Oil India Ltd

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

Thank you, Manav. A very good morning to everyone. I'd like to extend a very warm welcome to all the participants as well as the management of Oil India Limited. We have with us the senior management of Oil India, represented by Mr. Abhijit Majumder, Director of Finance; Mr.

Saloma Yomdo, Director, Exploration and Development; Mr. Trailukya Borgohain Director Operations; Mr. Bhaskar Jyoti Phukan, MD – NRL; Mr. Ranjan Goswami – ED Business Development; Mr. Anup Kumar, ED; Mr. Ajaya Kumar Sahoo, Company Secretary; Mr. Abhijit Das, Chief General Manager (F & A)

I hand over the call to Mr. Abhijit Majumder for their opening remarks, and then we can move on to the Q&A. The floor is yours, sir.

Thank you, Mr. Varatharajan. Good morning, ladies and gentlemen. A warm welcome to all the participants joining us for Oil India Limited's Investor and Analyst Conference Call for the first quarter of financial year '25-'26. I'm Abhijit Majumder, Director of Finance at Oil India Limited.

I'm joined today by my esteemed colleagues from both Oil India and our material subsidiary, Numaligarh Refinery Limited. I would now like to invite our Chief General Manager, Corporate Finance to present the opening remarks.

Thank you, sir. Good morning, ladies and gentlemen, all who have joined in this con call. At the outset, I would like to thank Antique Stockbroking Limited for hosting today's analyst and investors call for Oil India Limited. Myself is Abhijit Das, the Chief General Manager, Oil India Limited, hosted in a corporate office in Noida.

Along with me, our senior management team has joined along with the other colleagues. Mr.

Abhijit Majumder, our Director of Finance; Mr. Saloma Yomdo, Director, Exploration and Development; Mr. Ajaya Kumar Sahoo, Executive Director, Company Secretary and Mr. Saket Garodia of NRL Finance team. Along with this team from our headquarters and corporate office in Noida, Mr. Goswami has joined from our field headquarter. He is ED Production.

On behalf of the management, I welcome you all in our first quarter earnings call for the quarter ended 30th June 2025. The final results of this quarter has been approved by our Board of Directors in its 570th meeting, which was held on 12th of August 2025 and has been duly published as per the requirement of the statute.

Just a quick overview of our strategic steps which we have taken. Oil India continued its steady transition into the integrated energy company. On upstream front, we have been maintaining

consistent growth in both oil and gas production on a quarter-to-quarter basis. Our midstream pipeline expansion is progressing well and has been targeted.

The downstream side expansion of Numaligarh Refinery is gathering momentum and going to get commissioned as planned in the phased manner. We are expecting to get it commissioned in the month of December 2025. A few operational highlights, which has been taken place in this quarter, I'd just like to bring to the knowledge of this entire audience gathering here.

In production front, we are continuing in growth story during the quarter, OIL has pursued its efforts towards ensuring national energy security by sustaining oil and gas production from its mature fields in Northeast at 1.680 million metric ton oil and gas equivalent for the current quarter as compared to 1.689 million metric ton of oil equivalent in the previous quarter of '25.

We sustained momentum in our upstream operation. The crude oil production for the quarter stood 0.85 million metric tons. There has been a marginal decrease of 2% on year-to-year, but we have been achieving 1.07% on quarter-to-quarter basis increase in production of crude oil.

The natural gas production for the quarter has reached 0.83 bcm. On quarter-to-quarter, it has increased by 2.61%, and on a year-to-year, it is 1.1%.

We have a good news during the quarter that during the quarter, OIL has discovered a hydrocarbon discovery in Namrup-Borhat OALP block, which is in Upper Assam. And we have also commenced natural gas production from our Bakhritibba Discovered Small Field in Rajasthan in the district of Jaisalmer. This growth reflects our continued focus in well intervention and field development activities.

I would like to bring some glimpse of our financial highlights during the quarter. The average crude oil realization, there was a slight decline during the quarter, which has decreased around 22% as compared to year-to-year basis. In the current quarter, we had a realization of $66.2 per barrel as compared to $84.89 per barrel.

The natural gas price stood at 6.72 MMBTU, aligned with the regulatory benchmark has been guided by the Government of India. Our stand-alone revenue has -- we have registered a stand- alone revenue during the quarter of INR5,012 crores as compared to INR5,839 crores in the previous year. We have a marginal other income, but our total income during the year was INR5,188 crores as compared to INR6,001 crores in the previous year of the first quarter.

Our PBT for the current quarter is INR1,097 crores as compared to INR1,974 crores in the previous quarter -- in the previous year, and our PAT has gone down because of the sharp decline in the price of crude oil. We have registered the bottom line of INR813 crores as compared to INR1,467 crores in the previous year.

