OIL India Limited — Call Transcript 2026

Feb 17, 2026

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Regd. Office: P.O. Duliajan, Dist. Dibrugarh, Assam-786602 Corp Office: Plot No. 19, Sector 16-A, Noida-201301, Uttar Pradesh CIN: L11101AS1959GOI001148 Website: www.oil-india.com

Ref. No. OIL/SEC/32-33/NSE-BSE Dated: 17.02.2026

National Stock Exchange of India Limited BSE Limited Exchange Plaza, Department of Corporate Service Plot No. C/1, G Block, Phiroze Jeejeebhoy Towers Bandra Kurla Complex, Dalal Street Bandra (E), Mumbai - 400 051 Mumbai - 400 001 Symbol : OIL Security Code : 533106

Sub: Conference Call for Q3-2025-26 Financial Results – Transcript

Ref: Regulation 30 of the SEBI (LODR) Regulations, 2015

Sir/Madam,

We write further to our letter of even no. dated 05.02.2026 & 11.02.2026 regarding Conference Call [Con Call] for Financial Results of the Company for Q3 (FY 2025-26) and inform that the Transcript of the said Con Call [dated 11.02.2026] has been uploaded on our website as detailed hereunder:

www.oil-india.com Investors Investor Services Analysts / Investors Meet Transcript of the Analysts’ and Investors’ Call on 11[th] February 2026

Weblink:

• https://www.oil india.com/files/investor_services_documents/Transcript_of_the_Analysts_and_Investors_Call_on_11th_February_2026.pdf

This is for your information & records please.

Thanking you,

Yours faithfully, For Oil India Limited

Ajaya Digitally signed by Kumar Ajaya Kumar Sahoo Date: 2026.02.17 Sahoo 15:59:10 +05'30'

A.K. Sahoo Company Secretary & Compliance Officer

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“Oil India Limited

Q3 FY26 Earnings Conference Call” February 11, 2026

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MANAGEMENT: DR. RANJIT RATH – CHAIRMAN AND MANAGING DIRECTOR – OIL INDIA LIMITED MR. ABHIJIT MAJUMDER – DIRECTOR FINANCE – OIL INDIA LIMITED MR. BHASKAR JYOTI PHUKAN – MANAGING DIRECTOR – NUMALIGARH REFINERY LIMITED MR. AJAYA KUMAR SAHOO – EXECUTIVE DIRECTOR, COMPANY SECRETARY – OIL INDIA LIMITED MR. ABHIJIT DAS – CHIEF GENERAL MANAGER (F & A) – OIL INDIA LIMITED MR. RAGHUNATH MISHRA – CHIEF GENERAL MANAGER- BUSINESS DEVELOPMENT – OIL INDIA LIMITED

MODERATOR: MR. VARATHARAJAN – ANTIQUE STOCK BROKING

Moderator:

Good morning, ladies and gentlemen, and welcome to the Oil India Limited Q3 FY '26 Earnings Conference Call hosted by Antique Stock Broking Limited. As a reminder all participant lines will be in the listen-only mode and there will be an opportunity for you to ask questions after the presentation concludes. Should you need assistance during this conference

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call please signal an operator by pressing star then zero on your touchstone phone. Please note that this conference is being recorded.

I now hand the conference over to Mr. Varatharajan from Antique Stock Broking Limited. Thank you, and over to you, sir.

Varatharajan:

Thank you, Swapnali. Good morning, everyone. I'd like to extend a very warm welcome to all the participants and the management of Oil India Limited to this call. We have with us Dr. Ranjit Rath, Chairman and Managing Director; Mr. Abhijit Majumder, Director (Finance); Mr. Saloma Yomdo, Director (Exploration and Development); Mr. Trailukya Borgohain, Director (Operations); Mr. Bhaskar Jyoti Phukan, MD NRL; Mr. Ajaya Kumar Sahoo, ED, Company Secretary; Mr. Abhijit Das, CGM F&A; and Mr. Raghunath Mishra, CGM Business Development.

Once again, I would like to welcome -- a special welcome to Dr. Ranjit Rath for the first time I think he is on the call. I'll hand over the call to him for his initial remarks. The floor is yours, sir.

Abhijit Majumder:

Good morning, ladies and gentlemen. At the outset, I would like to thank Antique Stock Broking for hosting today's analyst and investor call for Oil India Limited. I'm Abhijit Majumder, Director, Finance. I am joined today by Dr. Ranjit Rath, Chairman and Managing Director, Oil India Limited; and my colleagues from Oil India Limited; Mr. Saloma Yomdo, who is traveling today.

So, in his place, Mr. D.S. Manral will be representing the Exploration and Development Department; Mr. Trailukya Borgohain, who will be joining soon; Mr. Bhaskar Jyoti Phukan MD, NRL; Mr. Ajaya Kumar Sahoo, Executive Director, Company Secretary, Oil India Limited; Mr. Abhijit Das, CGM F&A OIL; Mr. Raghunath Mishra, CGM Business Development OIL

On behalf of the management, I welcome you to our Quarter 3 FY '25-'26 earnings call covering the period 1st of October '25 to 31st of December '25. The financial results were approved by the Board and duly published on 10th February 2026 based on statutory requirements. Prior to diving deeper into the current quarter performance, I would firstly like to call upon our CMD, sir, Dr. Ranjit Rath, to share his perspective on Oil's current strategy. Sir, over to you.

Ranjit Rath:

Good morning, everyone, and I thank all of you -- for joining us on this call. Please bear with me because of my sore throat; I will try to adjust and we'll be able to join the discussion.

Let me begin by welcoming our shareholders and the analyst fraternity and by thanking you for your confidence that you have reposed on Oil India Limited. Your continued engagement and the perspective that you share helps us stay anchored on execution, accountability and long-term value creation.

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As you all know, recent macro environment has once again underscored how dynamic the energy landscape can be shaped by geopolitics, supply discipline and the transition. Yet one really remains unchanged and India's energy demand will continue to grow while ensuring reliable, affordable and progressively cleaner energy remaining a national priority.

For Oil India, this creates both responsibility and opportunity. Responsibility to strengthen India's energy security and opportunity to deliver durable value across the entire value chain. As you all know, Oil India continues to traverse its path as an integrated energy company with operations spanning upstream exploration and production, midstream transportation, refining and downstream value capture and a growing footprint across renewable energy initiatives.

Upstream remains our focus and foundation. First, to build a stronger prospect and secure pipeline through our targeted exploration, seismic and subsurface analysis. Second, accelerating development and near-field opportunities to shorten the cycle time from discovery to production, that is early monetization. Third, improving recovery in mature assets through reservoir management, interventions and efficiency program. Alongside the upstream growth, our midstream readiness is critical.

Let me share some few milestones on this also. The Numaligarh-Siliguri product pipeline expansion from 1.72 million metric ton per annum to 5.5 million metric ton per annum has already achieved mechanical completion, and we are in the process of completing the commissioning process. The Duliajan-Numaligarh pipeline expansion from 1 million to 2.5 million has already achieved mechanical completion on 15 November, and we expect to commission the expanded pipeline by April 2026. In parallel, we expect to complete the common carrier licensing process with PNGRB by April 2026 to initiate the hookup of the DNPL and IGGL line.

