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. As a reminder, all participants will be in listen-only mode, and there will be an opportunity for you to ask questions after the presentation concludes. Should you need assistance during the conference call, please signal an operator by pressing star then zero on your touchstone telephone. Please note this conference is recorded. I would now like to hand over the floor to Mr. Sri Vivek Tongaonkar for his opening remarks. Thank you, and over to you, sir.
Thank you very much. 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 2026. Thank you for joining on this call. I am joined here by my colleagues from ONGC: Sri Ajay Kumar Singh, Chief Corporate Planning; Sri Satish Kumar Dwivedi, Chief JVBD; Sri Yogesh Naik, Chief Corporate Finance; Sri Akhilesh Tiwari, Head Corporate Accounts; Mr. Prakash Joshi from Investor Relations. We also have Mr. Bhishmadev Mandal and Mr. Rajkumar 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 quarter-on-quarter basis. The standalone crude oil production during Q2 financial year 2026 and H1 financial year 2026 were 4.630 million metric tons and 9.314 million metric tons, respectively, registering a growth of 1.2% over the corresponding periods of financial year 2025. On the gas production front also, ONGC has been able to arrest the degrowth. The decline, which was 0.35% in Q1 financial year 2026 over Q1 financial year 2025, has been brought down to 0.04% in Q2 financial year 2026 over Q2 financial year 2025. Gas from new wells continues to be the key contributor, with revenue from new well gas reaching INR 3,352 crore in H1 financial year 2026.
This delivered an additional INR 651 crore 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 well gas surpassed 21% of total gas revenue from nomination fields 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 crore. 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 crore during the second quarter of financial year 2026, as against INR 9,841 crore during the second quarter of financial year 2025, an increase of INR 2,774 crore, 28.19%.
This increase in profit is mainly attributed to our subsidiaries, HPCL and MRPL. Consolidated profit for H1 financial year 2026 stood at INR 24,169 crore, as against INR 19,617 crore in H1 financial year 2025, an increase of INR 4,552 crore, 23.2% higher. The company on standalone basis has earned a net profit, that is, profit after tax of INR 9,848 crore during Q2 financial year 2026, as against INR 11,984 crore during Q2 financial year 2025, which is a decrease of INR 2,136 crore, 17.8%. This decrease in net profit during Q2 financial year 2026 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 2025. Also, lower interest and dividend income by INR 1,462 crore and exchange rate fluctuation of INR 1,045 crore.
Sales revenue in Q2 FY 2026 declined primarily due to an INR 1,340 crore drop in crude oil revenue and an INR 424 crore reduction in value-added products, which was partially offset by increase of INR 1,006 crore in natural gas revenue compared to the same quarter last year. While higher crude oil sales volumes contributed INR 1,165 crore, this was offset by an 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 $6.5 per MMBTU to $6.75 per MMBTU, and incremental revenue of INR 318 crore from new well gas sales. During Q2 financial year 2026, the expenditure on account of statutory levies is INR 6,470 crore, as compared to INR 7,830 crore for Q2 FY 2025. This is a decrease of INR 1,360 crore, which is 17.4%.
This decrease is attributable mainly to evaluation of SAD on crude oil with effect from 2 December 2024, which was INR 1,128 crore in Q2 2025, and decrease in average selling price of crude oil from INR 49,160 per metric ton in Q2 financial year 2025 to INR 44,043 per metric ton in Q2 FY 2026. In Q2 FY 2026, operating expenses stood at INR 6,875 crore against INR 6,389 crore in Q2 financial year 2025. Raw material consumption costs increased by INR 346 crore quarter-on-quarter basis due to increase in LNG consumption cost mainly at Dahej C2-C3 plant, which amounted to INR 273 crore. DD&I, that is, depreciation, depletion, and impairment cost for Q2 FY 2026 stood at INR 6,368 crore, as against INR 5,598 crore during the corresponding period of previous year, that is, an increase of INR 770 crore.
Increase in depletion expenditure is attributed to INR 285 crore at Western Offshore WO-16 field on account of increase in production, INR 221 crore at KG 98/2 field due to increase in carrying value of ONGC asset oil and gas assets related to capitalization of A and P fields. The increase in depreciation by INR 199 crore is mainly at Western Offshore, which was made up partly because of INR 105 crore 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 for redevelopment of the Mumbai High 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. Friends, with this, I finished my briefing of the second quarter results for financial year 2025-2026. We will be happy to take your questions from you. We would request you to restrict your queries on financial results only. Thank you.
