Good morning, ladies and gentlemen, and welcome to the Oil India Limited Q3 FY 2026 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 call, please signal an operator by pressing star then zero on your touchtone 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.
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 of Finance, Mr. Yombo Saloma, Director, Exploration and Development, Mr. Trailokya Borgohain , Director of Operations, Mr. Bhaskar Jyoti Phukan, MD, NRL, Mr. Ajay Kumar Sahu, 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's on the call. I'll hand over the call to him for his initial remarks. The floor is yours, sir.
Yes, Abhijit.
Good morning, ladies and gentlemen, 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 am Abhijit Majumder, Director of Finance. I am joined today by Dr. Ranjit Rath, Chairman and Managing Director, Oil India Limited, and my colleagues from Oil India Limited, Mr. Yombo Saloma, who is traveling today. So in his place, Mr. D.S. Mangal will be representing the Exploration and Development department. Mr. Trailokya Borgohain , who will be joining soon. Mr. Bhaskar Jyoti Phukan, MD, NRL. Mr. Ajay Kumar Sahu, 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 three FY 2025-2026 earnings call, covering the period first of October 2025 to December 31st, 2025. The financial results were approved by the board and duly published on February 10th, 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.
Good morning, everyone, and I thank you, all of you for joining us on this call. Please, bear with me because of my sore throat. I will try to adjust and will 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. 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 tonnes per annum-...
to 5.5 million metric tons per annum, has already achieved mechanical completion, and we are in the process of completing the complete commissioning process. The Duliajan-Numaligarh pipeline expansion from 1 million to 2.5 million, has already achieved mechanical completion on November 15th, 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 nine months of FY 2025-2026, our performance reflects this approach: a steady operational execution, continued progress on drilling and development activity, and financial discipline. On the financial front of nine months, our consolidated revenue stood at INR 27,036.78 crores, EBITDA at INR 9,298.62 crores, and a PAT of INR 5,126.21 crore. On the operational side, our combined oil and gas production for nine 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 performances.
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 thirty-first of December 2025 is, the combined oil and gas production for Q3, it is 1.659 million metric ton, and for the nine 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-over-quarter. The crude oil daily production has ramped up to 9,861 metric ton on thirty-first 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 has experienced minimum degrowth, driven by reduced offtake from major customers, such as Ram, 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 2025-2026. On the exploration and development front, progress has remained strong. Our company has drilled 19 new wells during the quarter. Cumulatively, for the nine-month period, 51 wells have been drilled, which we have achieved 65% of our annual target.
The key financial highlights for this quarter, as with the period of the nine months ended thirty-first of December 2025, are: the average price realization for Q3 FY 2026 was $62.84/bbl .... is $73.8/bbl in Q3 of FY 2025. For the nine months ended thirty-first of December 2025, the average crude oil price realization was $65.73/bbl , versus $79.35 /bbl in the previous nine 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 nine months. The natural gas price stood at $6.65 per MMBtu in Q3 of FY 2026, versus $6.56 per MMBtu in Q3 of FY 2025.
The standalone operating revenue for Q3 FY 2026 is INR 4,916 crore, and for the nine months, it is INR 15,385 crore. The EBITDA margin for the Q3 of FY 2026 is 33.96%, as compared to 34.82% of Q2 of the current year. The profit after tax for Q3 is INR 808.31 crore during the quarter. Our EPS stood at 16.39 per share for the nine months ended of FY 2026. I take this opportunity to share the performance of our material subsidiary, Numaligarh Refinery. The operating revenue is INR 6,526 crores for Q3 FY 2026, which is at par of the previous year.
Further, during the nine months, the operating income is INR 19,249 crore, which is 5.67% higher as compared to the previous year. The capacity utilization of our refinery is 100.31% in quarter three of FY 2026, and the distillate yield for the quarter was 86.8%. The gross refinery margin, excluding excise duty, is $16.27 /bbl , which is up by 54% versus Q2 of the current year. The EBITDA is INR 1,302 crore for Q3 of FY 2026, versus INR 611 crore in Q3 of FY 2025. The PAT is INR 867 crore for Q3 of FY 2026, versus INR 385 crore of Q3 FY 2025. I'd like to present the consolidated financial results of our company.