We had a substantial other comprehensive income because of our strategic investment in Indian Oil Corporation. The share price has increased around INR1,400 crores or we are having 7.284 million equity shares of INR10 each but we have a very strong other comprehensive income, and it has increased as compared to the previous year. Because of low PAT, our earnings per share has gone down by INR4. We have earnings per share of INR5 in the current quarter.

The EBITDA margin has gone down from 43% to 34% in the quarter because of lower revenue and small increase in our operating expenses for providing provisions against our well assets.

Two major things which has happened in the current year is that we have provided of INR307 crores in our two Bangladesh block, which we have decided to increase in this quarter. Another provision, which is having made of our another overseas joint venture is Gabon block, which is we have provided of INR207 crores because of nonperforming as per the plan.

Our performance from our material subsidiary, we have Mr. Garodia here with us to answer all your questions. But the revenue of our material subsidiary is INR6,208 crores during this quarter.

The refinery has been operating at a capacity of 106%. We had a crude throughput of 799 TMT as compared to 764 TMT in the previous financial year. The EBITDA of our material subsidiary is INR786 crores and the PAT is INR488 crores.

The consolidated performance of the company -- the company has sustained a consolidated PAT of around INR2,047 crores in spite of dip in PAT in the stand-alone profit. The major reason of increase in the group performance is contribution from our material subsidiary, which -- and our performance from our foreign subsidiary for our Russian investment. They have contributed INR544 crores and INR780 crores, respectively, where they registered a better group performance for the quarter.

Our EPS per share in the group has also increased marginally from INR11.59 per share to INR11.66 per share. With this, I'd like to share my closing thoughts with you before I hand over to the gathering to pick up the question-and-answer session. Oil India has delivered resilient and disciplined performance in the first quarter of the current financial year, supported by its operational stability and prudent financial execution.

As we look ahead, our focus remains on execution, excellence, production growth, long-term value creation across portfolio of our company. With this, I like to conclude my remarks and welcome you all in the questionnaire session. But our request is that kindly put up two queries per participant to allow time for all. Thank you, sir.

Thank you very much, sir. We will now begin the question and answer session. We have our first question from the line of Vivekanand from Ambit Capital.

My first question is on the production outlook and guidance for FY '26 and '27. Could you refresh us on that? And that's my first question. The second question is on the capex that you have been guiding for FY '26 and '27, if you can give us the number as well as the split across key projects like contribution to NRL and also the upstream operations and other areas like CBG? ED Production, are you there? Yes, sir. Can you take the first question?

Yes, sir. Regarding first question, our incremental oil and gas columns were largely driven by a few high-performing domestic fields like Baghjan. Baghjan field is continuing delivering strong

volumes supported by expanded gas infrastructure. Barekuri has emerged as a key contributor.

We are planning 15 wells to drill in this area, which will give that Mission 4 plus production ramp-up. Kumchai, we developed that network delivery line and Kumchai also taking a step up for this -- after pipeline connectivity, Kumchai production is also ramping up.

Would you be able to help us with some quantitative guidance on FY '26 and '27? I think -- I believe the last time you had highlighted 3.5 MMT of oil and 3.5 -- sorry, 3.7 for oil and 3.5 for gas, if I'm not mistaken?

So our actual achievement for '24, '25 has been 3.458 for oil and 3.341 for gas -- 3.252 for gas.

Now for '25-'26, we have set a target of 3.70 MMT for oil and 3.40 for gas. I mean 3.65 for gas.

Does that answer your query or you want data for '26, '27 as well?

Yes, yes. The latter would be helpful, '27 also would be great? '27 is 3.95, that's crude oil, MMT. And natural gas would be 4.31.

All right, sir. This is very helpful. If you could just address my second question, that would be great.

Can you repeat the second question, please?

The capex for FY '26 and '27, along with some details of the area?

CGM Corporate Finance is taking that question. He's replying.

In the previous year, as you have all known that there was an increase in our capex expenditure by about 123% as planned. For '25-'26, we have planned INR6,995 crores or you can say INR7,000 crores.

That is at the standalone level, right? Oil as an upstream entity. Yes, please continue, sir.

And during this quarter ended, what we have achieved for our capex expenditure. For exploration and development, we have already spent around INR1,100 crores. For our capital equipment and facilities, it is around INR900 crores. For our survey expenditure, it is INR250 crores. If we take this expenditure for our E&D activities, it is around INR2,300 crores.

After considering this, if we think of some overseas investment, also we have spend around INR300 crores majorly in G&P activity and drilling. Other than that, we have also contributed around INR550 crores for our investment in NRL, the final call amount which we have been due for payment. So for this quarter, if you can sum up, you can find it is INR3,350 crores for the current financial year as targeted around INR7,000 crores.

