Oil and Natural Gas Corporation Limited (ONGC) Earnings Call Transcript

Good afternoon, ladies and gentlemen. I'm Palsheya, moderator for the conference call. Welcome to ONGC's Earnings Conference Call for quarter ended 30th September 2025. We have with us today Vivek Tongaonkar, Director of Finance, ONGC and team who will interact with investors and analysts to discuss Q2 earnings. [Operator Instructions] Please note this conference is recorded. I would now like to hand over the floor to Mr. Shri Vivek Tongaonkar for his opening remarks. Thank you, and over to you, sir.

Thank you very much, and good afternoon, ladies and gentlemen. To introduce, I am Vivek Tongaonkar, Director of Finance, ONGC. I welcome you all in this ONGC earnings call for Q2 financial year '26. Thank you for joining on this call. I am joined here by my colleagues from ONGC, Shri Ajay Kumar Singh, Chief Corporate Planning; Shri Satish Kumar Dwivedi, Chief JV & BD; Shri Yogish Nayak, Chief Corporate Finance; Shri Akhilesh Tiwari, Head, Corporate Accounts; Mr. Prakash Joshi from Investor Relations. We also have Mr. Bhishmadev Mandal and Mr. Raj Kumar Das from ONGC Videsh Limited. ONGC has compiled its financial results for the quarter ended 30th September 2025, which have been reviewed by the statutory auditors. The financial results have already been released on 10th November 2025 through a press note and sent to the stock exchanges. This has also been sent to the analysts who are there on our mailing list. Brief highlights of the quarterly performance are as under. ONGC's crude oil production continues to grow on a quarter-on-quarter basis. The stand-alone crude oil production during Q2 financial year '26 and H1 financial year '26 were 4.630 million metric tons and 9.314 million metric tons, respectively, registering a growth of 1.2% over the corresponding period of financial year '25. On the gas production front also, ONGC has been able to arrest the degrowth. The decline, which was 0.35% in Q1 financial year '26 over financial year -- Q1 financial year '25 has been brought down to 0.04% in Q2 financial year '26 over Q2 financial year '25. Gas from new wells continues to be the key contributor with revenue from new well gas reaching INR 3,352 crores in H1 financial year '26. This delivered an additional INR 651 crores compared to the APM gas price as gas from the new wells is eligible for a 20% premium over the domestic APM gas price. Notably, the share of new oil gas surpassed 21% of total gas revenue from ONGC during the period, reflecting its rising importance in ONGC's gas portfolio. In line with its consistent dividend paying track record, the ONGC Board has approved an interim dividend of 120%, translating to INR 6 per equity share of INR 5 face value. The total payout on this account amounts to INR 7,548 crores. Now we come to the financials. The company at a consolidated level has earned a higher net profit, that is profit after tax of INR 12,615 crores during the second quarter of financial year '26 as against INR 9,841 crores during the second quarter of FY '25, an increase of INR 2,774 crores, 28.19%. This increase in profit is mainly attributed to our subsidiaries, HPCL and MRPL. Consolidated profit for H1 financial year '26 stood at INR 24,169 crores as against INR 19,617 crores in H1 financial year '25, an increase of INR 4,552 crores, 23.2% higher. The company on a stand-alone basis has earned a net profit, that is profit after tax of INR 9,848 crores during Q2 financial year '26 as against INR 11,984 crores during Q2 financial year '25, which is a decrease of INR 2,136 crores, 17.8%. This decrease in net profit during Q2 financial year '26 is on account of lower crude oil price realization of $67.34 per barrel in the current quarter against $78.33 per barrel in Q2 financial year '25. Also, lower interest and dividend income by INR 1,462 crores and exchange rate fluctuation of INR 1,045 crores. Sales revenue in Q2 FY '26 declined primarily due to a INR 1,340 crores drop in crude oil revenue and INR 424 crore reduction in value-added products, which was partially offset by an increase of INR 1,006 crores in natural gas revenue compared to the same quarter last year. While higher crude oil sales volumes contributed INR 1,165 crores, this was offset by INR 2,505 crore decline due to lower crude oil price realization resulting in a net decrease. The rise in gas revenue was driven by an increase in the ceiling price of nomination gas from USD 6.5 per MMBtu to USD 6.75 per MMBtu and incremental revenue of INR 318 crores from new well gas sales. During Q2 financial year '26, the expenditure on account of statutory levies is INR 6,470 crores as compared to INR 7,830 crores for Q2 FY '25. This is a decrease of INR 1,350 crores, which is 17.4%. This decrease is attributable mainly to abolishing of SAED on crude oil with effect from 2nd December 2024, which was INR 1,128 crores in Q2 '25 and decrease in average selling price of crude oil from INR 49,150 per metric ton in Q2 financial year '25 to INR 44,043 per metric ton in Q2 FY '26. In Q2 FY '26, operating expenses stood at INR 6,875 crores against INR 6,389 crores in Q2 financial year '25. Raw material consumption costs increased by INR 346 crores quarter-on-quarter basis due to increase in LNG consumption costs, mainly at Dahej C2-C3 plant, which amounted to INR 273 crores. DD&I that is depreciation, depletion and impairment costs for Q2 FY '26 stood at INR 6,358 crores as against INR 5,598 crores during the corresponding period of previous year. That is an increase of INR 770 crores. Increase in depletion expenditure is attributed to INR 285 crores at Western Offshore WO-16 field on account of increase in production, INR 221 crores at KG-98/2 field due to increase in carrying value of ONG assets, oil and gas assets related to capitalization of A and P fields. The increase in depreciation by INR 199 crores is mainly at Western Offshore, which was made up partly because of INR 105 crores due to addition in ROU assets related to hiring of additional vessels that is 18 OSVs, 2 WSVs and MSVs and extension of FPSO hiring for C7 field. With BP-led TSP advancing as for redevelopment of the MH field, scheme for revival of KG 98/2 and combined Western Offshore development plan, ONGC is strategically positioned to counterbalance declines from mature fields. Accelerated monetization of new hydrocarbon discoveries alongside a sharper focus on deepwater and ultra-deepwater exploration is expanding ONGC's resource base. These efforts accompanied by enterprise-wide cost optimization and digital integration across workflows are expected to boost operational efficiency and reinforce ONGC's resilience in the quarters ahead. Well friends, with this, I finish my briefing of the second quarter results of financial year '25-'26. We will be happy to take your questions from you. We would request you to restrict your queries on financial results only. Thank you.