Our company has reported the consolidated operating revenue of INR 9,111 crore, and registered a PAT of INR 1,436 crore during Q3 of FY 2026. Both the consolidated operating revenue and PAT are in line with Q3 of FY 2026. We are pleased to inform you that the company has declared a dividend of INR 7 per fully paid equity shares during our period closing of December 31st, 2025. Our company has delivered a resilient and a disciplined performance in the third quarter of FY 2026, supported by our operational stability and strong 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.
Thank you very much. We will now begin the question and answer session. Anyone who wishes to ask a question may press star and one on their touchtone telephone. If you wish to remove yourself from the question queue, you may press star and two. Participants, please use handsets while asking a question. Ladies and gentlemen, we will wait for a moment while the question queue assembles. We have the first question from the line of Probal Sen from ICICI Securities. Please go ahead.
Thank you for the opportunity, sir. I hope I'm audible.
Yes, you are audible.
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 2027, therefore, what kind of throughput should we be looking at for NRL?
Yes, yes.
Yes, I'm MD, NRL. So, during the last quarter, actually, we expect to have a serious run of the whole refinery complex.
Mm-hmm.
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.
Mm-hmm.
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 2027, with a 4 million capacity, throughput.
Just to add. Yeah, 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 it could have 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.
Understood, sir. Understood. The second question was with respect to, of course, the volume growth. You did mention that, the nine-month Oil India's 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 2027, 2028? Any color 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 productions while we arrest the decline of pressure or performance by 8%-10%. All of you know that.
Mm-hmm.
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 of the Q3, we have been able to maintain the production. And Q4, we expect that we will have a uptick in the production, having maintained it so far, based on two aspects. One, in comparison to last to last year and last year, when we drilled 61 and say 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+ 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. Now, 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+ bbl, 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 100-200-400 bbl. Today, we are doing 1,000 bbl/d from our Rajasthan field, and we have also recently completed one of the fastest well drilling in Rajasthan, just 23 days.
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.
Thank you, sir. That was a extremely useful and detailed answer. One small follow-up, if I may. Earlier, I think it was mentioned that there are some pipeline connectivity, you know, timelines, which will basically drive the gas production increase, because monetization can only happen with connectivity. You did mention-
Sure.
about the pipeline connectivity for Numaligarh. If you can also give us some updates on where we are on the gas monetization pipelines and, you know, 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, there are two things which has happened. We are now looking at laying additional infill 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. 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.
Thank you, sir. That is extremely useful. I'll come back with more questions on this.
Okay.
Thank you. Ladies and gentlemen, in order to ensure that the management will be able to address all the questions from the participants, we request you to kindly limit your questions to two per participant. If you have a follow-up question, please rejoin the queue again. We will take the next question from the line of Vivekanand S. from Ambit Capital. Please go ahead.
Hello. Thank you for the opportunity. 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 INR 892 crore from, say, last year INR 500 crore, and last quarter INR 520 crore? That is question one. Secondly, thank you for the color, 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 two-three years. And this has resulted in the company exploring many new areas like Andaman Basin.
Is there any color you can provide on new discoveries that one can look forward to? Any timelines 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 Four? Thank you very much.
First of all, let me thank you for asking this question, because through your questions, we get an opportunity to share our thoughts and insights of our E&P effort. 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 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 the development drilling, which happens to enhance our production, has got a contribution to the reserve replacement ratio, which needs to be maintained ±1, and more than one 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 m/ well depth, today, our target ranges from 5,500+ m, 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 100,000 sq km , out of which 50,000 sq km pertains to shallow water, deep water, and ultra deep water acreages. And as you know, we are currently drilling the third exploratory well in Andaman and Nicobar, and as we speak, the depth range is about 3,500 m-3,600 m. We are going to go down to 4,200 m.