So would you like to -- Saket, another part of the capex?

With regard to Numaligarh Refinery, the capital expenditure target for the current year is around INR9,133 crores, which is largely on account of the expenditure to be made in its current refinery expansion plan and the petrochemical unit that will be coming up. So current year, we are

planning a capex of INR9,100-odd crores. And in the next year, the capex will be around INR7,300-odd crores.

We have a next question from the line of Probal Sen from ICICI Securities.

Yes. Sir, just about this Russian investment that was mentioned that it has actually contributed to the console numbers. Just wanted to understand where does the -- I mean, how is the payment mechanism actually working at this point of time? And what sort of dividend can we actually expect for the rest of the year? Are there any issues with respect to sanctions or anything else with respect to repatriating our share of dividend from Russia at this point of time?

Do you have any other question or that's all?

The second question, sir, was with respect to capex. I did not get the audio completely. I just wanted to clarify that the FY '26 guidance mentioned was INR6,995 crores. Just wanted a clarity on that. Is that the correct number?

Yes, that's the right number. Yes, correct.

Okay. All right. So then the Russia part was the main question that I had?

See, as far as the dividend from two of our investments in Russia are concerned, that is TYNGD and Vankorneft. We have almost recovered close to 95% of our investment combined in these two assets. 111% of investment has been recovered through dividends for the Taas-Yuryakh asset and close to 83% plus dividend -- sorry, investment has been recovered through dividend in Vankorneft asset.

As far as the outlook for the current year is concerned, this will be dependent on the performance.

We do not have any guidance available as of now how much of dividend will come. But in the current quarter, we have received around USD 11 million of equivalent of dividend from Taas- Yuryakh project.

And to just update on the performance of these assets and an assurance that dividend flow will continue. For your information, the Taas-Yuryakh asset is still producing at the peak level of 5- plus MMT equivalent of oil, and that is still picking. So there is no downside to the dividend inflow that we see from this asset. As far as Vankorneft is concerned, this is in the declining trend, but all the necessary infrastructure logistics have been upgraded to arrest those declines.

So there will be continuous flow of dividend in that asset also. And as I told you, 95% of investment has been recovered. We are at least sure that during the current year, 100% of investment for both the assets will be recovered by OIL. And then it will continue also further in the coming years.

Got it, sir. One last question, if I can squeeze in on NRL, you already mentioned the capex plan.

Can we also get a sense of the operational progress of the expansion in terms of physical progress, time line for the completion?

With regard to the physical performance, the company has achieved almost 106% utilization in the capacity utilization in the first quarter with nearly 799 TMT of throughput. And for the rest of the year, we expect to overshoot the capacity utilization of 100% again this year. So we'll be -- we are targeting for crude throughput of more than 3 MMT in this year.

And with regard to refinery expansion, our -- as has been informed, so the commissioning of the project will start in phased manner from December '25 itself. And slowly, the productions will also get ramped up as and when the unit starts coming up and start getting commissioned in the next financial year.

We have a next question from the line of Karen Kwan from Pine Bridge.

I have a couple of questions. The first question is, as we're upstream operator, it seems like we won't have too much direct impact from the U.S. tariff. But from the indirect impact front, we could. Can you comment on what sort of impact do we see from the U.S. tariff? And also, what sort of oil price expectations do you have for the next 12 months?

And secondly, sorry, I could not hear the fiscal year '26, '27 sort of capex number. Was it 7,300 for the fiscal year-end '27 March? And also lastly, can you give us any updates in terms of -- previously, we were looking into doing some trial runs for the hydrogen cell e-buses and the solar project collaboration with HPPCL. Just some updates on the ESG fund for renewable energy and any new sort of renewable energy capacity that will be online for the next 2 to 3 years?

As far as the impact of U.S. tariffs on oil's operations, I mean, the upstream operations are concerned, let me clarify that there would be no impact at all because ours is all internally consumed. We are not -- we don't export anything anywhere. So we are a hydrocarbon deficient country. Hence, everything will be internally consumed. So we don't have any apprehension as far as U.S. tariff is concerned. So with respect to capex for '26, '27, that's what you wanted to know?

Yes, because I heard for the first one, FY '25, '26 is INR9,133 crores from the previous question.

And then I heard INR7,300 crores for fiscal year '26, '27. Is that INR7,300 crores number correct? If not, what's the number?

No, your numbers are correct. However, we have a material subsidiary who would be investing about INR9,100 crores for '25-'26. And OIL as parent would be investing INR6,995 crores.

These are all investment numbers for '25-'26. As far as '26-'27 is concerned -- sorry? Please go ahead.

Okay. So as far as '26-'27 is concerned, OIL would be investing INR7,585 crores, covering the various heads under which the investments will be made, and NRL... INR7,300 crores.