Thank you, sir. Ladies and gentlemen, we will now begin the question and answer session. If you have a question, please press star and one on your telephone keypad and wait for your turn to ask the question. If you would like to withdraw your request, you may do so by pressing star and one again. The first question comes from Prabhalsan from ICICI Securities. Please go ahead.
Yeah, thank you for the opportunity. There are a couple of questions. Firstly, if I look at the H1 run rate of—am I audible, sir?
Yeah.
Yeah. Go ahead. 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 tons of oil for the full year. We are at about 9.3 for H1. Similar numbers for gas also, such as that it could be a small miss on the guidance. Is that a fair way to look at it, sir?
Yeah. For this year, current year, 2025-2026, 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 that next year. We are expecting that, again, the 2021 what we had given, we should be approaching 20 million metric tons for crude oil. 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.
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 we 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.
For gas, sir?
Gas.
Gas is 3 million. Gas is 3 million MMSCMD. We had already mentioned earlier on that for KG 98/2, we are to install the living quarters. Once those get installed at offshore during December, January, coming December, January, we expect that the 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?
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 two, for these two quarters. 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 is, I know, sir, you mentioned about NWG, the new well gas being about 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?
You want the quantum for that NW gas?
Yes. If I can get the volume number for new well gas?
Yeah. Just hold on.
Yeah. Hello.
Yes, sir?
Hello.
Yeah.
Yes, sir.
Currently, we'll be about 13.4%, and we should increase it or ramp it up to up to 14%.
14%, right?
Right.
All right, sir. Thank you. I'll come back. Thank you so much for your answers. All right.
Thank you. The next question comes from Sabri Hazarika from Emkay Global. Please go ahead.
Yeah, good afternoon. I have a couple of questions. Firstly, the presentation where you have mentioned regarding the cost optimization, you have mentioned the 15% cost reduction. If I look into your CapEx plus OpEx, it is roughly INR 60,000 crore. Does it mean that, I know, it's like, I mean, just wanted some clarity. Does it mean that INR 8,000-INR 9,000 crore of cost reduction will happen over the next few years? How to look about it?
We are targeting that we should have a reduction of about INR 5,000 crore in OpEx or in our hello?
Yeah.
Yeah. 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. That cuts down on the distance that we have for servicing our locations, offshore locations in the Western Offshore. 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 would also be considering hiring of bigger vessel sizes because from Pipavav, 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. That reduces our logistics costs. It also cuts down on the HSD.
We have also optimized the diesel consumption for our drilling rigs, both at onshore and offshore. 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. In the long run, we plan to set up our own green solar and wind power plants, which should come up in the next 18 months to 2 years, which would cut down on the power cost that we would be utilizing. We are also optimizing on the rig building that happens when we interlocation movement of the rigs that happens in onshore.
We are also shifting from our reducing our cost on worker operations by utilizing smaller size rigs rather than the drilling rigs which we use. All these are likely to translate into savings for us over a period of time of about INR 5,000 crore.
Okay. So this is purely on OpEx. And CapEx side?
CapEx, we have our robust CapEx going on. We are not going to cut down on our exploration, etc. Continue to have around INR 30,000-INR 35,000 CapEx for the years. Even in this year, we will be having on similar lines only.
Got it, sir. That's all from my side. Thank you so much.
Thank you. I request the participants to restrict with two questions in the initial round and join back the queue for more questions. The next question comes from Varatharajan Sivasankaran from Antique Stock Broking. Please go ahead.
Thanks for the opportunity, sir. Sir, if you can give us the guidance on production for FY2027 as well and what all will contribute to that production growth, primarily from Western Offshore Mumbai High as well as KG and other developments. Anyway, Eastern Offshore, you have already given some idea.