On the downstream front, our priority is steady execution and value capture through reliability, efficiency and disciplined project delivery. At Numaligarh Refinery level, all of you know that the 3 million metric ton per annum to 9 million metric ton per annum is progressing well with the commissioning commenced for CDU/VDU, the mother units along with select utility packages towards the end of December 2025. Stabilization for these units is expected by end of Q4 of FY 2026.

Concurrently, the Paradip-Numaligarh crude oil pipeline, which will supply imported crude to NRL has also achieved about 90% physical progress and will be ready for commissioning by Q1 of FY 2027.

The last few months continue to remind us that crude prices and realizations can fluctuate meaningfully in short time spans, driven as much by global events and sentiments as also by the fundamentals. Over the first 9 months of FY '25-'26, our performance reflects this approach, a steady operational execution, continued progress on drilling and development activity and financial discipline. On the financial front of 9 months, our consolidated revenue stood at INR27,036.78 crores, EBITDA at INR9,298.62 crores and a PAT of INR5,126.21 crores.

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On the operational side, our combined oil and gas production for 9 months stands at 4.991 MMTOE. This performance keeps us aligned with our annual operating priorities and trajectories we have laid out towards our production objectives. Our emphasis is straightforward, strong technical execution, rigorous project discipline and prudent capital allocation.

Thank you once again for your continued support. I'll now hand over to our Chief Investment Officer -- Investor Relations Officer, Mr. Abhijit Das, who will provide an overview of the third quarter performance.

Abhijit Das:

Thank you, sir. Good morning, ladies and gentlemen. I take this opportunity to share our company Oil India Limited, the operational and the financial highlights and the performance of our material subsidiary, NRL.

The key operational performance of our company for the quarter and the period ended on 31st of December '25 is : - The combined oil and gas production for Q3, it is 1.659 million metric ton. And for the 9 months ended, it is 4.991 MMT.

The crude oil production for the quarter is 0.858 MMT, which is increased by 1.18% on quarter-to-quarter. The crude oil daily production has ramped up to 9,861 metric ton on 31st of December 2025, which is the highest in the last decade. The natural gas production for the quarter is 0.801 bcm, which is almost at par with the previous quarter.

The gas sales have experienced minimum de-growth driven by reduced offtake from major customers such as Namrup Power Plant, BVFCL, which has resulted in the temporary shutdown of their units. These shutdowns have now been lifted and the gas production and sales are well beyond recovery during the quarter of '25-'26.

On the exploration and development front, progress has remained strong. Our company has drilled 19 new wells during the quarter. Cumulatively, for the 9-month period, 51 wells have been drilled, which we have achieved 65% of our annual target. The key financial highlights for this quarter as per the period of the 9 months ended 31st of December 2025 are the average price realization for Q3 FY '26 was $62.84 per barrel vis a vis$73.8 per barrel in Q3 of FY '25.

For the 9 months ended 31st of December 2025, the average crude oil price realization was $65.73 per barrel vis-a-vis $79.35 per barrel in the previous 9 months. 17.16% decline in the crude oil price realization is the major driver in decline of our operating revenues during the period of the quarter as well as the 9 months.

The natural gas price stood at $6.65 per MMBtu in Q3 of FY '26 vis-a-vis $6.56 per MMBtu in Q3 of FY '25. The stand-alone operating revenue for Q3 FY '26 is INR4,916 crores and for the 9 months, it is INR15,385 crores. The EBITDA margin for the Q3 of FY '26 is 33.96% as compared to 34.82% of Q2 of the current year. The profit after tax for Q3 is INR808.31 crores during the quarter. Our EPS stood at INR16.39 per share for the 9 months ended of FY '26.

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I take this opportunity to share the performance of our material subsidiary, Numaligarh Refinery. The operating revenue is INR6,526 crores for Q3 FY '26, which is at par of the previous year. Further during the 9 months, the operating income is INR19,249 crores, which is 5.67% higher as compared to the previous year.

The capacity utilization of our refinery is 100.31% in quarter 3 of FY '26 and the distillate yield for the quarter was 86.8%. The gross refinery margin, excluding excise duty is $16.27 per barrel, which is up by 54% vis-a-vis Q2 of the current year. The EBITDA is INR1,302 crores for Q3 of FY '26 vis-a-vis INR637 crores in Q3 of FY '25. The PAT is INR867 crores for Q3 of FY '26 vis-a-vis INR385 crores of Q3 FY '25.

I'd like to present the consolidated financial results of our company. Our company has reported the consolidated operating revenue of INR9,111 crores and registered a PAT of INR1,436 crores during Q3 of '26. Both the consolidated operating revenue and PAT are in line with Q3 of FY '25.

We are pleased to inform you that the company has declared a dividend of INR7 per fully paid equity shares during our period closing of 31st of December 2025. Our company has delivered a resilient and disciplined performance in the third quarter of FY '26, supported by our operational stability and prudent financial execution. As we look ahead, our focus remains on execution excellence, production growth and long-term value creation across portfolio.

With this, I conclude my remarks. We will now like to welcome your questions and look forward for an engaging discussion. Thank you very much.

Moderator:

Probal Sen:

Bhaskar Jyoti Phukan:

Ranjit Rath:

Thank you very much. The first question from the line of Probal Sen from ICICI Securities.

Sir, a couple of questions. Firstly, on NRL on the expansion front, as was mentioned that the mother units, the CDU and the VDU should be -- have already commenced commissioning and should stabilize by Q4. So, for FY '27 there, sir, what kind of throughput should we be looking at for NRL?

Yes, I'm MD NRL. So, during the last quarter, actually, we expect to have a serious run of the whole refinery complex. So, we will not have any major throughput this year. But towards the Q4, we will try to run the refinery at least at 50% of the rated capacity of 9 million. So, we can translate that. Maybe we will be able to process around 1 million more than our capacity -- current capacity of 3 million. Maybe we will end the year FY '27 with a 4 million capacity throughput.

Just to add and then since we are answering this question, just to add, these units are commissioned in a batch process. That's number one. And all the units need to be commissioned for stabilization also. However, we are also working on an intermittent process so that we can start the production portfolio with an enhanced capacity. So that thought process has also kicked in. So, we will try to achieve 4 million metric ton by the last quarter of FY 2027.

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Probal Sen:

Ranjit Rath:

Understood, sir. Understood. The next -- the second question was with respect to the volume growth. You did mention that the 9-month oil and gas output of close to 5 million tons is in line with the medium-term objectives. Now where are we with respect to the targets for basically reaching 4 million tons of oil and 5 bcm of gas, which I believe was the earlier target to reach by around FY '27-'28? Any colour you can throw on that?