And NRL investment would be INR7,300 crores. So total would be INR14,000-plus crores for '26-'27.

And can you just quickly comment on the ESG side?

See, yes, we have earmarked a sum of INR25,000 crores to kind of achieve our net zero target by the year 2040. So investments will be made in different segments, starting from solar, wind energy. We are also into CBG, which is the compressed biogas produced from -- I mean, mostly municipal solid waste. So these are some of the projects. We are in the process of setting up about 25 CBG plants across different states in India.

We have already tied up with a few states, already the MOUs and other agreements have already been signed. Additionally, we are going to set up nearly 1.9 gigawatt of solar energy, mostly in two states, one of which is in the Northeast, Assam, and the other one is Rajasthan. In these two states, we will be setting up solar -- I mean, solar energy plants, and this will actually be done by our wholly owned subsidiary, Oil Green Energy Limited.

And one more, sir, 150-megawatt solar plant at Himachal Pradesh.

So for the 1.9 gigawatt solar in the North Eastern Rajasthan, what is the rough time line we expect it can be up and running? And lastly, we're not doing the hydrogen cell e-buses anymore, right? March '26 target. March '26, very fast. Okay.

March '26. Regarding the solar projects, as already -- sir has already told, so we are aiming 645 megawatts in Assam, and 1 gigawatt in state of Rajasthan and 200 megawatts green energy projects in Rajasthan. And as far as Himachal Pradesh is concerned, we are already establishing a 1-megawatt capacity of green hydrogen plant in a place called Baddi in Himachal Pradesh.

EPC contract has been awarded and the work is in progress right now. And as far as the 150- megawatt solar project is concerned, we are discussing with the Himachal Pradesh government team. These discussions are going on. Hopefully, this will come up.

Yes. Just before we close, there's a bioethanol plant coming up in the Northeast. So that is going to be commissioned very soon. The date actually has already been finalized. That is going to be coming, I mean, inaugurated on 8th of September. That's a bioethanol plant, which is meant for mixing of bioethanol with HS and MSD.

We have our next question from the line of Somaiah V from Avendus Spark.

Sir, my first question is on the NRL projects. So if you could just help us with status of completion. So for instance, the refinery in terms of completion, it's 90%, 95% and also in terms of pipeline length from Paradeep to Numaligarh, the total length, and so far, the completion achieved? Similarly, on the other side, the pipeline to Siliguri. If you could just help us with some details in terms of extent of completion in all these projects would be helpful?

Yes. So with regard to our refinery expansion project, the overall physical progress of around 80% has been achieved by the end of the quarter 1. And in case of our CNPCL, that is the crude oil pipeline, we have achieved around 84% of physical progress. And with regard to the refinery expansion part, it is around 76%. So we are -- the pipeline -- crude oil pipeline is expected to get commissioned in the early Q4 of '25, '26.

And just to inform that we have -- out of 1,635 kilometers, we have already opened RoU for nearly above 1,500 kilometers. And the phase commissioning of the project is set to begin from December '25 and wherein each unit in phased manner will start getting tested and commissioned and production will be ramped up slowly.

Understood, sir. Sir, in terms of utilization of this expanded capacity, let's say, 6 months from commissioning, ballpark, where should we be able to reach to?

So we are expecting that in the second half of financial year '26, '27, actually additional output from the NREP will start coming in. However, in the initial stage, the production levels will be around 40% additional. And then going forward, we are expecting that in the financial year '27, '28, we will have an output of nearly 80% from the new refinery.

That's helpful, sir. So second half of FY '27, roughly 40% kind of utilization of the expanded capacity? Yes. That's right.

Got it. Sir, also on the upstream part, in the quarter gone by, were there any shutdown by customers that impacted our production? And also for this quarter, are we seeing any shutdown- related impact to production?

Yes, sir. This shutdown of non-upliftment of gas is affecting our production. We are setting our wells frequently. So once it is that connection, IGGL connectivity is -- build up and DNPL also get that permission, and it will be -- that production will ramp up.

Yes, sir. I was just trying to understand whether the last quarter, whether any fertilizer or any other industry, there was a shutdown that led to marginal decline. So just want to understand that?

Yes, sir, that shutdown is one is that BPCL -- VCPL, they have shut down for more than 20 days. Then BVFCL also have shut down. Numaligarh also, some amount they have taken less.

So all these are APL, they are taking maintenance up. So these are affecting our production, sir. Now these are now started taking gas.

I think the LPG plant was suppose to shut down for a month before.

LPG plant also shut down for a month, yes, sir.

Got it, sir. Sir, one last question on the other expense. This run rate has been higher. So for instance, this quarter, it's around INR1,700 crores. So one is this INR300 crores provision related

to the Bangladesh asset. But I think in the opening remarks, you also mentioned another INR200 crores provision.