Yeah. Varadarajan, good afternoon. 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. We had mentioned that it would start, hopefully, it should start giving us some green shoots from January onwards. We are happy to note that, yes, we are already seeing certain uptick happening in our production of oil and gas for MH field. That is on the Western coast. We do expect that during this year itself, we should have some positive story coming about over there. We have also mentioned Daman Upside project, which is running on, it is running ahead of schedule. 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 DSF2 field, which is already under development. In that case, for the last quarter of 2026-2027, we expect that production to come up on stream as such.
Just for completion's sake, if you can give us the number as well in terms of production for oil and gas, which is.
Sure, sure. Just hold on. As we stated previously, our standalone production for the current year, oil we expect 19.8, and for next year, it is 21 MMT. As far as gas is concerned, it is 20 for the current year, and it is 21.5 for the next year. Thereafter, it would be in the same lines that we would come up with a figure once some of the projects, as sir already told, those would be reaching their peak production.
Great, thank you. 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. Thank you.
Yeah. As of now, all the partners have decided to lift the force majeure. We are expecting that ballot to happen either today or tomorrow. 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, till the ballot happens, it would not be a final event, so to say. Maybe in a couple of days, we should be in a position to confirm that. We would have already read that Oil India and BPRL have already informed the stock exchange that they have decided or partners have decided to lift the force majeure. Once it is lifted, we would also be informing accordingly.
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?
See, for the CapEx for the current year, for the total CapEx, currently, the ministry has approved $18.2 million. After post-finger lifting, if the situation as well as revaluations of all projects, if it goes beyond that, we will come to CCA for further approval. The decision will be known then.
Okay. Could you get that, Varatharajan?
Yeah, I got it, sir. If I may, I just wanted to follow up on that as well. Effectively, once you lift the force majeure, you are back in terms of inflation 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.
The Mozambique government, are you asking?
Yes.
Mozambique government already has given the nod for this force majeure approval. Only the operator, so they want to get some sort of clarity from the security, clarity from the government. Now that part is already over. Now all the partners have agreed for the force majeure lifting. Even though the regulator, NHI, we have submitted the force majeure lifting documents to NHI. Only the ministry we have to submit because the last two or three days, because of their closing holidays, we could not be able to submit. By.
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.
Great, sir. That's very useful. Thanks a lot.
Yes.
Thank you. The next question comes from Mayank Maheshwari from Morgan Stanley. Please go ahead.
Thank you for the call, sir. 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 are talking about 90% or so. 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? Is there a pricing level that you kind of thought about, and why did you see a bit of utilization rate cut? The second question was on OVL. You have seen production decline again this quarter. Can you just give a bit of outlook on what is going on there?
Okay. On OPaL, there was briefly reduction in that capacity utilization because they had a breakdown in one of the equipments, which has since been made good, and it is again operational. For about one month, there was a breakdown in that 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 capacity, at 90% plus capacity during these next two quarters as such. We do not envisage anything adverse now, and we are expecting with the prices that are there for petrochemicals, they would be EBITDA positive. That is for as far as OPaL goes. As far as OVL, Mandalji, can you add?
About the OVL production, for this H1, the production was around 4.8. We are expecting for this current year, the production will be in the range of 10 MMTA. This will be continued for another next year too. The last year production was around 10.278, around 2.8. The little drop in the H1, one is H1 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 MMT.
Any update on the Vietnam extension?
Vietnam extension is there for 16 years, but currently, the production from the Block 06.1. We have ceased production from July 2025 because it is uneconomical. We are just awaiting the Vietnam government here to develop the PLDC area. If we are able to drill those oil in that PLDC area, then we can resume our operation further. Currently, as it is uneconomical, from 1 July 2025, we have stopped our production. I just want to mention, this Vietnam is in the end of its project life.
Okay. Thank you.
Yeah, just mine to add to your thing. Even when this OPaL plant was not running to full capacity, we have had an EBITDA of $225 million positive. Going forward, as the capacity utilization improves, it will be better.
Also, for quarter. Perfect. Thank you.
Thank you. The next question comes from [Gagandeksit] from Elara Capital Securities. Please go ahead.
Yeah, thanks for taking my question, sir. Sir, my question is regarding this Mumbai High plan with British Petroleum. Can you break into some concrete milestones for FY 2026-2027? I mean, number of wells, workovers, what are your plans? Also, when do we expect that this contract will be converted into the performance link from the fixed fee? That's any, some idea you have, sir?
