Oil India Ltd Q3 FY2026 Concall Summary

Key Takeaways

• Production maintained, but price hit revenue: Crude output held steady through workovers and record drilling, yet a 17% drop in crude price realization drove the revenue decline.
• Contract costs surged on drilling intensity: Contract costs jumped to INR892 crores from INR500 crores last year, reflecting a record 75-plus well program, deeper targets, and new deepwater seismic activity.
• Gas sales dipped on temporary customer shutdowns: Reduced offtake from Namrup Power Plant and BVFCL caused a minimum de-growth, but the shutdowns have been lifted and sales are recovering.
• NRL delivered a standout quarter: The refinery captured strong diesel margins, achieving a \$16 GRM while running at over 100% capacity with its best yield.
• What to watch next quarter: Whether the Q4 production uptick materializes, the pace of gas sales recovery, and any firm capex or production guidance for FY27 beyond the aspirational targets.

Production & Drilling Activity

• Mature fields managed via two-pronged strategy: Workover operations arrest pressure and performance decline by 8-10%, while new development well drilling adds incremental output. A production uptick is expected in Q4, with the Rajasthan field already performing well.
• Record drilling year in progress: The company will close the year with 75-plus wells, the highest ever in its history, alongside possibly the highest ever workover operations. The same manpower is delivering more drilling than 2-3 years ago due to improved operational efficiency, standardized SOPs for rig movement, and meticulous planning of service bundling.
• Deeper wells drive non-linear cost increase: Target ranges have moved to 5,500-plus metres from ~4,000 metres, with technology-supported deeper horizon seismic imaging. Drilling deeper increases complexity and prolongs duration non-linearly, and workover duration in mature fields has also increased.
• Production buildup timing is back-end loaded: When drilling happens, the buildup towards production comes in the last quarter, and management cautioned that some output could "sleep over beyond FY27." Aspirational target is 0.4 crore metric tons crude if 100 wells are drilled, with conservative planning indicating 3.8 in FY27 and 4.0 in FY28.

Rath: "We are going to close the year by a number which will be the highest ever in the history of Oil India Limited, that will be 75-plus wells with additional possibly highest ever or near highest ever workover operations."

Gas Business & Monetization

• Gas sales decline was temporary: Minimum de-growth was driven by reduced offtake from major customers Namrup Power Plant and BVFCL, which resulted in temporary unit shutdowns. These shutdowns have now been lifted and gas production and sales are well beyond recovery during the quarter.
• Associated gas flaring eliminated: Previously flared associated gas is now monetized via additional compressors alongside fields, preventing any impediment to crude oil production. A new pipeline from Kumchai (Arunachal Pradesh) to Kusijan (Duliajan) helps evacuate gas previously flared from the Arunachal field, boosting crude production.
• Gas storage capability established: A compressor has been converted as an injection pump, enabling gas to be injected back when evacuation is constrained and withdrawn once pipeline connectivity is complete.
• Feeder line authorization in advanced stage: The Duliajan feeder line, once approved by the government and communicated to IGGL, will take approximately 18 months to construct and will enable evacuation of 0.35 crore standard cubic meters of gas per day. The drilling program is already planned for this evacuation capacity.

Rath: "Today, by virtue of having additional compressors alongside those fields, we are monetizing those earlier being flared gas and maintaining the crude production. So, this has been our strategy, and this will continue to be the strategy for us so that the crude oil production is not getting impediment because of the necessity of flaring."