So total INR500 crores of provision is within this INR1,700 crores. That's the first part. And second, in general, this run rate has been going up last two, three quarters. If you can just help us with some final details as to...

I didn't get the last part of your question. One is the normal on provision and what is the other part?

Other part is your other expense, if you -- the breakup that you give as part of the...

Everything is [inaudible 0:0:34:57] only. However, what exactly -- see, Bangladesh was actually -- it is flowing from the previous year. Bangladesh, we had our performance bank guarantee invoked by Petrobangla, which is the equivalent of DGH in Bangladesh. So with respect to some MWP, our BG was invoked. However, both the companies, as you know that we are in partnership with OVL.

So both of us decided to quit from that particular project. So this INR285 crores roughly, which the amount was invoked in the previous year, and this was charged as expenses in the current year. This has got nothing to do with the current year as such. It is just flowing from the previous year.

And there were a few other wells, which is a regular kind of a thing in an E&P business. We have full provisions with respect to a few wells. There were basically two wells. One is Mechaki and the other is Bhojo. These are the two wells in respect of which we made provisions.

However, studies are going on. And if we get to see some better results in the days ahead, possibly we might take a different call and reverse it. That decision is yet to be taken. These are broadly the provisions that we have taken in our books in the current quarter.

Got it, sir. Sir, I was just looking at this -- the total other expense breakup of the INR1,700 crores, so where you have your contract cost expiration...

On average, we take about INR400 crores of provision annually. But this time, because of Bangladesh, which by itself took away INR285 crores, that -- apart from that, others are regular provisions. There are nothing -- I mean, these are not operational hiccups. These are normal provisions, which any E&P company would take, and we have also taken.

We have our next question from the line of Achal Shah from Ambit Capital.

Can you throw some light on the inventory losses at NRL, like out of the reported GRM, how much was impacted due to inventory losses? That is my first question. And second on -- sir, what is your near-term and long-term crude price outlook like for F '26 and then onwards?

I will take the first question. With regard to the impact on GRM of NRL. So NRL reported a GRM of $5.02 per barrel in the -- for the period of April to June '25, '26. And we had to take a hit of $2.93 for this particular quarter on account of loss of the value of the inventory, which was

largely on account of fall in the crude prices compared to 31st March and closing at 30th of June. So for the second part of the question.

I mean it's a very difficult question. See, crude price, nobody can predict. And as conservative entities, we also cannot make a real prediction about a major increase in the crude oil price in the days ahead. So our outlook would be at best, maybe 65 to 70. We are currently hovering at around 66, 67. So we don't expect a major increase in the crude oil price in the days ahead. If that happens, that will be very good for us because the result that you have seen this time is largely because of a 22% drop in crude oil price vis-à-vis quarter 1 of '24, '25.

Understood, sir. Sir, any update on the time line for invoicing the gas as new well gas?

See, as far as new well gas is concerned, the notification says that it has to be supplied to the city gas distribution, which is on top of the list. There are other sectors as well, but CGDs have to be provided -- have to get the preference first. Since CGDs are yet to come up in the Northeast, we are facing that problem.

However, we have made a request to the ministry to let us allow the gas to be lifted by NRL, give us that marketing freedom so that -- see, we are sitting on a reserve of roughly 140 bcm of gas. So as far as supplying gas is concerned, we are ready. But then we have to have the network there and also the sector to which the gas can be supplied.

Now if CGDs have to be supplied, then we'll have to wait because CGDs will come up -- it will take some time. Maybe not before '28. But in the immediate term, if we are permitted to supply gas to NRL or other producers, then we are okay. We have made a request to the ministry. If that is granted, maybe we will be able to fetch the premium that the notification provides for.

We have our next question from the line of Vaibhav Badjatya from Honesty and. Integrity Investment.

I have two questions on the Northeast gas pipeline network. So first is the gas flow that can happen from Numaligarh to Barauni, whenever we ramp up our production, I think that connection is still not fully ready as per my knowledge because there is some compressor -- Guwahati station has to install some compressor station, which has not yet started.

So I just wanted to understand what is the status on that compressor station and when that can be commissioned so that full gas flow can be established. Second is before Numaligarh, for gas to flow still Numaligarh we also need DNPL pipeline, which has to be declared as common carrier. So I'm also at lost what is the status of DNPL being declared as common carrier for that to happen? So if you can just provide a status update on these two things, that would be helpful?

See, presently, the infrastructure is like this. DNPL is already there, which is supplying roughly 1 MMSCMD of gas to Numaligarh. And that capacity is now being enhanced. It would be able to supply roughly 2 to 2.5 MMSCMD of gas. Now that is independent of whether DNPL is designated as a common carrier or not because this is happening already.