Okay. I'll answer this question in a manner which is -- I'll take a bit of time to explain also. Look, the production from mature fields are done with a two-pronged strategy. Number one, you do workover operations and that contributes additional production while we arrest the decline of pressure or performance by 8% to 10%. All of you know that.

Second strategy is we enhance our drilling effort and the new drilling -- new development well drilling gives us an additional component, and that is how the production is maintained. You would be happy to note that till now as per the Q3, we have been able to maintain the production. And Q4, we expect that we will have an uptick in the production, having maintained it so far based on 2 aspects.

One, in comparison to last to last year and last year when we drilled 61 and 57 or 59 wells. This year, by this time, we have already completed 62 wells. Of course, this has got a mix of exploratory and development wells, but 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.

So, we are looking at surpassing the last year's highest ever 6.71. So how much, I do not wish to speculate, but having arrested the decline, we are definitely looking at touching those numbers. In addition to this, I would supplement as we speak, our current Daily production is hovering over 10,000 metric ton per day. That calculates about 77,000-plus barrels. And this is also supplemented by another achievement, which our Rajasthan field has actually started producing very well.

And all of you know earlier, we were doing about 100 to 200 to 400 barrels; today, we are doing 1,000 barrels per day from our Rajasthan field. And we have also recently completed one of the fastest well drilling in Rajasthan, just 23 days. So, these optimization efforts and operational efficiency gives us the confidence that we are on a right path to cross the last year's highest ever production outlook. I hope I have been able to substantiate my response.

Probal Sen:

Ranjit Rath:

That was extremely useful and detailed answer. One small follow-up, if I may. Earlier, I think it was mentioned that there are some pipeline connectivity timelines, which will basically drive the gas production increase because monetization can only happen with connectivity. You did mention about the pipeline connectivity for Numaligarh. If you can also give us some updates on where we are on the gas monetization pipelines and where we are in terms of those timelines?

Okay. I'll answer this. As far as the gas monetization effort is concerned, while we have identified gas wells, which will enhance our commitment to enhance production of natural gas,

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there are 2 things which has happened. We are now looking at laying additional infield lines to enhance or to handle the bottlenecks from a process point of view within the main producing area. That is one.

Second, as all of you would know, the feeder line needs authorization of the government. That process is underway. Once we have those notifications, I would prefer to apprise you, but I can tell you this is in an advanced stage. And after the PNGRB approval is done, it takes 18 months' time, and we have already planned our drilling program in a manner that we will be able to evacuate.

As far as the Duliajan-Numaligarh dedicated pipeline is concerned, current capacity is 1 million and we -- the planned capacity expansion is about 2.5 and the commissioning process is underway right now. We are hopeful that by April of 2026, that pipeline will also get commissioned. This will actually help us to supply more natural gas to Numaligarh Refinery. And with the hookup of IGGL line from Baihata, that is North Bank of Guwahati with Numaligarh pump station at Jorhat, should there be any further requirement once the DNPL is declared as a common carrier, we can push more gas as well.

Moderator:

Vivekanand S.:

We will take the next question from the line of Vivekanand S. from AMBIT Capital.

My first question is on the increase in contract cost. Is this increase only due to the GST change? Or is there any other factor here which has led to increase in contract cost to INR892 crores from, say, last year, INR500 crores and last quarter, INR520 crores? That is question one.

Secondly, thank you for the colour, Dr. Ranjit, on the exploration efforts as well as development wells. I wanted to understand from an exploration standpoint; Oil India has expanded its acreage very meaningfully as has the rest of the E&P industry in the last 2-3 years. And this has resulted in the company exploring many new areas like Andaman Basin. Is there any colour you can provide on new discoveries that one can look forward to?

Any time lines that you believe this project is yielding? And how much more effort will it need for you to come up with any new discoveries, which might be critical for your longer-term targets beyond the mission forward? Thank you very much.

Ranjit Rath:

First of all, let me thank you for asking these questions because through your questions, we get an opportunity to share our thoughts and insights of our E&P effort. And even if it is asked by one organization or entity, I'm sure the response is heard by others. So, this is what you have reaffirmed through your response also.

Now let me ask -- let me take the question on increase in contract cost. As part of our exploration effort, while we do rank exploration that I will cover in the second part, we undertake near-field exploration, which is primarily the exploratory wells drilled in the mining lease area and which supports the development drilling. So, the near-field exploration and development drilling, which happens to enhance our production has got a contribution to the

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reserve replacement ratio, which needs to be maintained plus or minus 1 and more than 1 is always better.

As part of our efforts in this near-field exploration and development drilling, you would appreciate today, we are having technology supported deeper horizon seismic imaging. Earlier, while we were drilling about 4,000 meters per well depth, today, our target ranges from 5,500plus meters. And we are establishing presence of hydrocarbon and in monetization. So, one part of the contract cost increase is the drilling of deeper wells.

Second, we have enhanced our drilling portfolio and our workover portfolio. When I say workover portfolio, that means we deploy more workover rigs and drilling portfolio, we deploy more drilling rigs. This adds to the contract cost.

Third, while we need to work on all this, we also need to supplement these release of locations by additional studies and extensive seismic data acquisition processing and interpretation. So, this also adds to additional cost. This is part of our production enhancement efforts.

In addition to that, now I will supplement my response to your second question. Today, Oil India has got an acreage of 1 lakh square kilometre out of which 50,000 square kilometre pertains to shallow water, deepwater and ultra-deepwater acreages. And as you know, we are currently drilling the third exploratory well in Andaman Nicobar.

And as we speak, the depth range is about 3,500 to 3,600-meter. We are going to go down to 4,200-meter. As far as our exploration in Kerala-Konkan Basin is concerned, we intend to drill up to 6,000-meter to trace presence of hydrocarbon in the cretaceous permissions. Now these additional efforts leads to the additional contract cost.

I must share with you another interesting development. In the month of May 2025, we got the deepwater blocks 40,000 square kilometre in 4 blocks Mahanadi and KG basin. As part of our exploration effort, we have already completed 4,200-line kilometres of 2D seismic and 50% of 3D seismic that is 5,300 square kilometre. This also adds to contract cost.

But most importantly, these data helps us to strategize our further exploration program, and this will also help us to strategize our efforts for securing more acreages in the OALP 10[th] bidding round, which is now extended till 29th of May 2026. I hope I have been able to substantiate with my response. Should you require, please let me know.

Vivekanand S.:

Ranjit Rath:

No, sir. This is very helpful. Just on the financial front, given the increased efforts on the exploration side, is this the new baseline in terms of contractual costs that one should assume for modelling?

Okay. Very good question, and this is -- I would also love to answer. Look, it's like this. As of today, we are deploying semi submersible rigs and jack-up rigs, which are primarily shallow water depth but deeper horizon. But this also includes a substantial component from our onshore drilling effort. Simultaneously, we are enhancing our efforts for undertaking exploration and drilling in the newly acquired Cambay Basin blocks and in Meghalaya.

