Oil & Natural Gas Corpn Ltd Q4 FY26 Earnings Call: Record 265% Dividend Payout, Guides 7-8% Annual Gas Growth

Oil & Natural Gas Corpn Ltd held its Q4 FY26 earnings call on May 26, 2026. Here's a quick read of what management said — performance, strategy, and the outlook ahead.

Record Payout Offsets Lower Standalone Earnings

• Consolidated PAT for Q4 FY26rose 53% YoY to Rs.13,678 crores, with annual consolidated PAT at Rs.49,793 crores (up 30% from Rs.38,329 crores in FY25), driven by subsidiaries HPCL, MRPL, OVL, and OPaL.
• Standalone Q4 FY26 PATof Rs.6,650 crores (up 3% QoQ) was flat, while standalone FY26 PAT of Rs.32,894 crores declined from Rs.35,610 crores in FY25, impacted by lower crude realisation.
• Statutory levies fell 15.6%to Rs.26,148 crores in FY26 (from Rs.30,968 crores in FY25), primarily due to lower crude prices and the abolition of SAED effective 2-Dec-2024.
• Total dividend for FY26reached a record 265% (Rs.13.25 per share), with a payout of Rs.16,669 crores representing a 51% payout ratio — the highest ever total payout.
• Standalone crude oil productionwas 18.355 MMT in FY26 (vs 18.558 MMT in FY25); natural gas production was 19.533 BCM (vs 19.654 BCM in FY25), with management attributing the decline to operational disruptions and new project start-up blips.

Gas Becomes the Dominant Stream with 7-8% Annual Growth Targeted

• Production mix has shifted to ~2/3 gas and ~1/3 oil, making ONGC predominantly a gas company; management guided 7-8% annual gas production growth in FY 2026-2027 and FY 2027-2028.
• New-well gas volumes jumped to ~9 MMSCM/dayas of April 2026, with management guiding to ~12 MMSCM/day in FY 2026-2027 (priced at 12% of crude oil, currently ~$10.8 at $90/bbl crude).
• DUDP (Daman) monetisation commencedin March 2026 with 4 of 15 wells opened; all wells expected online by September-October 2026 (FY 2026-2027), adding 3-4 mmscmd of gas and reaching peak production of ~4.89-5 mmscmd in FY 2026-2027, with a plateau of 7-8 years.
• DSF field expected to add 4-5 MMSCMDof free-priced gas, with ramp-up targeted for FY 2027-2028; the project has been delayed but management considers it geologically more predictable than other offshore fields.
• KG basin gas productionis currently 2.3 MMSCMD (Q4 FY 2025-2026) and expected to ramp up after new wells are connected in July-August 2026 (FY 2026-2027); management declined to give specific numerical guidance due to geological unpredictability.
• KG basin oil productionfaced geological surprises; a solution involving additional wells has been identified, with production expected to return to originally planned levels within 3-4 quarters (around mid-FY 2027-2028).
• Natural decline from existing assets is 7-8% annually, with interventions compensating for 2-4%, leaving a net decline of 1-2% per year unless new fields (DUDT, DSF) add production.

Rs.30,000-32,000 Cr Capex Guided for FY27 with Offshore Focus

• E&P CAPEX for FY 2026-2027guided at Rs.30,000-32,000 crores, with non-E&P CAPEX of an additional Rs.10,000-11,000 crores if new business opportunities arise.
• Exploration spend of Rs.8,000-10,000 crores per yearto be maintained in FY 2026-2027; management expects ~16 wells to be drilled over FY 2026-2027 and FY 2027-2028 from the conventional exploration budget.
• Capex split for FY 2026-2027guided as 70% offshore and 30% onshore; of the offshore portion, ~70% (or ~49% of total capex) is allocated to western offshore, the primary destination due to higher commercial productivity.
• Government exploration spending(seismic surveys, well assistance) is not expected in FY 2026-2027; first material inflows anticipated in FY 2027-2028 after seismic results are evaluated.
• ONGC drilled 500 wells total in FY 2025-2026, including 100 exploratory wells and only 4 deep-water wells (each costing ~100 onshore wells); management cited Oil India's 2.5× capex increase to Rs.10,000 crores as a benchmark but stated ONGC cannot similarly raise standalone budget from current levels.
• Western offshore decline— production dropped from a peak of 39 MMTOE in FY96 to 26.18 MMTOE in FY26, a roughly one-third fall over 30 years; management expects BP's TSP-2 contract covering 62% of western offshore (now 100% total) to help arrest and reverse the trend.