As far as our exploration in Kerala-Konkan Basin is concerned, we intend to drill up to 6,000 m to trace presence of hydrocarbon in the Cretaceous formations. 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 sq km in four blocks, Mahanadi Basin and KG Basin. As part of our exploration effort, we have already completed 4,200 line m of 2D seismic and 50% of 3D seismic, that is 5,300 sq km.
This also adds to contract costs, 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 bidding round, which is now extended till the May 29th, 2026. I hope I have been able to substantiate with my response. Should you require, please let me know.
No, sir, this is very helpful. Thank you so much for the rich insights. 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 modeling?
Okay. Very good question, and this is, this is. I would also love to answer. Look, it's like this: as of today, we are deploying semi-submersible rigs and jackup rigs, which are primarily shallow water depths but deeper horizon. And 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. Cambay Basin block is a Category one basin. Meghalaya is a Category two 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 our 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 three-four 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 would 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 basis, assumptions for seismic data acquisition and processing and interpretation will have the oversight of Total, which is a 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 this 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 de-risk mechanism, so that we not only look after the OALP nine blocks that we already have acquired, we will also follow a similar approach for our OALP ten bidding strategy. I hope I have been able to substantiate my response.
Thank you, Dr. Ranjit, for the detailed color.
... Thank you.
Thank you.
Thank you, sir. We will take the next question from the line of Sarthak Tita from DSP Asset Management. Please go ahead.
Hi, morning, sir. I hope I'm audible.
Yes, you are.
Yes. Great. So just, sir, I had a couple of questions on, and I would like to hear your views on that. So first of all, I like—we had a understanding with BPCL on their new investment in the Andhra Pradesh refinery, right? So just wanted to get some viewpoint as to the reason behind us getting into that in as a strategic investment, and what will be the percentage or what will be the collaboration that we are working on. And secondly, sir, our standalone operations of ENP. Just would like to know more about the production guidance for FY 2026, 2027 and 2028 for both crude and gas, if you could provide some color on that. Yeah. Thank you.
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 cum petrochemical complex, wherein we are looking at a 12 million metric ton, and the refinery will have about 35% petrochemical intensity index. Now, the D-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 mainstay will continue to remain E&P, for that matter. As far as standalone E&P production is concerned, as I have already said, our target for 4 million metric ton and 5 BCM are contingent upon two 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, 2024, 2025 production. Year after, we are looking at a number, though 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 eight. We will be actually having one, guidance. The crude oil production, 4 million metric tonnes would happen. However, natural gas production, though we have potential to produce from the current 8 million standard cubic meters per day, to 13 million standard cubic meters 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.
Going forward, we are looking at something like 7.5 MMTOE. Should there be the evacuation in place, we would aspire to achieve 8.5 MMTOE FY 2028.
Great, sir. This was very helpful. Thank you so much for your insight, sir.
Thank you.
Thank you. We will take the next question from the line of Bineet Banka from Nomura Wealth. Please go ahead.
Yeah. Hi, sir. Thanks for the opportunity. I have a couple of questions on the NRL refinery part. So firstly, how much of the refinery's 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 fields 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 rail. 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 all India. So, it fluctuates with international prices.
So there will be differentiate, the logistics cost will be higher if you are importing and using pipeline to transport. So what could be that depletion?
See, pipeline transportation cost typically is INR 0.50 per ton per kilometer. And you also have the luxury of importing crude, which is 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-$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.
Did I answer your question?
Yes, sir. Yes, sir. Yeah, just another question on the same NRL refinery. So what was the reason you had, like, very high refinery, like $16 in this quarter? This is much higher than what the other ONGC have reported.
See, actually, we are-
Are you not happy?
You must be happy. But, at the same time, I would like to explain. See,
Yeah.
We are mostly the current refinery is mostly a diesel refinery. 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%-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.
But that is a modest answer. Let me supplement this. The refinery is running 100%+ capacity, and the best yield too in percentage terms also. So these two 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 HSG, and most important is the performance of the refineries.
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 one or two years, including the Petchem plant?
I think the current debt is-
About INR 16,000 crore.