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Cambay Basin block is a Category 1 basin. Meghalaya is a category 2 basin. We are also looking at additional expenses; I would call it as investment for substantively more drilling in our Rajasthan block. Now this gives a kind of broad outlook as far as onshore exploration and development drilling is concerned.

Next year, by now, we should have excellent clarity in terms of our deepwater drilling commitment. And the best part is while we would definitely be undertaking at least 3 to 4 deepwater drilling commitments, which will entail mobilization of drill ships, which will definitely be at a higher cost since we have not discovered the price, it will be premature for me to speculate any number.

But to give you a comfort, we have a collaboration with TotalEnergies, which is in the public domain to support our exploration effort. As part of that, the entire design basin adjunctions for seismic data acquisition and processing and interpretation will have the oversight of Total, which is an international oil company with adequately and extensive exposure in deep and ultra-deepwater drilling and exploration.

As part of the collaborative framework, there is a right of first refusal, which is available to TotalEnergies. Should there be any prospect identified out of the seismic API that we are doing right now for our deepwater block, TotalEnergies will also like to share the cost and share the risk. Therefore, we are currently not anticipating any specific issue as far as cash flow or additional contract cost is concerned.

Similarly, we are also reaching out to other international oil companies and national oil companies with exposure and expertise in deepwater and ultra-deepwater to secure derisk mechanism so that we not only look after the OALP 9 blocks that we already have acquired, we will also follow a similar approach for our OALP 10 bidding strategy. I hope I have been able to substantiate my response.

Moderator:

Sarthak Tita:

We will take the next question from the line of Sarthak Tita from DSP Asset Management.

So just sir, I had a couple of questions on -- and I would like to hear your views on that. So, first of all, like we had an understanding with BPCL on their new investments in the Andhra Pradesh refinery, right? So just wanted to get some viewpoint as to the reason behind us getting into that as a strategic investment? And what will be the percentage or what will be the collaboration that we are working on?

And secondly, sir, on our stand-alone operations of E&P, I just would like to know more about the production guidance for FY '26, '27 and '28 for both crude and gas, if you could provide some colour on that?

Ranjit Rath:

Okay. As far as our planned investment participation in the AP refinery, which is being steered by BPCL, we foresee that this will be a high-end refinery petrochemical complex, wherein we are looking at a 12 million metric ton and the refinery will have about 35% petrochemical intensity index.

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Now DFR for the same is currently being worked out, not only in terms of cost, but also the crude slate. So that we maximize the petrochemical component as well. Therefore, the cost estimates are still work in progress. As far as our interest -- evinced interest to BPCL is concerned, currently, it is in the range of 10% with a likely possibility, should there be any interest, we can enhance it.

But as of today, once we have clarity on the DFR and clarity on the overall cost, an appropriate decision will be taken. This is primarily to have an extension or an oversight in terms of our strategic diversification. Our main stay will continue to remain E&P for that matter.

As far as stand-alone E&P production is concerned, as I have already said, our target for 4 million metric ton and 5 bcm are contingent upon 2 things. One, the main producing area will provide us opportunities to drill more wells and do more workover. I would share with you that while this year, we are going to achieve 75 wells, the next year target is 100 wells as part of our strategy for both exploration and development wells. Now that gives me an outline of the number that we are looking at.

The number that we are looking at is this year, we will achieve to surpass last year's production, '24-'25 production. Year after, we are looking at a number, so I don't want to generally don't speculate. This is our internal estimate of likely prospects that we would target and bring it to the surface will be hovering around -- total production will be hovering around 7.5 MMTOE. And going forward, it will be 8 MMTOE.

We will be actually having one guidance. The crude oil production, 4 million metric ton would happen. However, natural gas production, though we have potential to produce from the current 8 million standard cubic meter per day to 13 million standard cubic meter per day. That will be actually contingent on the feeder line that we are all waiting for. And the DNPL line will provide an opportunity to evacuate also. So going forward, we are looking at something like 7.5 MMTOE. And should there be the evacuation in place, we would aspire to achieve 8.5 MMTOE FY 2028.

Moderator:

Bineet Banka:

Bhaskar Jyoti Phukan:

Bineet Banka:

We will take the next question from the line of Bineet Banka from Nomura Wealth.

I have a couple of questions on the NRL refinery part. So firstly, how much of the refinery current crude intake is coming from the local sourcing? And what is the cost difference if you procure the crude locally versus importing?

We are getting almost 100% crude from local field of Eastern Assam, but a very small quantity is also coming through Haldia through import route, and we are transporting from Haldia to Numaligarh by rake. That constitutes around 50 KTPA, whereas all the rest, 3,000 KTPA crude is coming from the Upper Assam oil field. And actually, we are benchmarked to international prices. And the prices which was indicated initially in the presentation is the price that we are actually giving to Oil India. So, it fluctuates with international prices.

So, there is a differential logistic cost logistic cost will be higher if you are importing and using pipeline to transport. So, what could be that differential?

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Bhaskar Jyoti Phukan: See, pipeline transportation cost typically is INR0.50 per ton per kilometre. And you also have the luxury of importing crude, which are cheaper than what we are getting today because our refinery, we have configured in such a manner that cheap crude can also be processed. So, delta typically can range from $2 to $4 if you can actually appropriately source crude, which you can process but are cheaper in the market. So that leverage will always be with you. And actually, you will end up in the same sort of product because you have a very complex process in place as far as new refinery is concerned. So therefore, whatever additional logistic cost that we will incur in terms of getting crude into our refinery will be compensated by the lower crude cost of procurement. So, did I answer your question? Bineet Banka: Yes, sir. Just another question on the same NRL refinery, sir. So, what was the reason you had like very high refinery GRM $16 in this quarter? This is much higher than what the other OMCs have reported? Bhaskar Jyoti Phukan: See, actually... Ranjit Rath: Are you not happy? Bhaskar Jyoti Phukan: We are very happy. I would like to explain. See, we are mostly -- the current refinery is mostly a diesel refinery. And diesel refinery diesel margin was very, very high. Actually, at times, it went to as high as $24, you may have seen in the third quarter. So therefore, our almost 65% to 70% product is diesel. So therefore, we have a head start vis-a-vis our peers as far as refining margins are concerned only when the diesel margins are higher. So that is the simple answer that I could have given. Ranjit Rath: But that is a modest answer. Let me supplement this. The refinery is running 100% plus capacity and the best yield in percentage term also. So, these 2 things have also added to the performance -- physical performance of the refinery. So, one is the crude oil price, which is subdued to the spread that one gets in HSD. And most important is the performance of the refinery. Bineet Banka: Okay, sir. Got it. Just last one on the NRL only. So, what is the total debt on NRL balance sheet? And what will be the debt when all the capex is done, I think over the next 1 or 2 years, including the petchem plant? Bhaskar Jyoti Phukan: I think the... Ranjit Rath: About INR16,000 crores. Bhaskar Jyoti Phukan: Yes. It is around INR16,000 crores. And by the time we end all the projects, including petchem, it should be around INR25,000 crores to INR26,000 crores. Moderator: We will take the next question from the line of Nitin Tiwari from PhillipCapital India.