Now second part of the -- we are yet to get clearance from the Ministry for the feeder line, feeder line, which will run parallel to the existing DNPL line. So that would actually supply gas to Numaligarh and beyond because that will be part of the IGGL network that is being commissioned. So IGGL would certainly be the common carrier in this case.

Whereas DNPL will play a limited role to the extent that it would supply gas to the customers, various customers in the Northeast to whom they are already supplying. Beyond these -- if the gas has to flow beyond Numaligarh to other parts of the country, you need the IGGL network, which is the first phase. And that first phase is already commissioned.

There's no compression issue, nothing is there. But because the lower end is not connected yet or the upper end -- I'm wrong, upper end. Upper end is not connected yet, we are unable to kind of inject gas into the system so that it can flow to Numaligarh and beyond.

Right. Yes. Sir, my question was on that -- onward flow from -- onward flow itself. So on the Phase 1 itself. So I think if gas has to flow from Assam towards Barauni, I think at Guwahati, we need compressor station, right? Otherwise, the gas will not be able to flow freely till Barauni.

I think that compressor station commissioning is still pending, if I'm not wrong?

That compressor station already commissioned at Baihata near Guwahati.

Okay. That has been commissioned. Okay. So the only hurdle is basically our upstream connection? Upstream connection, yes.

And there is no proposal as such to use DNPL itself to supply to other customers apart from Numaligarh and local gas consumers. There is no proposal as such to declare DNPL as a common carrier?

No, nothing as such. DNPL is essentially a supplier within the Northeast, largely in the state of Assam only.

We have our next question from the line of Nitin Tiwari from PhillipCapital India.

I'm slightly confused about the status of pipeline and capacity because there are several phases, several pipelines involved. So when you mentioned that the expansion that we are talking about in case of DNPL is from 1 to 2, 2.5. So that's the expansion of the existing pipeline and the feeder pipeline is in addition to this pipeline or the feeder pipeline coming in along with the pipeline would lead to the expansion? That is one.

Secondly, like as you mentioned that the Phase 1 of IGGL is completed and is commissioned.

So now I mean, the connection that you referred to, what is that connection that is required? And where are we in terms of our road map to increase our gas production from here to about 5 Bcf that we've been targeting? I mean what are the road blocks to that ramp-up? So if you can just comment on that, then I'll ask my second question?

It was a very long one, and I couldn't hear you properly. Anyway, whatever I have understood of the question. See, we are presently -- our production is 3.2, and we are supplying the entire gas to the various customers located in the Northeast. So additional to -- make it 5, which is basically DNPL alone. DNPL is now being -- capacity is now being enhanced from 1 to 2. So that would, in any case, make it 4 plus.

So whatever we are saying that 4 bcm of gas would be supplied to customers in the Northeast, for which I do not really think that the feeder line has to come immediately. Feeder line would make it -- would make the capacity rise to maybe 7 plus because feeder line is a parallel line, and that would kind of evacuate much larger quantity of gas than the 5.

For 5, we need some network within the fields between the various wells which is OIL's own network -- which would be OIL's own network, plus the DNPL line would make it comfortably 5 plus for which we don't need a feeder line. However, feeder line, the objective is to finally achieve our target of supplying roughly 8 to 9 MMSCMD of gas in the whole of Northeast. And the surplus, if any, that would be supplied through the IGGL network to Mainline India.

So that's what I was referring to. So the expanded capacity of DNPL is what is pending for common carrier approval. So you're expanding the DNPL from 1 to 2.5 MMSCMD 2, 2.5 and the expanded capacity is pending for common carrier approval. Is that the right understanding?

Presently, DNPL line is transporting 1 million gas and they have revamped that line and that capacity will ramp up to 2.5 million. And this can be connected to IGGL if they got the PNGRB clearance, common carrier clearance.

Understood. So the -- I mean, you also mentioned that there's a parallel line which you are planning along with DNPL, right?

Yes. That is the IGGL feeder line up to Duliajan.

So this will be in addition to the 2.5 MMSCMD that you... Yes.

This is still in plan. This is not like incremented as of yet?

Already, this is projected to MOPNG. Once that approved, that line will be laid. Our target is March '27.

March '27, okay. And in case of IGGL, the upper end connection that you mentioned, so what is that connection that is still pending for IGGL?

Once it can -- laid the line, get the permission, then only that upper end connectivity will be there.

No, sir, this upper end connectivity is where? Where is it connecting? Oilfield at Duliajan.

Oilfields connectivity is pending. But the pipeline is ready and...

Pipeline is ready up to Numaligarh. To Numaligarh to this oilfield Duliajan, it is around 165- plus kilometers. Once that permission is given by Ministry, then that Duliajan oil field will be connected, Oil India field will be connected.