[Operator Instructions] The first question comes from Probal Sen from ICICI Securities.

If I look at the H1 run rate of -- am I audible, sir?

Yes. Go ahead.

I was saying that if I look at the H1 run rate of oil and gas production versus the annual guidance, do you think that there is any downside risk that we face? Because I believe the guidance was close to, I think, 21 million tonnes of oil for the full year. We are at about 9.3 for H1. Similar number for gas also suggest that this could be a small miss on the guidance. Is that a fair way to look at it, sir?

Yes. So for this year, current year, '25-'26, we have had certain -- a little bit downside from what we were expecting. Most likely, the production is likely to shift a little bit quarter into the next year. But we are expecting that, again, the 21 what we had given, we should be approaching 20 million metric tons for crude oil. And as far as gas is concerned, it would be slightly lesser than the 21.5 BCM that we had projected -- gas would be slightly lesser than 21.5 BCM that we had projected. However, we expect that in the next quarter -- in the first quarter of the next year, things would make up for this deferment of production.

Sir, if I can ask what is the run rate of the Eastern Offshore field including KG right now, in terms of gas amount and what is the kind of exit rate that you expect?

For KG 98/2, currently, we are having 28,000 barrels of oil per day, and that is what is actually affecting our production estimates for this year.

And for gas, sir?

Gas is 3 MMSCMD. And we had already mentioned earlier on that for KG 98/2, we are to install the living quarters once that -- those get installed at offshore during December, January -- coming December, January, we expect that gas production would get ramped up at 98/2 by end of the last quarter of this year.

Understood. The second question was with respect to OPaL. We have seen quite a sharp improvement in terms of the EBITDA run rate. Just wanted to understand how should we look at the business for the next two quarters? Are we seeing an improvement in realizations, or, I mean, what has really driven the kind of improvement we have seen in terms of EBITDA? Can we expect a similar run rate for the next couple of months?

So we are expecting that the plant would run on capacity, fairly good capacity. It would be 90-plus capacity that we would have for the following -- for these 2 quarters. And we are expecting that with the current rates or the prices that we have and the run rate that we would be having, we should have positive EBITDA for these coming quarters.

All right. Last question, if I may, sir, you mentioned about NWG, New Well Gas being now 21% of the total gas revenue. Can we get a sense of what it is as a share of the overall production right now, NWG?

So you want the quantum for that NW gas?

Yes, sir. If I can get the volume number for renewable gas.

Hello?

Yes, sir.

Yes. Currently about 13.4% and we should increase it or ramp it up to up to 14%.

1 - 4, 14%, right?

Right.

The next question comes from Sabri Hazarika from Emkay Global.