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Nitin Tiwari: Sir, staying on the question of contractual cost, the explanation that you gave is a rather structural one where like your incremental exploration and development effort is leading to perhaps a higher cost. But I'm interested in knowing what specifically happened in this quarter because in this quarter, your contractual costs were higher by about 70% to 71% on both Y-oY as well as Q-on-Q basis. And as the earlier participant also asked that is this the baseline that we should consider going ahead?

Ranjit Rath: Okay. I'll give you a bit more elaboration. This month, we have already drilled the equivalent number of drilling that we had done last year. And this is just 62. We are going to drill another 12 to 15 wells. So, this is the additional cost which is coming on the way because these are all monthly payments. So, this will accrue. That is how the higher contract cost is concerned.

Second, I will reiterate, we are now drilling deeper. So, when you drill deeper, it is not a linear complexity. The drilling rigs come with an operational day rate, but the complexity increases, the geological complexity increases. Therefore, that also add to a prolonged drilling duration. Third, when we deal with mature fields, the workover duration also increases. So, these are those contract costs which has actually come in, in the Q3.

As far as specific response, if you are looking at a benchmarking, I would suggest that's what I had given an elaborate answer that this could continue to be the benchmark with the onshore and the current offshore -- shallow offshore drilling that we are doing. There will be a slight uptick in terms of benchmarking year after when we will undertake the deepwater drilling, but that would also be hedged with international collaboration. So, from a safe assumption point of view, the current numbers could be benchmarked.

Nitin Tiwari: So, sir, if I understood this right, because your working hours have increased. So, have you deployed more rigs in this quarter, which has perhaps added to your higher working hours and also higher contractual cost? Ranjit Rath: Okay. I'll now -- let me take some credit here. This activity, please understand, Oil India was drilling only 30 to 35 wells -- 2 to 3 years ago. The same manpower, we are delivering more drilling because of 2 - 3 things. One, our operational efficiency has gone up substantially.

Two, we are drilling more wells and more deeper wells by standardizing an SOP where the drilling rigs and then the interlocation movement is seamlessly practised. Third, the waiting on period of the bundling services for testing is also planned in a very meticulous manner. Fourth, the plinth which is created for carrying these drilling activities, whether it is a 2,000horsepower rig, 1,400 horsepower rig or a 3,000-horsepower rig are standardized. Fifth, the movement between the workover rig coming in or the testing protocol that we need to do for early monetization has also been improved. So, all these actually giving us an opportunity of cost optimization and operational efficiency.

Nitin Tiwari: Okay. Fair enough. Sir, secondly, again, a clarificatory question on the production guidance that you gave. You mentioned 7.5 million tons and 8.5 million tons equivalent in '27 and '28. So, if we look at like the crude production in '26 is going at a run rate of about 3.4 million tons

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	annually. So, if we can get to specifics in terms of what you are targeting for '27 and '28 in
	terms of crude production? Gas, I understand you said it's contingent on connectivity and other
	aspects?
Ranjit Rath:	Crude production -- if we are able to drill 100, and I can assure you we are going to drill 100
	wells, we would aspire to touch 4 million next year. But...
Nitin Tiwari:	In '27?
Ranjit Rath:	In '27. But on a conservative side, we are planning or we have indicated that we would do 3.8
	in 2027 and 2028, we'll achieve 4. That also will have risen because when the drilling happens,
	the buildup towards production comes in the last quarter. So, there could be a situation that we
	would sleep over beyond the FY 2027. Therefore, the outlook that we have given to ourselves
	is in the order of 3.8 and 4.0.
	But in case we are able to drill 100 plus or 100 wells and year after another 100 with the
	number of drilling rigs that we have planned, number one. Number two, we will have more
	3,000-horsepower rig in our fleet. Number three, we will have a couple of new rigs joining the
	fleet. Therefore, we are planning that 100 numbers to be drilled and to be able to produce.
Moderator:	We will take the next question from the line of Vikas Jain from CLSA.
Vikas Jain:	So the scenario that you're painting is, of course, there is a lot of excitement in terms of
	activity, which you most likely will possibly end up drilling 3x the number of wells and you've
	been able to get some efficiency without much increase in manpower and some of these other
	costs. But in that scenario, what I want to understand is that would obviously mean more costs,
	but these costs will be largely what seismic-related costs which would show up in terms of
	other expenditure for this period. And obviously, these are costs that we -- that might show up
	today, but it will lead to higher production later. That's the kind of thought process that how
	we should be thinking about, right? Is that the right understanding?
Ranjit Rath:	Excellent. I think you were bang on. I'm so glad that you have summarized your assessment so
	rightly.
Vikas Jain:	Okay. Sir, so in that context, could you just give me what has been the seismic cost for, say,
	3Q and 2Q as well and the 9 months that we have because that's part of the other expenditure,
	right?
Ranjit Rath:	Okay. I'll just dig out because I'll have to dig out exact number, what is the seismic cost.
	Where is that? Okay. The seismic cost number towards seismic data acquisition is about
	INR580 crores that I'm given to understand, and 9 months is INR1,151 crores.
Vikas Jain:	And the 2Q was?
Abhijit Majumder:	Excuse me, what is the other question?
Vikas Jain:	2Q.

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Abhijit Majumder:	So, the quarter 3 number is INR579 crores, and quarter 2 number is INR321 crores.
Vikas Jain:	Okay. Understood.
Abhijit Majumder:	These are ultimately variable parameters, the more you drill, the more deep you go, your cost
	would naturally go -- it will increase.
Vikas Jain:	Obviously. And sir, so in terms of this activity that we are talking about, there will, of course,
	be development wells, which will be largely capitalized till production come in, but a lot of it
	will also be even exploratory wells. These would show up other than seismic, where would this
	be? Would this be broadly bunched up? These would also come up in terms of higher
	exploration write-offs in terms of dry well write-offs. Is that the reason why your 9-month
	number is almost getting closer to INR2,000 crores?
Abhijit Majumder:	Yes. I mean, see, exploration appears under the exploration and evaluation costs. So, there is a
	separate line item under which it would appear. And once you -- it becomes a development
	asset, then it would move from E&E to development, which you will finally capitalize. Till
	such time, it will remain there as E&E asset because this is an ongoing activity. And till the
	time you really turn it into a producing asset, it will remain there as E&E.
Vikas Jain:	Sure. So, I think these will be the 2 elements? Or is there something else that I'm missing other
	than seismic and...
Abhijit Majumder:	Other than this, it'll be G&G, which is my seismic, survey expenses, et cetera.
Vikas Jain:	Yes. So, the seismic and survey expenses are the numbers that you gave us, INR1,150 crores,
	right? That's the one that you gave us.
Abhijit Majumder:	Yes, that's correct.
Ranjit Rath:	Yes. Gentlemen, I'm sorry. I had to step out. See, the -- when we look at these numbers, my
	suggestion to all of you would be the activities in the field are weather window driven. When
	we talk about seismic data acquisition, during the monsoon, the work comes to a standstill. So,
	you would appreciate when we look Q1, Q2 and Q3, the expenses incurred as part of our
	contract cost would never be equal or even equivalent. Therefore, in fact, when we discuss
	this, and I must share with you these numbers within the ambit of our Board, we take
	cognization of the fact that considering the Northeast region that we operate in, considering the
	necessity of a fair weather window in which we do the seismic API, these numbers would also
	reflect in the respective quarter.