Yeah. It is around INR 16,000 crore, and by the time we end all the projects, including Petchem, it should be around INR 25,000 crore-INR 26,000 crore.
Okay, sir. Thank you. Thank you very much.
Thank you. We will take the next question from the line of Nitin Tiwari from PhillipCapital India. Please go ahead.
Hi, sir. Good morning. Thanks for taking my question.
Good morning.
Morning, sir. So, sir, staying on the question of contractual cost, explanation that you gave is a rather structural one, where, like, you know, your incremental exploration and development effort is, is leading to perhaps a higher cost. But, I am interested in knowing what specifically happened in this quarter, because in this quarter, your contractual costs were higher by about 70%-71% on both YOY as well as QoQ basis. And as the earlier participant also asked, that is, is this the baseline that we should consider going ahead?
Okay, I'll give you a bit more elaboration. This month, we have already drilled the equal number of drilling that we had done last year. And this is just 62. We are going to drill another 12-15 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 a 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, 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 deep water drilling, but that would also be helped with international collaboration. So from a safe assumption point of view, the current numbers could be benchmarked.
... So, sir, if I, if I understood this right, because your, like, you know, 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 costs?
Okay. I'll now, let me take some credit here. This activity, please understand, Oil India was drilling only 30-35 wells, three-four, two-three years ago. The same manpower, we are delivering more drilling because of two-three things. One, our operational efficiency has gone up substantially. Two, we are drilling more wells and more deeper wells, while standardizing an SOP, where the drilling rigs and then the inter-location movement is seamlessly baptized. Third, the waiting on period of the bundled 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 2,000 hp rig, 1,400 hp rig, or a 3,000 hp 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.
Yes, sir, fair enough. So secondly, again, a clarificatory question on the production guidance that you gave. You mentioned 7.5 million and 8.5 million tons equivalent in 2027 and 2028. So if we look at, like, you know, the crude production in 2026 is going at a run rate of about 3.4 million tons annually. So if we can get to some specifics in terms of what you are targeting for 2027 and then 2028 in terms of crude production. As I understand, you said it's contingent on connectivity and other aspects, but,
Crude production, if we are, 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-
In 2027?
In 2027.
Okay.
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 four. That also is a reason, because when the drilling happens, the buildup towards production comes in the last quarter. So there could be a situation that we would slip 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 wells 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 hp rig in our fleet. Number three, we will have couple of new rigs joining the fleet.
Therefore, we are planning that 100 numbers to be drilled and to be able to produce.
Thank you so much for the elaborate answer, sir. Really helpful. I'll get back in the queue. Thanks again.
Thank you.
Thank you. We will take the next question from the line of Vikas Jain from CLSA. Please go ahead.
Dr. Rath, and team, sorry, thanks for taking my questions. So, the scenario that you're painting is, of course, there is a lot of excitement in terms of activity, which with you most likely will possibly end up drilling three times the number of wells, and you've been able to get some efficiency in 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 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?
Excellent. I think you are bang on. I am so glad that you have summarized your assessment so rightly.
Okay. Sir, so in that context, could you just give me what has been the seismic cost for, say, three Q and two Q as well, and the nine months that we have, because that's part of the other expenditure, right?
Okay, I'll just dig out, because I'll have to dig out exact number. What is the seismic cost? Where is that?
354, sir.
Okay, the seismic, the cost number towards seismic data acquisition is about INR 580 crore, that I am given to understand, and nine months is INR 1,151 crore.
2Q was?
Excuse me, what is the other question?
Two Q.
So the quarter three number is, Excuse me. Yes. So the quarter three number is INR 579, and quarter two number is INR 321.
... Okay, understood. And-
These are actually variable parameters. The more you drill, the more deep you go, your cost would naturally go, it will increase.
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, you know, even exploratory wells. These would show up—other than seismic, where would this be, would this be broadly bunched up? You know, 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, your, your nine-month number is almost getting closer to INR 2,000 crore?
Yes. I mean, see, exploration appears under the head 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.