As far as the number of wells, etc., is concerned, that is not yet there. We have reached, 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 or the wells that we have over there. Now onwards, it will start coming up. That plan is currently under preparation, and it should be there by this December, this calendar year end as such. When it will come up for that incentive part of it or move out of that fixed fee, it is two years from the start of the project, which was sometime in January this year. It should be January 27 onwards, it should be moving it. That fixed fee should stop.
Okay, okay. Okay. Sir, how will those payments be shown up in your P&L? It's an OpEx or CapEx or it's a mix of both, sir?
CAP. It should be OpEx only. Because CapEx is not paying for service.
Service provider. Okay, okay, sir. Okay, that's from my end, sir. Yeah. Thanks.
Thank you. The next question comes from [Nilesh] from HDFC Securities. Please go ahead.
Yeah, hi. Good afternoon, sir. Am I audible?
Good afternoon.
Yeah, yeah, 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. In next year, quarter one, you will recoup that. The production is expected to go up. What are the steps that you are taking to boost that in Q1? That gives you confidence that the volume will go up for crude as well as for gas?
That production, which I have said that it will be coming up more in the first quarter of the next year, is more of a deferred production, so to say, because for KG 98/2, we would be having our living quarter setup being installed during December, January, and January, February, it would happen. Part of that production, which otherwise we were expecting in the last quarter, full part of the last quarter, will get deferred as such. Some we are expecting from TSP, as I have already mentioned, that from TSP from January, we are expecting green shoots. We are expecting that they should be more healthier production subsequently. That is how we are expecting that the production would be increasing from the first quarter of the next year.
Sir, Prakash sir mentioned about the estimated production for 2027. Does this include those increased after this increase particularly mandated by two?
No. What he had mentioned was when we had earlier planned this living quarters, etc., 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. That is getting a little delayed. It is coming in December, January, which moves everything partly into that monsoon period also, which then affects this thing. 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.
Okay. Thanks, sir. Thanks for answering all my questions. Thank you.
Thank you. Ladies and gentlemen, if you have any question, please press star and one on a telephone keypad. The next question comes from Ramesh S, an individual investor. Please go ahead.
Thank you and good evening. If you look at your new oil 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. 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? When did it start declining based on the investments you are making in the infill drilling and new wells?
See, I am Ajay Kumar 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. Whatever we are intervening in the well or when we are drilling the new wells, that comes under the new well gas. When I am managing.
That I understand. I'm just asking, for the new well gas production, for the investment you are making, is it possible to give us some kind of a production profile for the increase and then peak production? When that new well gas production itself will start declining?
See, for the next four to five 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.
Sorry, MMS.
5 MMSCMD of gas in this year. Next year, we are going to commission the DSF 2, which will be adding another 4 million. Both put together, 9 million is the addition. Currently, what we are producing is around 20. We will be producing near about 24. Considering the decline, 24-25 MMSCMD. That is the target. Another, if you add to next CBE 2027-2028, we will be producing in this range only. This is our plan projected. You can see that near about 30-35% of entire production will come from the new well gas.
Okay. So you are 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 five, ten years. That's what you're saying, right?
See, right now, I'm not talking about 5-10 years. We are talking about 3-4 years. This is short term. In long term, we have another plan which will be included in our underwater field also and in deep water, which may come. That right now, we are not able to tell you.
Okay. If you look at the segment numbers, the EBIT margin you are reporting in the onshore is lower than that of the offshore EBIT margin for the latest quarter. Is there any operating reason for that? What exactly? Because onshore cost should be lower. What is driving that difference in the higher EBIT margin for offshore compared to onshore?
Normally, offshore operations are more profitable as a thumb rule also. Onshore production, because it is lesser, there are a number of costs that are involved over there. Most of our onshore fields are mature fields. Some of them are older than 60 years old. 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. Once the BP consulting inputs are already showing the benefits, when do you start seeing the benefit of the higher oil and gas production? 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? What will be the ramp-up in that production volume, let's say, over the next two, three years?
As I've already mentioned earlier, under TSP, we are likely to see green shoots from 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 should happen from January onwards. 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%, 60% on a cumulative basis.
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 2028? Will it be by FY 2030? Any sense you can give on that?