However, when we look at these numbers on an annualized basis, that gives us a clear picture, both in terms of our enhanced effort, enhanced deployment of resources and a number which is annualized. So Q1, Q2, Q3 comparison as far as these activities are concerned are based not update. So, I hope I have given a kind of a clarity on the concept.

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Vikas Jain: Sure, absolutely. Obviously, I mean, so Q3 and Q4 might have more fair-weather window, so that might have more activity over there, obviously? Ranjit Rath: Exactly. Vikas Jain: So just to kind of -- for comparison's sake, like last FY '25 from what I can see, your total seismic cost was about INR750 crores and your total E&P dry well write-off was about INR650 crores or so. So those numbers? Ranjit Rath: One second, I'll take down your number first. What you said, I'm glad that you are doing this granularity. Seismic, you are saying how much? Vikas Jain: Sir, this is from what you had reported, I think, INR750 crores? Ranjit Rath: No problem. I will take it from you. I accept it because that helps me to crystallize my thoughts. Please go ahead. Vikas Jain: Sir, INR750 crores and INR650 crores, roughly, I'm rounding it off, INR750 crores is? Ranjit Rath: No problem. Vikas Jain: And INR650 crores is dry well write-off. So, these number, what -- how should we think of FY '26 and '27 in terms of where these will go up to? Like FY -- 9 months has already become nearly INR2,000 crores for dry well write-off. This should continue in a similar 3Q kind of number run rate for 4Q as well and seismic also a similar kind of number like 3Q? Ranjit Rath: Can I get your name, please? Vikas Jain: Vikas, sir. Vikas. Ranjit Rath: Vikas, I'm so glad that you are asking these questions in so granularity because this gives me an opportunity to share my thoughts. In an E&P operation, while we undertake efforts for enhanced exploration, we also are prepared to write-off wells as part of the Ind AS guidelines, okay? That's one.

Second, when we look at exploration activities, I would share with you, normally, exploration activities are never linear. It is having some kind of an overlap. The process is, first, you do a bit of seismic, then you do drilling, basis your drilling, you do post-drill analysis, you do a tiein study, then you bring in a supplementary seismic, then you decide a couple of more drilling to be done.

In between, you do a back analysis of your data, run your dynamic modelling, then you bring in infill wells to enhance your production and also enhance your recovery rate. 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, number one.

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Number two, you would appreciate that the work in progress as part of development well and in case of exploratory wells, where we anticipate that there is certain horizons which could possibly be tested are caved as work in progress. One example, the first well that we have drilled in Andaman Nicobar, we have drilled up to 3,600 meters.

And we have -- we are carrying that well as a work in progress because we intend to do testing in certain horizons that we have established as part of our geophysical logging that we have carried out. Only after obtaining the test results, we will take a call to write-off.

But one thing for sure, as part of the Ind AS mechanism and in the governance criteria, the incidents are reported instant basis within the same quarter. You do not have the opportunity to defer should an incident happen in that quarter. So, while it will be difficult for me to indicate a number of dry well costs that we might report, you will have to bear with me with this clarity that I'm trying to offer.

Vikas Jain:

Sure. No, I fully appreciate that. I mean, finally, exploration, there is an element of chance and predictability can be difficult. But I mean, my motive of asking that question is to get a sense that activity levels would be similar to where they are today for all of FY '26 and FY '27. That's the right way I should be thinking about it.

Ranjit Rath: Okay. I will give you an answer -- supplementary answer to this. I'm so glad that you are asking these questions because through you, I have been able to share my insights. As an E&P company, we would like to have enhanced activity. When I mean enhanced activity, that means our exploratory efforts, both near-field exploration and development well drilling has -- is resulting or giving us more as we call our sand horizons or target horizons.

If we get more target horizons, it gives us more activity, gives us more perforation, gives us more workover and leading to more production. So, we are happy with more activities. We are very unhappy when the well goes without any activity.

Vikas Jain: Sure. Sir, just shifting gears a little bit and one last thing before I know I've taken a lot of time, but hopefully, we've been [inaudible 1:04:20] important?

Ranjit Rath: Please do.

Vikas Jain: Is on Numaligarh, we did -- I mean, it was mentioned that we will hopefully get to 50% utilization of the CDU and VDU. But typically, the bigger gains for refineries would come when the upgrader units operate and that's when distillate yields increase and that's when refining margins increase. So how should we think about operating at higher, at fuller -- the right utilization levels for the overall refinery?

Number one. And when will the Petrochem expansion start kicking in, you could go by quarter-by-quarter, say, 1Q, 2Q of next year? I mean, when should we start seeing the right refining margins ex of petco, petchem start kicking in with all upgrader units operating?

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Bhaskar Jyoti Phukan:

See initially, I told that we will be operating our refinery, the whole complex by end of next year, last quarter of next year. And we hope to achieve 50% capacity utilization on a daily basis during that quarter. Going forward, next quarter, obviously, our effort will be to go up on that 50% utilization to say, around 75% then gradually going up to 100%. So, you will see a gradual uptick in the capacity utilization of the new complex that we have built up starting from Q4 of FY '27 and continuously going up to, say, Q2 of next financial year thereafter, that is FY '28.

And during FY '28 towards the last part, we should also be commissioning our petchem project. Petchem is a single unit. So, once it is commissioned, that means it is commissioned and gradually, the product will start tickling in. Maybe at the first quarter, we will not be able to achieve 100% of capacity run. But gradually, it will ramp-up in 2 to 3 quarters, we will be able to go to 100% capacity utilization.

So, to summarize, in Q4 of FY '27, we will be at 50% daily capacity utilization and going up to 100% by Q2 of FY '28 and petchem will start by close of FY '28 and we will be achieving its full capacity by, say, Q2 of FY '29. So that is the outlook that I would like to give you at this moment.

Moderator: We'll take our next question from the line of Gaurav Jain from ICICI Prudential Mutual Fund. Gaurav Jain: Just one question from my side. If you can share, sir, region-wise split of the 60 wells that we would have drilled till now, how many of them are in, say, Northeast? How many are in other geographies, etcetera? That will be helpful.

Ranjit Rath: Give me 1 minute. I'll tell you -- I'll give you a construct. See, you all know that the main producing area for Oil India Limited is in Arunachal Pradesh and in Assam, okay? And by 9- month of FY 2026 in Assam and Arunachal Pradesh, we have already drilled 38 wells. And in Rajasthan, we have drilled 10 wells.