Understood. And sir, my second question is with respect to the gas pricing, which was -- I mean, a caller also raised earlier in the call. So we are not able to build the gas as per NWG. So I just wanted to understand that is this gas not eligible for gas swapping? I mean, because -- I mean, can not the swapping of gas make this gas eligible for NWG prices? By swapping, I mean...

Repeat your question. What exactly you mean by swapping?

Yes, sir, I'll elaborate on my question, sir. So if like suppose HPHT or any other gas is being used anywhere else in the country, I mean, gas molecule is gas molecule. I mean, can it not be like virtually swapped in terms of pricing only for Oil India to get a better pricing for its gas? I mean city gas companies in rest of India, I mean, are using HPHT and other -- gas from other sources and paying a higher price for that.

And Oil India is not able to evacuate its gas from Northeast. But in terms of at least pricing, maybe Oil India can get NWG pricing and the city gas companies can accordingly pay NWG price in the rest of the country instead of like waiting for city gas to develop in Northeast and then NWG billing can start. So is that not a possibility, sir?

I'm just trying to answer your question according to my understanding of the question. So now I am saying that there are already CGDs coming up in the Northeast. So for us to sell gas to other CGDs in other parts of the country would arise only after we meet the entire requirement of the CGDs located in the Northeast.

So swapping, whether it will happen or not, that would depend entirely on the surplus that I'm generating after meeting the requirements of the customers in the Northeast, including the CGDs. Now once the Northeast gets connected to the Mainland India, then gas can flow anywhere, and CGDs are buying gas on IGX, that is the exchange at which the gas is traded, that price is a different price.

And for that quantity of the gas, which the CGDs would offtake, I would certainly get a different price. That is not dependent on the nomination price or on the premium gas, et cetera, because CGDs are buying gas based on individual agreements they're entering into with the CGD -- I mean, the buyers -- the CGD buyers are entering into with the suppliers.

So sir, let me expand the point I was trying to make a little bit more. So you are already supplying gas to, say, NRL in Northeast, right? So NRL as per priority order is not eligible for a lower- priced gas, correct?

Is eligible. However, it is lower down in the list. In the priority order?

Yes.

I mean in terms of priority order, city gas gets to the first priority, right? So what I was trying to say is that suppose like right now, we are limited by our evacuation capacity to rest of the country, right, because of the pipeline connectivity. Now I mean, is there a possibility that city gas companies in rest of the country because they are buying gas from exchange for HPHT, whether it's HPHT or any other gas for their consumption.

So is there a possibility that a virtual swap can be done? I mean, in terms of like swapping only the differential pricing is what needs to be charged. And so -- I hope I'm able to make my point, I mean, that NWG pricing -- at NWG pricing, certain volume can be offered from Oil India to these companies and basically exchange, in lieu of that NRL could be charged the higher prices could be, like say, HPHT price.

I mean because at the end of the day, city gas gets a higher priority in terms of gas allocation of whatever domestic APM gas is there, APM and NWG gas is there. So that's what I'm trying to get at because I mean, because our problem is that until and unless city gas develops within Northeast until then you won't be able to bill on NWG, right, unless until that happens?

See, we have made a request to the ministry to let us sell gas to NRL because NRL is a steady customer, not just a customer, there are material ssubsidiary. Now the capacity is being enhanced from 3 to 9. Obviously, their offtake of gas would also go up. So we are -- what we are saying is supposing every gas that I'm producing from the nomination area, the pricing is already fixed.

It is fixed by the government notification.

Only with respect to the gas produced from wells, through new well intervention or some work over operations, that would fetch the premium. But otherwise, the nomination gas price itself is fixed. What we are saying, as you have mentioned, that if you are unable to supply gas to CGDs, who would you supply it to?

I can always supply it to other customers. My only limitation is that I will not be able to get the premium. Apart from that, anything -- any gas that I am producing, I can sell it to customers, not just within Northeast, I can sell it to customers elsewhere also. Now when it goes to customers located in other parts of the country, who is the -- who will help me fix the price? It is only IGX.

So whatever IGX, the price at which gas will be traded at the exchange, I will get that price, irrespective of whether it is produced from nomination, like suppose I'm saying, I have a few pre nelp exploration development fields in the Northeast itself, where the price is different because that's not a nomination area. That price because your PNGRB notifies two prices.

One is the nomination price, other is the -- other than nomination price. Even within Northeast, as we speak, I'm getting a different price for gas produced, say, from my Dirok field. So wherever there are DSF -- I am having DSF fields in the Northeast and some of the fields will soon be monetized.