Rs.4,000 Cr Saved in FY26; Second Rs.5,000 Cr Program Lined Up

• First phase of a Rs.5,000 crore cost-saving initiativeyielded ~Rs.4,000 crores in actual savings during FY 2025-2026, partially offset by rupee depreciation (~11%) and a GST hike on inputs from 12% to 18% (which eroded ~Rs.2,000 crores of savings).
• A second Rs.5,000 crore cost-saving programhas been lined up and is expected to be realised over approximately FY 2027-2028; management expressed being "very comfortable" on costs.
• Q4 FY 2025-2026 operating expensescame in at Rs.9,200 crores versus a regular quarterly run rate of Rs.5,500-6,000 crores, with one-off items totalling ~Rs.1,034 crores (GST on royalty Rs.235 cr, KG-98/2 umbilical write-off Rs.262 cr, old outstanding recoverable provision Rs.257 cr, stores and spares provision Rs.280 cr).
• Other expenses for full FY26increased Rs.3,373 crores to Rs.28,104 crores (from Rs.24,731 crores in FY25), driven by a Rs.1,142-crore rise in provisions/write-offs and a Rs.1,932-crore increase in exchange loss due to rupee depreciation.
• Per-barrel impact of the Rs.5,000 crore programequates to roughly $1.8/BOE, based on 40 million tonnes of production; management noted that dollar-denominated costs and rupee depreciation complicate per-unit comparisons.

BP TSP Expansion, OPaL Turnaround, and Government Policy Tailwinds

• BP awarded TSP-2 contract for 62% of western offshore, making BP the Technical Services Provider for 100% of ONGC's western offshore assets; the TSP-1 partnership in Mumbai High exceeded targets (oil at 102%, gas at 108-109% of baseline in its first year).
• OPaL turned around with Rs.1,206 crores EBITDA in FY 2025-2026(near its Rs.1,500 crore target); management guided FY 2026-2027 EBITDA of Rs.1,500-2,000 crores. An ethane import ship has been ordered from Samsung, with delivery in December 2028 (calendar) and imports expected to begin in FY 2028-2029.
• ONGC Green Limited now has 3,000 MW+ of renewable capacity, with another 1,000 MW expected in FY 2026-2027; the board also approved a new 50:50 port JV with the Gujarat Maritime Board at Dahej.
• Management observed that the government has not imposed windfall taxeseven when crude oil prices touched $140/bbl, interpreting this as a deliberate policy to support domestic E&P on APM gas pricing (review scheduled for January 2027 in FY 2026-2027), management noted that prices have reached $7/mmBtu and the share of APM-priced gas will be less than 50% of total by FY 2027-2028.
• OVL subsidiaryis back to full production at Sakhalin (Russia); the Mozambique LNG project is progressing with 6,000 workers on site, targeting first LNG by end of FY 2027-2028.
• OVL approved FID and contracted an FPSOfor the BM-SE-4 block (Sergipe-Alagoas basin), "targeting net production of 1.3 million tonnes oil equivalent per annum (OVL's 25% share) with first oil in 2030 and first gas in 2031."

1.15x Reserve Replacement in FY26 with Three New Discoveries

• 2P reserves baseline for FY 2025-2026was 44 million tonnes, the same as the prior year (FY 2024-2025); with production of ~40 million tonnes, this implies additional reserves of 4 million tonnes were added during the year.
• Reserve replacement ratio (RRR) of 1.15xin FY 2025-2026, indicating ONGC replaced what it produced; management committed to sharing detailed 2P reserves data with analysts after the call.
• Three hydrocarbon discoveries in FY 2025-2026, all in shallow-water Mumbai Offshore region (two new prospects, one new pool). Additionally, two Western Offshore and one Assam discovery had flow rates exceeding expectations, though management cannot quantify reserve size or CAPEX until appraisal wells are drilled.
• Medium-term gas realisation uplift— management expects 80-90% of total ONGC gas to become new-well gas over 4-6 years, which would significantly improve blended realisations as new-well gas is priced at 12% of crude oil.
• Key near-term production contributorsfor FY 2026-2027 include KG 98/2 gas, Daman, and DUDT; DSF is expected to add production from FY 2027-2028.Management declined to provide specific numerical guidance for FY27 and FY28 gas production, reiterating: "Gas will grow."
• Risks and headwindsinclude geopolitical disruptions (Gulf War causing project delays), new commissioning requiring temporary shutdown of existing wells (creating short-term blips), and geological unpredictability in the KG basin ("geology is geology").