That is the next producing field. By end of this year, we would attempt to drill 65 wells in Assam and Arunachal Pradesh. Rajasthan possibly would give us another 2 or 3 wells. But overall, since we have got exploratory wells being drilled in Mahanadi, exploratory well being drilled in Kerala-Konkan, exploratory well being drilled in Andaman, the DSF block in Tripura and in Rajasthan would also have a couple of drillings. So, we are looking at a total of 75.

Gaurav Jain: Just a follow-up on this, sir. What we understand is, sir, we have evacuation challenge on the gas side because of connectivity issues. But then the crude growth is also, sir, lackluster than what we have been expecting. And then if we are drilling more wells and those fields or those wells are more of associated fields where both gas and crude would be there and then the evaluation of gas will be a challenge?

So if you can help us understand that dynamic, sir, that how comfortable are we to expect that crude will grow, whereas gas will grow with a lag because of connectivity issue and these

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wells that we are drilling has to be then crude only maybe so that we can take out the crude? Where are we wrong in understanding this, sir?

Ranjit Rath:

Okay. I'm so glad you are asking the granular questions. Let me give you a perspective. When we drill, we really look at hydrocarbon because the signatures tell us presence of hydrocarbon. After the testing is done, we establish the sand horizons and then we establish whether it is a crude oil with associated gas or dry gas, okay?

Now the question is, in earlier cases, we were actually flaring those associated gas. 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. That is one piece.

The second is we have recently, and all of you know, have built a pipeline from Kumchai in Arunachal Pradesh to Kusijan in Duliajan that is nearby, which is helping us to evacuate the natural gas, which was getting flared from Arunachal field, and that is also giving us a boost in the crude oil production.

The third piece that we have done is we have already established a possibility of gas storage in one of our fields by converting a compressor as an injection pump. So, in case we are getting associated gas and there is an evacuation constraint, we are actually -- we have injected the gas back to the system, which can be withdrawn once the pipeline connectivity is done.

The fourth is recently in one of our westernmost fields that is in Lakwa gaon, we have converted a crude line to a gas line. And that way also, we are kind of planning to evacuate natural gas or associated gas, helping us to maintain the crude oil production. The best part of crude oil, you have appreciated, evacuation is easy. Therefore, we are confident that we will be able to maintain the outlook that we have aspired to.

Moderator: Next question is from the line of Sabri Hazarika from Emkay Global Financial Service.

Sabri Hazarika: Two questions. Firstly, on this capex front, what we have noticed is that I think 9 months stand-alone capex is somewhere around INR8,500 crores, so which is in line with the full year guidance. So, for this year, would we be overshooting the guidance?

Ranjit Rath: The more we do the activity, the more the capex that you would appreciate. We would -- we had planned a certain amount of capex, and we would actually surpass that number this year. That is actually to supplement our efforts for production. So, the number that we have indicated for '25-'26 is INR8,800 crores, but given the numbers that we have seen yesterday as part of our Q3, it would be increasing.

Sabri Hazarika: Okay. And next year also would be like similar, or higher than the INR8,500 crores, INR8,600 crores that you have given?

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Ranjit Rath: It will be in that order because it would actually help us, but I would actually have a caveat here that since next year, we'll have more drilling rigs, we'll drill more wells, the capex would definitely have an upswing. So, we will readjust our RE once we have a line of sight after Q1 of 2027.

Sabri Hazarika: Okay, sure. And NRL, how much has been the financial progress? How much capex has been done?

Bhaskar Jyoti Phukan: This year, capex outgo so far has been around INR6,000 crores, and we will end the year with INR8,000 crores. And our capex -- total capex, both the refinery and petchem put together is INR45,000 crores. And there are smaller projects also included there actually. Sabri Hazarika: Right, sir. And second question is on this Andaman field. So, we have done -- we have drilled 2 wells, and we have taken some write-off also. So right now, are we done with -- I mean, have we written off whatever is required in Andaman field? Or is there something pending? And what is the next drilling plan? You said third well. So, when is it expected to be done? And how many more wells in the near-term you have made plans about? Ranjit Rath: I'm so glad. Okay. So, Andaman, I'll give you a perspective. Andaman are the OALP blocks. We have 2 blocks, 9,000 -- I think 10,000 square kilometre, 1 block on the east side, 1 block on the west side. We had initially planned to drill 4 wells in Andaman shallow water. The first well was drilled up to 3,600 meters.

We are carrying that well as work in progress from a finance point of view because we intend to carry out some testing activity. The second well, we drilled up to 2,600 meters, and we undertook a site track. And then we tested the well in the site track that is called A Well and the site track well established presence of hydrocarbon.

As far as Ind AS is concerned, even if you are doing site tracking, the mother well have to be written off. And following that principle, we have written off the component of the second well. The third well, we are actually under drilling right now, which is currently at around 3,300, 3,400 meter. We are going to drill the fourth well on the northwest side of Andaman block, but the story doesn't get over here.

Having established the presence of natural gas in the second well at a depth of 2,200 meter, we have already initiated the appraisal process. The appraisal process entails reprocessing of the 2D seismic data that has already been completed. Next, followed by 600 square kilometre of 3D seismic in that same area to establish the structure and then the extent of the structure.

Third, that activity, we have already initiated. The mobilization will commence. After the 3D seismic of additional 600 square kilometre, we intend to drill an appraisal well. So that will be the fifth well in Andaman Nicobar. So that's the Andaman story.

And just last one small question. You mentioned that currently, the crude oil production run rate is around 10,000 metric tons per day. Is that right?

Sabri Hazarika:

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Ranjit Rath:	Yes.
Sabri Hazarika:	And what would be the equivalent gas production current in MMSCMD?
Ranjit Rath:	Give me 1 minute. I'll just take out my daily production report. I'll tell you as of today. Okay.
	As of today, we have done how much? 8.597 million standard cubic meter per day.
Sabri Hazarika:	That's natural gas. And crude oil as of today?
Ranjit Rath:	Crude oil, as of today, we have done 7,288 barrel. That works out to 10,029 metric ton.
Moderator:	Next question is from the line of Somaiah V. from Avendus Spark.
Somaiah V.:	So, first question is on the Paradip-NRL pipeline. So how much kilometre is still left? And
	what is our expectation by when this will get completed?
Ranjit Rath:	I'm sorry, I could not get your question. What is that kilometre...
Moderator:	Sorry to interrupt. Somaiah, can you use your handset, please? Your audio is not clear.
Somaiah V.:	Yes. I hope I'm audible now.
Ranjit Rath:	Yes. You are.
Somaiah V.:	So, my question was how much kilometre is still left in that Paradip-NRL pipeline?
Ranjit Rath:	Okay. Very good. So PNCPL is about -- not about, 1,635 kilometre. The ROU so far have
	already opened is 1,600 kilometre. The balance ROU that we intend to open, which is spread
	across states is about 40 kilometre. And you would appreciate about we are going to travel 5
	states, Odissa, West Bengal, Jharkhand, Bihar and Assam. So, in some -- in all the states, the
	small, small ROUs are left. Otherwise, we are on track as far as our production or the ROU
	opened is about 98%. The lowering is about 92% that is completed.
Somaiah V.:	Okay. Sir, so we don't see this as any impact. For instance, we want to ramp-up the utilization
	on the refinery -- expanded refinery front. So why then, we expect this to be fully completed?
	So, we don't see any risk of this getting delayed. So, I just want to have a confirmation?
Ranjit Rath:	No, we don't see any bottleneck as of the pipeline is concerned. We have got excellent
	interaction with the state government for these remaining ROUs, and we do not foresee any
	constraint.
Somaiah V.:	Got it, sir. Second question, sir, is on the capex front on NRL. So, of the INR45,000 crores that
	we mentioned for the project, so far, what have we spent? And the remaining amount, what is
	the profile -- the spend profile in next couple of years?