Once those fields are monetized, the pricing is not dependent on whatever is there in the notification. I mean, there is a notification, but that's a different price. That's a higher price. So

the point that is trying to make is that through well interventions, if you are increasing your production, you will get the premium only if you supply it to CGD first. Maybe after that, there are other companies, maybe third or fourth in the order is the refinery.

Refinery is already there. Now our point is that since refinery -- for the refinery to finally get commissioned and finally operate at its full potential, it will take some time, till such time, let us -- I mean, till CGDs would -- for the CGDs to come up, it will take some time. Refinery is going to be commissioned by end of this year.

So let us allow -- let us be permitted to supply gas to the refinery at the premium. We are not kind of compromising on the premium. If the gas is produced through OIL intervention or through work over operations, the premium that we are entitled to, we must get even from the refinery. But now the refinery is over in the least, we are requesting the government to let us allow supply to the refinery till the CGDs come up. Does that -- I mean...

We have our next question from the line of Hardik Solanki from ICICI Securities.

So if you look at the consolidated numbers, your profit from the associates and JV have jumped sharply to INR724 crores if you look at year-on-year and quarter on. So can you just break down among the subsidiaries or the JVs where these properties flowing from?

You have seen that our PAT in the stand-alone is INR813 crores and the consolidated is INR2,046 crores. We have subsidiaries, associates and joint ventures, both domestic as well as foreign. The major amount which has been contributed by our material subsidiary for increasing the group PAT is INR544 crores from NRL as compared to INR450 crores in the previous year.

The major profit -- share of profit, which has came from our Russian investment, as I already mentioned in my opening remarks, is that in previous year, we had INR150 crores of and the current year, it is INR780 crores. This makes the major difference between our group performance as compared to the previous year. This is INR540 crores and INR780 crores from these two companies. One is our Russian investment of INR780 crores and INR544 crores from our major subsidiary.

We have a follow-up question from the line of Somaiah V from Avendus Spark.

Sir, in terms of this Russian assets dividend payment, from Taas, this is an annual payment that we have received for the previous calendar year. That is one. And with respect to last year, this number being lower, is it more to do with the payment ratio or is it to do with the performance in the previous year? That is with respect to Taas. And Vankorneft, in general, what is the dividend that we can expect in a year, so based on last 1 or 2 years, what we have seen as a precedence?

See, as far as the Taas-Yuryakh project is concerned, I'll give a rough number received in the last 2 years. In 2023, we received an amount of USD 51.5 million equivalent of dividend inflow that is corresponding to the share of Oil India stake in that project. That number went up to USD 70 million in '24. And in '25, as of now, we have received around USD 17 million of dividend.

And we expect that the amount of dividend that we have received last year will almost receive that -- to that extent, we will receive a similar dividend is expected. However, it is conditional upon the geopolitical situation and how the price is moving going forward. So this is about us and as far as the Vankor is concerned.

Vankor asset has given us a dividend of USD 37 million in '23 and that has gone up to USD 39.6 million or USD 40 million -- close to USD 40 million approximately in 2024. During the current year of 2025, we have received so far USD 11.2 million from the Vankor asset, and we expect the trend to continue for the current year also.

Quite helpful. Sir, if you could just help us with the net debt numbers at NRL and the excise duty hike that was taken last quarter, so we have that benefit in NRL?

Yes. So with regard to excise duty, on 7th of April, the excise duty rates increased by INR2, which has benefited by INR1 in our -- INR1 per liter for both MS and HSD for NRL. In the first quarter, our Northeast -- the impact of the increase in excise duty has been INR118 crores in our profit amount.

We have our next question from the line of Vivekanand from Ambit Capital.

My question is on the gas output. You mentioned that there were certain constraints you faced in stepping up gas output because of maintenance of NRL and also some shutdowns of the fertilizer and power plants. Was this unusual or was it similar to the shutdowns that happened last year? And on a related note is that now when you have given a guidance for the rest of the fiscal year, which implies a healthy growth in gas output. What gives you the confidence of getting that output?

This is not unusual. This is usual. This is the manual maintenance or breakdown maintenance work they are doing. So this is natural. And regarding your question that once the DNPL line is completed, then this type of problem will be resolved and they got the connectivity with IGGL.

As there are no further questions from the participants, I now hand the conference over to Mr.

Varatharajan from Antique Stock Broking for closing remarks. Over to you, sir.

Thank you, Manav. Sir, if you have any closing remarks, please go ahead.

I would like to thank all the participants for their -- I mean, for very insightful questions. And I hope that we have had a nice interaction with the participants. And thank you so much. Thank you, AMBIT, for organizing this. for organizing this -- Antique for organizing this.

Thanks all the participants, and thank the management for patiently answering all these questions. Have a nice day.

Thank you, sir. On behalf of Antique Stock Broking and Oil India Limited, that concludes this conference. Thank you for joining us, and you may now disconnect your lines.