Sure. So I think these will be the two elements, or is there something else that I'm missing other than seismic and-
Other than this is the G&G, which is my seismic survey expenses, et cetera.
Yeah. So the seismic and survey expenses are the numbers that you gave us. INR 1,150 crore, right? That's the one that you gave us.
Yes, that's correct.
Okay.
Yeah, 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 at 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 cognizance 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 best not updated.
Sure.
I hope I have given a kind of a clarity on the concept.
Sure. Absolutely. So obviously, I mean, so Q3 and Q4 might have more fair weather window, so that might-
Yes.
have more activity over there, obviously.
Exactly.
Just to kind of, for comparison sake, like last FY 2025, from what I can see, your total seismic cost was about INR 750 crore, and your total E&P dry well write-off was about INR 650 crore or so. Those numbers-
One second. One second. I'll take down your number first. What you said, I'm glad that you are doing this granularity. Seismic, you were saying how much?
So this is from what you had reported, I think 750, 7-
No problem. I will take it from you. I accept it, because that helps me to crystallize my thoughts. Please go ahead.
INR 750 crore and INR 650 crore. Roughly, I'm rounding it off. INR 750 crore is-
No problem.
INR 650 is dry well write-off.
Okay.
These numbers, how, what—how should we think of FY 2026 and 2027 in terms of where these will go up to? Like FY 2020, like nine months has already become nearly INR 2,000 crore 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 like 3Q.
Can I get your name, please?
Vikas, sir. Vikas.
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 guideline. 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 overlaps. 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 tie-in study, then you bring in a supplementary seismic, then you decide couple of more drilling to be done.
In between, you do a back analysis of your data, run your dynamic modeling, 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 costs 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. 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 horizon which could possibly be tested, are kept as work in progress.
One example, the first well that we have drilled in Andaman and Nicobar, we have drilled up to 3,600 m, 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 am trying to offer.
Sure. No, I fully appreciate that. I mean, finally, exploration, there is an element of chance and predictability can be difficult. But, you know, 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 2026 and FY 2027. That's the right way I should be thinking about it.
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 insight, 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, is resulting or giving us more, as we call, a sand horizon 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.
Sure. Sir, just shifting gears a little bit, and one last thing before this. I know I've taken a lot of time, but hopefully we may-
Please do.
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 distillery yields increase, and that's when refining margins increase. So how should we think about operating at higher, at full, fuller, you know, the right utilization levels for the overall refinery, number one, and when will the petrochem expansion start kicking in? If you could go by quarter by quarter, say, 1Q, 2Q of next year. I mean, when should we start seeing the high refining margins, ex of petro, petchem, start kicking in with all upgrader units operating?
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, we hope to achieve 50% capacity utilization on 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, and gradually going up to 100%. So you, you will see a gradual uptick in the capacity utilization of the new complex that we have built up, starting from Q4 of FY 2027, and continuously going up to, say, Q2 of next finance, the financial year thereafter. That is FY 2028. And during FY 2028, 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 that product will start trickling in. Maybe at the first quarter, we will not be able to achieve 100% of capacity run, but gradually it will ramp up in 2-3 quarters, we will be able to go to 100% capacity utilization. So to summarize, in Q4 of FY 2027, we will be at 50% daily capacity utilization and going up to 100% by Q2 of FY 2028. And Petchem will start by close of FY 2028, and it will be achieving its full capacity by, say, Q2 of FY 2029. So that is the outlook that I would like to give you at this moment.
Very granular. Thanks so much, sir. Those are all my questions. Thank you.
Thank you. We'll take our next question from the line of Gaurav Jain from ICICI Prudential Mutual Fund. Please go ahead.
... Sir, thank you for the opportunity. Just one question from my side. If you can share, sir, region-wise split of the 60 wells that you would have drilled till now. How many of them are in, say, Northeast? How many are in other geography, et cetera? That will be helpful.
Okay. Give me one minute. I tell you, I'll give you a construct. See, the you all know that the main producing area for Oil India Limited is in Arunachal Pradesh and in Assam. Okay? And by nine months 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 two or three 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 couple of drillings, so we are looking at a total of 75.