So I have a couple of questions. Firstly, in the presentation where you have mentioned regarding the cost optimization. So you have mentioned the 15% cost reduction. So if I look into your CapEx plus OpEx, it is roughly INR 60,000 crores. So does it mean that -- I know it's like -- I mean, just wanted some clarity, does it mean INR 8,000 crores, INR 9,000 crores of cost reduction will happen over the next few years? How to look about it?

So we are targeting that we should have a reduction of about INR 5,000 crores in OpEx -- hello?

Yes.

So towards that end, we have already started taking action. We have already reduced our cost towards logistics when we have started operations from Pipavav port. So that cuts down on the distance that we have for servicing our locations -- offshore locations in the Western Offshore. So that is reducing the number of vessels that we have to run over there. We have also started operations from our -- chopper operations from Surat, which takes care of the transfer of manpower from Surat towards the northern end of these fields. We have -- we would also be considering for hiring of bigger vessel sizes because from Pipavav, we can -- it being a regular port, it is possible to have a bigger size of vessels to ply between our offshore fields and the mainland then. So that reduces our logistics costs. It also cuts down on the HSD. We have also improved -- optimized the diesel consumption for our drilling rigs, both at onshore and offshore. And we are taking -- for -- individually for those rigs also, we are taking steps to convert some of those onshore rigs to dual fuel, that is gas as well as HSD. We are looking at reducing our power costs also by considering gas from the -- green gas from the grid as well. And in the long run, we plan to set up our own green solar and wind power plants, which would come up -- should come up in the next 18 months to 2 years, which would cut down on the power cost that we are -- that we would be utilizing. We are also optimizing on the rig building that happens when the interlocation movement of the rigs that happens in onshore. We are also shifting from our -- reducing our cost on workover operations by utilizing smaller-sized rigs rather than the drilling rigs, which we use. So all these are likely to translate into savings for us over a period of time of about INR 5,000 crores.

Okay. So this is on -- purely on OpEx and CapEx side?

CapEx, we have our robust CapEx going on. We are not going to cut down on our exploration, et cetera, continue to have around INR 30,000 to INR 35,000 crores CapEx for the years. And even in this year, we will be having on similar lines.

[Operator Instructions] The next question comes from Varatharajan Sivasankaran from Antique Stockbroking.

Sir, if you can give us the guidance on production for FY '27 as well and what all will contribute to that production growth, primarily from Western Offshore, Mumbai High as well as Daman and other developments? Anyway, Eastern Offshore, you've already given some idea.

Varatharajan, good afternoon and I'll just give a brief about this thing. See, you are aware that we have already engaged BP as a TSP for our Western for MH field. And we had mentioned that it would start -- hopefully, it should start giving us some green shoots from January onwards. So we are happy to note that, yes, we are already seeing certain uptick happening in our production of oil and gas for MH field. So that is on the Western Coast. So we do expect that during this year itself, we should have some positive story coming over there. Then we have also mentioned Daman upside project, which is running -- it is running ahead of schedule. We do -- we expect that in the last quarter of this year, we should have production coming out of that field also. For the next year, we have already mentioned on DSF-II field, which is under -- already under development. And in that case, for the last quarter of '26, '27, we expect that production to come up on stream as such.

Just for completion sake, if you can give us the number as well in terms of production for oil and gas, which you...

Sure, sure. Just hold on. As we reiterated previously, so our stand-alone production for the current year, oil, we expect 19.8. And for next year, it is 21 MMT. And as far as gas is concerned, it is 20 for the current year, and it is 21.5 for the next year. And thereafter, it would be in the same lines that we would come up with a figure once our -- some of the projects, as sir already told, those would be reaching their peak production.

Great. My second question was on Mozambique. We keep hearing a lot of news online. If you have an official version of it, if you can please reiterate that.

Yes. As of now, all the partners have decided to lift the force majeure. So we are expecting that ballot to happen either today or tomorrow. And once that happens, then it would be officially that force majeure would be lifted. Already all the partners have decided that they would lift the force majeure. However, that -- till the ballot happens, it would not be a final event, so to say. So maybe in a couple of days, we should be in a position to confirm that. But you would have already read that Oil India and BP have already -- BPRL have already informed the stock exchange that we have decided or partners have decided to lift the force majeure. So once it is lifted, we would also be informing accordingly. So once that...

So in that case, do you have any update on the hike in CapEx cost. And in case that hike has to be also officially approved by all the partners, is that a requirement? Or you are already okay with that?

The CapEx for the current year -- for the total [indiscernible] project. So currently, the ministry has been approved for the $18.2 million. But after force majeure lifting, if the situation as well as the validation of all projects, if it go beyond that, so then we will come to CCA for further approval, then the decision will be known.