Contract Cost Step-Up

• Contract cost more than doubled YoY: The increase to INR892 crores from INR500 crores last year and INR520 crores last quarter is partly due to near-field exploration and development drilling which enhances production.
• Three structural drivers: (1) drilling deeper wells with technology-supported deeper horizon seismic imaging; (2) an enhanced drilling and workover portfolio with more rigs deployed; (3) additional studies and extensive seismic data acquisition, processing and interpretation. Near-field exploration in the mining lease area also supports development drilling and the reserve replacement ratio.
• New deepwater acreage adds a fresh layer: Deepwater blocks covering 40,000 sq km in Mahanadi and KG basin were acquired in May 2025. Already, 4,200-line km of 2D seismic and 50% of 3D seismic (5,300 sq km) have been completed, adding to contract cost. Next year, management expects to undertake at least 3 to 4 deepwater drilling commitments, entailing mobilization of drill ships at higher cost.
• Seismic costs are seasonal, not linear: Activities are weather-window driven, with the monsoon bringing work to a standstill in the Northeast region. Q1, Q2, and Q3 expenses are never equal or equivalent, so an annualized basis gives the clearest picture.
• Management declined to call this the new baseline: When asked whether the increased contractual costs represent the new baseline for modelling, management elaborated on activities but did not explicitly confirm or deny.

Exploration & Andaman Basin

• Exploration costs are inherently unpredictable: The process involves overlapping cycles of seismic, drilling, post-drill analysis, tie-in studies, supplementary seismic, dynamic modelling, and infill wells. Continuous optimization makes it extremely difficult to give exact dry well costs before year-end calculations.
• Andaman wells show progress and write-offs: The first well was drilled to 3,600m and is carried as work-in-progress with testing intended. The second well was drilled to 2,600m with a side track that established the presence of hydrocarbon, but under Ind AS the mother well had to be written off despite the side track success. The third well is currently drilling at ~3,300-3,400m, and a fourth well is planned on the northwest side.
• Appraisal process initiated: 2D seismic reprocessing has been completed, and 600 sq km of 3D seismic is planned to establish the structure and extent of the discovery.

Rath: "With these kind of continuous process of optimizing your drilling cost basis the exploration efforts and then the studies, it is extremely difficult to give you a number what exactly will be my dry well cost at the year-end before doing the calculations."

NRL Refinery & Pipeline Infrastructure

• NRL captured exceptional diesel margins: The refinery, which is 65-70% diesel, benefited from diesel margins as high as \$24 in Q3, achieving a \$16 GRM. The refinery ran at 100%+ capacity with its best yield in percentage terms, supported by a subdued crude oil price spread to HSD.
• Expansion milestones progressing: Commissioning commenced for CDU/VDU mother units along with select utility packages towards end of December 2025. Stabilization is expected by end of Q4 FY26. Mechanical completion is targeted before Q4 FY27, with 100% capacity utilization by Q2 FY28.
• Ramp-up plan is phased: The refinery will achieve 50% capacity utilization on a daily basis during Q4 FY27, then gradually increase to ~75%, and then to 100%. After next year, no major capex is foreseen except the polypropylene unit (~INR7,200 crores), which will be at its peak spend period.
• Pipeline infrastructure nearing completion: The Paradip-Numaligarh crude oil pipeline has achieved about 90% physical progress and will be ready for commissioning by Q1 FY27. The Numaligarh-Siliguri product pipeline expansion and Duliajan-Numaligarh pipeline expansion have both achieved mechanical completion, with the latter expected to commission by April 2026.

Capex, Dividends & International Assets

• Capex will overshoot full-year guidance: Nine-month stand-alone capex of ~INR8,500 crores is already in line with the full-year guidance of INR8,800 crores. Management confirmed they will surpass this figure due to increased activity to supplement production efforts, and stand-alone capex will hover around INR9,200 crores plus going forward.
• Next year's capex will have an upswing: More drilling rigs and more wells are planned, but management declined to give a specific number, saying the revised estimate will be readjusted after Q1 line of sight.
• Dividend maintained despite consolidated PAT position: The board took a considered view to protect shareholder interests and maintained the same dividend of INR7 per share.
• Russian dividends retained in Moscow: Dividends are in Oil India's account with SBI's Moscow branch (CIBL), with approximately \$300 million retained there. Taas-Yuryakh dividends are 100%-plus backed, and Vankor dividends are ~90% backed.

Rath: "The dividends are in safe account of Oil India Limited and the account lies with CIBL branch that is SBI branch in Moscow. So, it is in our account. The range, the order of magnitude of retained money in Moscow branch is about \$300 million."

Guidance & Commitments

Key Metrics