Gaurav, does that answer your question?
Yes, sir. 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, or those wells are more of associated fields where both gas and crude would be there, and then the evacuation 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 wells that we are drilling has to be then crude only, maybe, so that we can take out the crude. If—where are we wrong in understanding this, sir?
Okay, I'm so glad you are asking this granular question. Let me, let me give you a perspective. When we drill, we really look at hydrocarbon because the signature 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 I, 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 is, we have already established a possibility of gas storage in one of our field 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 field, that is in Lakwagaon, we have converted a crude oil 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.
Very helpful, sir. Thank you so much.
Thank you. Next question is from the line of Sabri Hazarika from Emkay Global Financial Services. Please go ahead.
Yeah, good morning, sir. Two questions. Firstly, on this CapEx front, what we've noticed is that I think nine months stand-alone CapEx is somewhere around INR 8,500 crore, so which is in line with the full year guidance. So for this year, would we be overshooting the guidance?
The more we do the activity, the more the CapEx that you would appreciate. 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.
Okay.
The number that we have indicated for 2025-2026 is 8,800, but given the numbers that we have seen yesterday as part of our Q3, it would be increasing.
... Okay, and next year also would be, like, similar, higher than the INR 8,500-INR 600 crore that you have given?
It will be, 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.
Okay, sure. And NRL, how much has been the financial progress? How much CapEx has been done?
This year, CapEx so far has been around INR 6,000 crore, and we will end the year with INR 8,000 crore. Our CapEx, total, CapEx, both the refinery and petchem put together, is INR 45,000 crore. There are smaller projects also included there. Yes.
Right, sir. And, okay, and second question is on this Andaman field. So, we have drilled two 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?
I'm so glad. Okay, so Andaman, I'll give you a perspective. Andaman are the OALP blocks. We have two blocks, 9,000, I think 10,000 sq km , one block on the east side, one block on the west side. We had initially planned to drill four wells in Andaman shallow water. The first well was drilled up to 3,600 m. 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 m, and we undertook a sidetrack, and then we tested the well in the sidetrack. That is called A well, and the sidetrack well established presence of hydrocarbon.
As far as Ind AS is concerned, even if you are doing sidetracking, the mother well has 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 meters. 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 meters, 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 sq km 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 sq km , we intend to drill an appraisal well. So that will be the fifth well in Andaman Nicobar. So that's the Andaman story.
Thank you so much. 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?
Yes.
What would be the equivalent gas production, current, in MMSCFD?
Give me, give me, give me one 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.
That's natural gas. And crude oil as of today?
Crude oil, as of today, we have done 77,288 bbl. That works out to 10,029 metric ton.
1,029 metric ton. Thank you so much, yeah. Thanks a lot, yeah.
Thank you.
Thank you. Next question is from the line of Somaiya V. from Avendus Spark. Please go ahead.
Yeah, thanks for the opportunity, sir. So first question is on the Paradip NRL pipeline. So how much kilometer is still left, and, and, what is our expectation by when this will get completed?
I'm sorry, I could not get your question. What is that, kilometer?
Somaiya? Sorry to interrupt. Somaiya, can you use your handset mode, please? Your audio is not clear.
Yeah, yeah. I hope I am audible now.
Yes.
My question was, how much kilometer, how much kilometer is still left in that Paradip NRL pipeline?
Okay, very good. So PNCPL is about 16, not about, 1,635 km. The ROU, so far we have already opened is 1,600 km. The balance ROU that we intend to open, which is spread across eight, is about 40 km. And you would appreciate about we are going to traverse five states: Odisha, West Bengal, Jharkhand, Bihar, and Assam. So in some, in all the states, there are small, small ROUs left. Otherwise, we are on track as far as our production, or the ROU opened is about 98%. The loading is about 92%, that is completed.
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 by then, we expect this to be fully completed, so we don't see any risk of this getting delayed. So just want to have a confirmation.