Could you get that Varatharajan?

Yes, I got it, sir. If I may, I just wanted a follow-up on that as well. So effectively, once you lift the force majeure, you are back in terms of full-fledged activity in terms of development? Or is there another step because we were also mentioning last time about the government also supposed to complete some procedure of approval.

So Mozambique government are you asking?

Yes.

Mozambique government already has given the nod for this for force majeure approval. Only the operator, they want to get some sort of clarity from the -- security clarity from the government. So now that part is already over. So now all the partners have agreed for the force majeure lifting. Even though the regulator in NHI, we have submitted the force majeure lifting documents to NHI. Only the ministry, we have to submit because the last 2 or 3 days because of the closing holidays, we could not able to submit. So by...

So it is expected that both the parties, that is all the contracting parties and the government of Mozambique have already more or less arrived at a finalization of lifting this FM, and this is likely to happen in a couple of days. That is what we are waiting for.

The next question comes from Mayank Maheshwari from Morgan Stanley.

I had one question on OPaL. And one was related to, I think, any impact that you are seeing on the OVL side because of geopolitical tensions. If you can kind of talk about on OPaL, obviously, your utilization rate this quarter came down versus last quarter. You're talking about 90% or so. Like at what level of PE prices do you think it will kind of become a bit more profitable because it is still kind of going through that losses right now. So is there a pricing level where you kind of thought about? And why did you see a bit of utilization rate cut? And the second question was on OVL, like you've seen production decline again this quarter. So can you just give a bit of outlook on what's going on there?

On OPaL, there was briefly reduction in that capacity utilization because they had a breakdown in one of the equipment, which has since been made good, and it is again operational. So for about 1 month, there was a lockdown in that -- in OPaL plant. That is why the capacity utilization has been lesser. However, that is now working on -- they are back on stream, so to say, and they should be performing at full -- at 90-plus capacity during the next -- these 2 quarters as such. So we do not envisage anything adverse now. And we are expecting with the prices that are there for petrochemicals, they should have -- they would be EBITDA positive. That is for as far as OPaL goes. As far as OVAL, Mandal Ji, you can add.

About the OVL production, for this H1, the production was around 4.8. So -- and we are expecting [ margin for ] current year, the production [Technical Difficulty] 10 MMToe. And this will be continued for another -- next year too. The last year production was around 10.278, around 2.8, so the little drop in the H1, one is -- [ at least one was ] under shutdown for one month. This was the planned shutdown. Hopefully, in the H2, things will be normal, and we will range in the range of 10...

And any update on the Vietnam extension?

Vietnam extension is there for 16 years, but currently, the production from the Block 6.1, so we have ceased production from July 1, 2025 because it is uneconomical. So we are just awaiting the Vietnam government here to develop the PLDD area. If we are able to drill those oil in that PLDD area, then we can resume our operation further. But currently, as it is uneconomical, from July 1, 2025, we have stopped our production. I just want to mention, this Vietnam is in the end of its project life.

Yes. Just Mayank, to add to your thing, even when this OPaL plant was not running to full capacity, we have had an EBITDA of INR 225 crores positive. Going forward, as capacity utilization improves, it will be better.

Also for quarter.

The next question comes from Gagan Dixit from Elara Securities.

Sir, my question is regarding the -- your Mumbai high plant with the British Petroleum. So can you break into some concrete milestones for FY '26, '27? I mean number of wells workover, what are your plans? And also this -- when do we expect that this contract will be converted into the performance link will from the fixed fees? That's -- if any, some idea you have, sir?

So as far as the number of wells, et cetera, is concerned, that is not yet there. We have -- both the companies are working together on the technical part of it, and they have started utilizing the existing CapEx that we have over there and all the wells that we have over there. And now onwards, it will start coming up. That plan is currently under preparation, and it should be there by this December -- calendar year-end as such. When it would come up for that incentive part of it or move out of that fixed fee, it is 2 years from the start of the project, which was sometime in January this year. So it should be '27, -- January '27 onwards, it should be moving it -- that fixed fee should stop.

Okay. Okay. And sir, how will those payments will be shown up in your P&L? It's OpEx or CapEx or it's a mix of both, sir?

It should be OpEx only? Because -- service provider, I would say.

The next question comes from Nilesh from HDFC Securities.

Am I audible?

Yes, yes, audible.

While answering one question, you mentioned that this year, your production, crude oil as well as gas production will be below your expected line. And in next year, quarter 1, you will recoup that. The production is expected to go up. So what are the steps that you are taking to boost that in Q1 and that gives you confidence that the volume will go up for crude as well as for gas?

