniques across its asset base. As of March 2025, ONGC submitted 33 Enhanced Recovery pilot reports to the Directorate General Hydrocarbons, with 17 approved and 11 under consideration. AnnualReports +2
The results are measurable. A single-well surfactant-polymer flood test at Mumbai High boosted production from 76 to 115 barrels per day—a 40 bpd incremental gain. The first fully automated Chemical EOR plant aims to add 0.598 million metric tonnes by FY 2039-40, contributing about 4.27% incremental recovery to that mature field. In Gujarat, where enhanced recovery initiatives are "very high," the state contributes roughly 4.5 million tonnes of production annually with expectations of additional output. AnnualReports +2
But EOR has limits. It can slow decline, not reverse it entirely. The company's record drilling of 578 wells in FY25—the highest in 35 years—shows the sheer effort required just to stay flat. Transcripts
Recognizing that onshore brownfields can't deliver the growth India needs, the government launched "Samudra Manthan"—the National Offshore Exploration Scheme—with a ₹84,084 crore ($8.8 billion) outlay through FY 2030-31. The centerpiece: 50% government cost-sharing for deepwater exploration wells, capped at ₹675 crore ($8-9 million) per well.
This fundamentally changes the risk equation. A single deepwater exploratory well costs $125-150 million. With global success rates at just 1 in 7-8 wells, the financial risk is enormous.
This "risk-sharing subsidy" makes marginal blocks economically viable and crowds in private capital. Transcripts
The scheme targets India's frontier basins: Krishna-Godavari, Cauvery, Mahanadi, and the Andaman region. These areas hold an estimated 5,600 MMTOE of potential resources but require advanced technology and significant investment. ONGC plans to drill 150 deepwater wells over seven years, while the scheme itself funds 60 wells.
The cost structure of deepwater exploration has historically constrained ONGC's ambitions. One deepwater well equals 100 onshore wells in cost. With annual exploration expenditure typically running at ₹8,000-10,000 crore ($96-120 million), ONGC could previously afford only 6-8 deepwater wells per year. Post-scheme, that same budget supports 12-16 wells annually. Transcripts +1
The basin economics are brutal. Dry well write-offs in FY25 tell the story: KG Basin ₹1,808 crore ($217 million), Cauvery ₹779 crore ($94 million), Western Offshore ₹1,152 crore (~$139 million). Government support doesn't eliminate these losses, but it halves the capital at risk. Transcripts
ONGC's management has indicated that CapEx will increase proportionally to government support received. With "big money from government" expected to start flowing from FY27-28 after seismic surveys are completed, ONGC's exploration budget could meaningfully expand beyond current levels. Transcripts +3
Why this desperate push for domestic production? India's crude oil import dependence has risen from 55% in FY99 to over 90% in FY26. The annual import bill reached $137 billion in 2024 and $158 billion in 2022-23. With India now the world's third-largest crude consumer, this dependency creates systemic economic risks. AnnualReports +1
The refining sector, while globally competitive with 24 refineries processing diverse crude grades, faces supply chain concentration. Roughly 40-55% of India's crude imports transit the Strait of Hormuz. When the waterway effectively closed during the March 2026 Iran crisis, Brent crude surged from $80 to $120 in under a week. Estimates show that a $10 increase in crude prices could widen India's current account deficit by 40-50 basis points.
The trade deficit impact is immediate. India's goods trade deficit widened to $30.43 billion in June 2026—the widest on record for that month—as war in the Middle East and US tariffs on Russian oil lifted import costs. The current account deficit is projected to nearly double to ~1.7% of GDP in FY27, assuming $85/barrel average crude prices.
India isn't betting everything on exploration. The country is building its insurance policy through strategic petroleum reserves. Current SPR capacity stands at 5.33 MMT across Visakhapatnam (1.33 MMT), Mangaluru (1.5 MMT), and Padur (2.5 MMT)—providing only 9.5 days of consumption at full capacity. With reserves only 64% full, effective coverage drops to 5-6 days.
Phase-II expansion, approved at ₹14,527 crore ($1.74 billion), will add 6.5 MMT at Chandikhol (Odisha) and Padur (Karnataka) under a Public-Private Partnership model. The government provides up to 60% Viability Gap Funding, with private partners contributing the remainder. This commercial-cum-strategic approach allows facilities to serve both national security and revenue generation needs.
When complete, total SPR capacity will reach 11.88 MMT, moving India significantly closer to the International Energy Agency's recommended 90-day reserve standard. Additional facilities are being explored at Bikaner (Rajasthan)—India's first salt cavern-based reserve—and Bina (Madhya Pradesh).
The SPR expansion and offshore exploration strategy work together as complementary defense layers. Storage addresses immediate and medium-term risks—providing a buffer during supply disruptions that exploration, with its 5-10 year gestation period, cannot solve. Exploration addresses the long-term structural vulnerability by reducing import dependence itself.
The integration is strategic. ONGC's domestic production of 20.89 MMT in FY25 serves as a natural strategic reserve, reducing dependence on volatile international markets. The company's infrastructure—over 25,500 kilometers of pipeline including 4,500 kilometers sub-sea—supports the storage-distribution network. AnnualReports +1
International partnerships enhance both approaches. The May 2026 agreement between ISPRL and ADNOC explores expanding ADNOC's crude storage in India to 30 million barrels, including potential new facilities at Vishakhapatnam and Chandikhol. This brings investment, technology, and supply security—though it also raises questions about strategic autonomy given India's potential storage of reserves in Fujairah, UAE.
The trajectory of India's energy security hinges on the success of these initiatives. If Samudra Manthan delivers on its targets—adding over 600 MMTOE of reserves, raising annual production from 62 to 80 MMTOE, and expanding the resource base from 1.6 to 2.2 billion TOE—India could reduce crude oil imports by nearly ₹1 lakh crore annually. This would strengthen current account stability, reduce fiscal pressure from subsidies, and enhance strategic autonomy.
Failure, however, accelerates vulnerability. The International Energy Agency projects India's oil demand will rise by 1 million barrels per day between 2025 and 2030—the highest absolute growth of any country. Without domestic production growth, import dependence could exceed 95% by 2030, with annual import bills potentially surpassing $200 billion. The 74-day total reserve coverage (including commercial stocks) would become increasingly inadequate against a backdrop of growing imports. AnnualReports
The interim years are critical. Phase-II SPR projects will take 4-7 years to become operational after financial closure. Until then, India must rely on diversified sourcing, higher commercial inventories during geopolitical uncertainty, and long-term supply agreements.
India's energy security strategy has moved beyond policy reform to mission-mode implementation. The $8.8 billion offshore exploration bet and ₹14,527 crore storage expansion represent the most ambitious energy security initiative in India's history. Success isn't guaranteed—exploration is inherently risky, and storage infrastructure takes years to build. But with 90% import dependence, a $144 billion annual import bill, and vulnerability to chokepoint disruptions, the cost of inaction far exceeds the price of these bold bets.