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Ranjit Rath:	See, the project, you would have heard already, we are looking at completing the project and
	taking complete 100% capacity utilization by Q2 of FY '28, but the mechanical completion
	would necessarily happen before Q4 of FY 2027, okay?
	Now as far as the capex is concerned in terms of NRL, so far, we have done a debt of about
	INR16,000 crores, if my numbers are correct. That has been already drawn. And as far as the
	overall capex is concerned, we are looking at INR34,000 crores as far as NREP is concerned.
	And how much is the equity, let me -- other total is INR45,000 crores as a ballpark number.
Somaiah V.:	Sir, I was just looking for next couple of years, what will be the capex that NRL would be
	incurring to complete the project?
Ranjit Rath:	Actually, after next year, we don't foresee any major capex. The capex that will spread over
	beyond next year is the polypropylene unit, which would actually be at the peak. And
	polypropylene unit is about INR7,200 crores. So that's the spread.
Somaiah V.:	Okay, sir. Sir, a couple of questions. One on net debt at consol level. So, what would be the net
	debt? You gave NRL number also on the stand-alone as well as the international ops. And
	also, if you could give some colour on international...
Ranjit Rath:	I'm sorry. What is that you are asking? What is that?
Somaiah V.:	Consol net debt number, sir. Consol net debt?
Ranjit Rath:	Net debt, I'm sorry, INR34,000 crores.
Somaiah V.:	So, this is the consol level, including INR16,000 crores at NRL?
Ranjit Rath:	Yes. Let me give you a breakup. It is INR16,000 crores at NRL level. It is INR16,000 crores at
	Oil India level. The INR16,000 crores in Oil India level is primarily the external commercial
	borrowings for our overseas assets.
Somaiah V.:	Sir, last question on the overseas assets. If you could just give some colour on the performance
	and dividend status.
Ranjit Rath:	Dividend, you all have already taken note of the announcement that we have done. In terms of
	our dividend declaration, the Board took a very considered view that we must protect the
	interest of our shareholders. Therefore, we having got a balanced number as far as the
	consolidated that where we have maintained the PAT that you would have already reported.
	We have maintained the same dividend in terms of our announcement. First, it was INR3.5 per
	share. Yesterday, we have announced INR7. That brings it to INR10.5 per fully paid
	authorized share. So that is the dividend declaration, which I have to offer right now.
Somaiah V.:	Sir, my question was on the dividends that we need to receive from the international, the
	Russian assets. So, any update on that?

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Ranjit Rath: Okay. Okay. So as far as Russian asset is concerned, we have got 2 assets. One is TaasYuryakh and one is Vankor. Now when I say Taas-Yuryakh and Vankor, both our exposure is about USD 1 billion. As far as Taas-Yuryakh is concerned, we have got 100-plus percentage dividend backed. As far as Vankor is concerned, it's about 90%. Somaiah V.: Any dividend that is still there, which are yet to receive or so far, we've got -- whatever that's been declared, so far, we have received it? Ranjit 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. Moderator: Next question is from the line of Moksh Ranka from Aurum Capital. Moksh Ranka: I wanted to ask -- could you please provide some colour regarding the Northeast gas pipeline connectivity? Could you provide some colour on that? Ranjit Rath: Okay. I'll share that. The thought process is the main line, which goes from Urja Ganga led by GAIL, the line has already reached Baihata, that is the north bank of Guwahati and the pipeline is crossing Brahmaputra River to go to Guwahati. That is one.

Second, the Northeast grid -- Northeast gas grid, which is supposed to connect to the gas sources and then the capital of Northeast, first phase is from Baihata to Numaligarh, where the river crossing of Brahmaputra at Majuli in Jorhat and then it goes to Numaligarh. That line is fully completed.

Then the segment lines of connecting it to the respective capital are work in progress. You would appreciate the terrain is so difficult that NEGG is taking some time. But what is more important is the evacuation possibility from the main producing field that is the Duliajan or the main producing area of Oil India and ONGC and other small gas field operators.

We have got a dedicated pipeline called Duliajan-Numaligarh pipeline. The capacity upgradation of that pipeline is underway. We are looking at 1 million standard cubic meter per day of today to 2.5 and the mechanical completion is already over. The commissioning work is under progress. We should be able to have the pipeline commissioned by April 2026. Utilizing this pipeline, Oil India gas can reach and cater to the enhanced gas requirement of NRL that is one.

Moksh Ranka: Okay. And is this Duliajan hub going to integrate with the IGGL? And by when can we expect that also?

Ranjit Rath: I think there is some disturbance. The Duliajan feeder line is just waiting to be approved by the government once the authorization is communicated to IGGL, that is Indradhanush Gas Grid Limited. It will take about 18 months because it does not entail any major river crossing. So that would actually give us an opportunity of evacuating 3.5 million standard cubic meters of gas per day.

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Moderator: We'll take our next question from the line of Keshav Soni from Kotak Securities. Keshav Soni: Can you please share the stand-alone capex guidance for FY '26, '27 and '28? Ranjit Rath: Stand-alone capex for this year for Oil India? Keshav Soni: This year and '27, '28, yes, for Oil India? Ranjit Rath: Yes, it is INR8,800 crores. Going forward, it will hover around the same number or it will catch base about INR9,200 crores plus.

Moderator: As there are no further questions, I now hand the conference over to management for closing comments. Over to you, sir.

Ranjit Rath: First of all, thank you very much for this opportunity to interact with our colleagues, with our friends and our investor community, our shareholders, our analysts. It's always good and great to interact because this gives us an opportunity to reach out to the people who matter as part of our insight sharing, as part of our strategy sharing, as part of our growth story sharing. So, I hope we have been able to answer or respond your queries or questions or feedbacks reasonably well. And we are open to any further interactions at any point of time. Please feel free to reach out to us.

Thank you very much once again. While you have continued your trust in Oil India Limited, we will look forward to having such reposed faith and trust in Oil India's performance for days to come and years to come. Have an absolute and excellent day ahead. Thank you very much.

Moderator: Thank you, members of the management team. On behalf of Antique Stock Broking Limited, that concludes this conference. Thank you for joining us, and you may now disconnect your lines.

Ranjit Rath:

Thank you.

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