So that production, which I have said that it will be coming up more in the next -- first quarter of the next year is more of a deferred production, so to say, because our -- for KG 98/2, we would be having our living quarter setup being installed during December, January and January, February, it would happen. So part of that production, which otherwise we were expecting in the last quarter -- full part of the last quarter will get deferred as such. And some we are expecting from TSP, as I've already mentioned, that from TSP from January, we are expecting green shoots. We are expecting that there should be more healthier production subsequently. So this is -- that is how we are expecting that the production will be increasing in the -- from the first quarter of the next year.

Sir, Prakash sir mentioned about the estimated production for FY '27. So this includes those increase after this increase particularly mandated by...

No. It is -- what he had mentioned was when we had earlier planned this living quarters, et cetera, to happen in November, December this year and that production to start for the full quarter in December and January of this year as such. So that is getting a little delayed. It is coming in December, January, which moves everything into a -- partly into that monsoon period also, which then affects this thing. So that is why part of the production, which was scheduled to come in this year has reduced. It will go into the next year. What Prakash told you, those figures do not have that additional production or the deferred production, so to say, as of now.

[Operator Instructions] The next question comes from Ramesh S, an individual investor.

So if you look at your new well gas production, we had been going to understand in the past that it will ramp up by a certain proportion every year over the next 5, 10, 15 years. So can you give us some idea in terms of the production profile to peak production and how long that kind of profile can be sustained, say, over the next 10, 15 years? And when did it start declining based on the investments you are making in the infill drilling and new wells?

See, I'm Ajay Singh, Chief Corporate Planning. Every year, there is a natural decline of 7.5% from the natural gas that we are bridging by the way of drilling new wells or by intervening in the well by way of workover. So whatever we are intervening in the well or we are drilling the new wells that comes under the new well gas. So when I...

That I understand. So I'm just asking for the new well gas production, but for the investments you are making, is it possible to give us some kind of a production profile for the increase and then peak production and then when that new well gas production itself will start declining?

See, for next 4 to 5 years, when we are introducing our Daman upside, which is likely to come in this current year, we are expected to add by 5 million of metric -- 5 MMSCMD of gas in this year. And next year, we are going to commission the DSF-II, which will be adding another 4 million. So both put together, 9 million is addition. So currently, what we are producing is around 20 million. So we'll be producing near about 24 million. So that's considering the decline 24 to 25 MMSCMD. So that is the target. And another, if you add to next year the CB '27, '28, we'll be producing in this range only. So this is our plan projected, so you can see that near about 30% to 35% of our entire production will come from the new well, yes.

Okay. So you're saying that basically based on the increase in the new well production for gas, you'll be able to offset the decline and see some incremental growth, and that will sustain for about 5, 10 years. That's what you're saying, right?

See, right now, I'm not talking about 5 to 10 years. We are talking about 3 to 4 years. This is short term. And long term, we have another plan, which will be included in our Andaman field also and in deepwater, which may come. So that right now, we are not able -- we'll not be able to tell you that.

Okay. So if you look at the segment numbers, the EBIT margin you're reporting in the onshore is lower than that of the offshore EBIT margin for the latest quarter. So is there any operating reason for that? What exactly? Because onshore cost should be lower. So what is driving that difference in the higher EBIT margin for offshore compared to onshore?

So normally, offshore operations are more profitable as a thumb rule also. And onshore production, because it is lesser, there are a number of costs that are involved over there because most of our onshore fields are mature fields. They are -- some of them are older than 60 years old. So they naturally are more expensive to operate. Therefore, onshore is always a little bit lesser positive than offshore fields.

Okay. So one last question on this BP contract. So once the BP consulting inputs are already showing the benefits, when do you start seeing the benefit of the higher oil and gas production? And from which quarter can we expect that to actually be visible in your EBITDA and profit after tax? Can you give us some rough sense on what will be the ramp-up in that production volume, say, over the next 2, 3 years?

So as I've already mentioned earlier, under TSP, we have -- we are likely to see green shoots from January -- coming January onwards. We have got some positive indications already. But as you mentioned, to make a difference as far as profit is concerned, it would -- it should happen from January onwards. And under this contract, what has been committed, so to say, by BP is that over a 10-year period, we should increase our oil and gas production from MH field by about 60%, 6-0 percent on a cumulative basis.

So this 60% increase, when will that peak production happen, just to get a sense of when it will start showing the full benefit of the free cash flows? Will it be by FY '28, Will it be by FY '30? Any sense you can give on that?