No, we don't see any bottleneck as far as the pipeline is concerned. We have got excellent interaction with the state government for these remaining ROUs, and we do not foresee any constraints.
Got it, sir. Thank you. Second question, sir, is on the CapEx front on, on NRL. So of the INR 45,000 crore that we mentioned for the project, so far, what have we spent? And, the remaining amount, what is the, profile that, you know, the spend profile next couple of years?
The project, you would have heard already, we are looking at completing the project and taking complete 100% capacity utilization by Q2 of FY 2028, 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 capex of about INR 16,000 crore, if my numbers are correct.
Yes, that much has been done.
That has been already done. As far as the overall CapEx is concerned, we are looking at INR 34,000 as far as NREP is concerned. How much is the equity? Let me- ...
Total is 45,000 as a ballpark number.
Sir, I was just looking for next couple of years, what will be the CapEx that NRL would be requiring to complete the projects?
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 INR 7,200 crore. So that's the spread.
Okay, sir. So a couple of questions, one on net debt at consolidated. So, what will be the net debt? You gave NRL number, also on the standalone and as well as the international ops. And also, if you could give some color-
I'm sorry, what is that you are saying?
Uh, the-
What is that?
Consolidated net debt number. Consolidated net...
Thirty-four point.
Okay. Debt, INR 34,000 crore. Net debt, I'm sorry, INR 34,000 crore.
This is the consolidated level, including 16,000 at NRL?
Yes, yes. It is-
And-
Let me give you a break-up. Let me give you a break-up. It is INR 16,000 crore at NRL level. It is INR 16,000 crore at Oil India level. The INR 16,000 crore in Oil India level is primarily the external commercial borrowings.
Got you.
For our overseas effect.
Sir, last question on your overseas, sir. So if you could just give some color on the performance and dividend status.
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 INR 3.5 per share. Yesterday, we have announced INR 7. That brings it to INR 10.5 per fully paid authorized share. So that is the dividend declaration which I have to offer right now.
Sir, my question was on the dividends that we need to receive from the international ops, the Russian assets. So-
Okay.
Any update on that?
Okay, okay, okay. So as far as Russian asset is concerned, we have got two assets. One is Taas-Yuryakh , and one is Vankor. Now, when I say Taas-Yuryakh and Vankor, both our exposure is about $1 billion. As far as Taas-Yuryakh is concerned, we have got 100%+ dividend back. As far as Vankor is concerned, it's about 90%.
Any dividend that is still there, which I have to receive, or so far, we've got whatever that's been declared so far, we have received them.
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.
Thanks for the clarification, sir. Thank you.
Thank you. Next question is from the line of Moksh Ranka from Aurum Capital. Please go ahead.
Hello, sir. I wanted to ask, could you please provide some color regarding the Northeast gas pipeline connectivity? Could you provide some color on that?
Okay. I'll share that. The thought process is, the main line which goes from Urja Ganga, laid 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 capitals 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 capitals are work in progress.
You would appreciate the terrain is so difficult that IGGL 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 up, capacity upgradation of that pipeline is underway. We are looking at 1 million standard cubic meter per day as 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.
Okay, and is this Duliajan hub going to integrate with the IGGL, and by when can we expect that also?
Coming, coming. 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 crossings. So that would actually give us an opportunity of evacuating 3.5 million standard cubic meter of gas per day.
Okay. Okay, got it. Thanks for the clarification, clear from me. Thank you.
Thank you.
Thank you. We'll take our next question from the line of Keshav Soni from Kotak Securities. Please go ahead.
Thanks for the opportunity. Can you please share the standalone CapEx guidance for 2026, 2027 and 2028?
Standalone CapEx for this year, for Oil India?
This year and 2027, 2028, yeah, for Oil India.
Yeah, it is INR 8,800 crore. Going forward, it will hover around the same number, or it will touch base about INR 9,200+ crore.
Got it. Thank you. Thank you so much for the clarity. Okay.
Thank you. As there are no further questions, I now hand the conference over to management for closing comments. Over to you, sir.
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.
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.