As of now, no schedule has been given by them because the work is still under progress. By the end of the second year, which I said January 2027, they are likely to come up with a fully scheduled plan on this issue. However, what we are expecting is that in a normal case in such projects, you have peak production coming in after three to four years after the start of that project. I think we should start having it from 2028-2029, 2029-2030 onwards.
Okay. That's helpful. Thank you very much and wish you all the best.
Thank you.
A repeat question comes from Somaya V from Avendus Park. Please go ahead.
Yeah, thanks for the opportunity, sir. A couple of questions, sir. First is on the CapEx. In terms of OPaL, what would be the normal CapEx requirement and any further equity infusion required? Also, if you could just help the net debt at OPaL level.
For OPaL, we do not expect any additional CapEx to be or equity infusion required as of now. Whatever we have infused, that should suffice for OPaL as such. As far as net debt is concerned, debt currently at OPaL is about INR 25,000 crore, INR 25,188 crore as of end of September. We expect that this should move down to a lower interest debt also. The interest cost should go down. We already started taking action on those lines.
Sir, I mean, in terms of would you be able to quantify that extra of interest cost that could decline?
Currently, we have the interest, sorry, the interest rate on these debt is around 8.5% broadly, which we are expecting that we should be able to bring it down more than a percentage point.
Got it, sir. Also, what would be the normal maintenance CapEx in this case?
For OPaL?
Oh, yes, sir.
No CapEx.
No CapEx.
No CapEx. No CapEx. Because most of it would be OpEx for them.
Okay. Sir, also on the Mozambique equity contribution, if you could just help us with, I mean, anything that we need to spend in the next couple of years so far what we have spent. Also whether they're included in the INR 30,000-35,000 crore that we are planning for the year.
While they look up the figures exactly what you want, I would just broadly say that once that force majeure gets lifted, which is in a couple of days, formally that gets lifted out, then all these companies, the contracting parties will have recourse to financing arrangements also. Therefore, they would not be required to infuse any further equity as such in this project. You wanted some what is the equity that has been put in that figure? Is that it?
Yeah, yeah. Total investment so far and what remains based on existing cost of the project?
Till now, the CapEx has till FY 2026 Q2, it's around $5.98 million from the ONGC BD side. Inclusive of all CapEx and OpEx, it is around $6.6 billion. $6.6 billion.
This includes acquisition cost also.
This includes acquisition cost of $4.1.
Anything further that you are likely to? I'm sorry, sir. I was not able to hear clearly.
Okay. What he has mentioned is that till now, they have spent about $6.6 billion, including the acquisition cost. This is OVL's spend as of now. You also want what is likely further spend on this thing?
Yeah, based on the existing cost of the project.
On the existing cost of project, now we have any project financing. So that was around $16 billion, $16 million project financing as JV level. And but if the project cost is raised up to around.
How much would it be?
It will be in the range of 16-17.
Additionally?
No, no, not additionally.
Total.
Cumulatively, it would be $16 billion-$17 billion at the existing costs that have been there, out of which $6.6 billion has already been incurred by OVL.
Okay. Sir, also on the.
Let us just.
Sorry, sorry. Let us just.
Sorry, sorry. Let us just.
Sorry, sorry.
Get it corrected.
Hold on. Hold on.
Just hold on. Okay. Somaya, just a correction. I said 6.6 is already included in 16.1. It is actually addition. So it is 6.6 is own equity and 16.1 would be additional financing. Project finance. By all the concessionaries. This is by all the 16.1 is by all the concessionaries, by the contractor party as such.
I mean, if I get it right, 16 + 6 or 22 is the total cost. That's what we are referring to.
No. 6.6 is OVL portion. That is one portion. That is period. 16.1 is project finance, which is there for all the contracting parties, out of which 16% would be for OVL. Around 2.6. 2.6 + 6.6. It will be around 8.8.
8.8.
Around 8.
Sixteen percent of 16.1 is share of OVL. Adding to that 6.6, which we have already mentioned, it would be around $8.8 billion as far as OVL is concerned. Okay. The other question on the renewables front. If you could just help us with, I mean, what are the CapEx that we plan to incur on this front over the next couple of years?
We have already invested for the acquisition of other assets worth INR 5,000 crore. We are in the process of awarding a job again for an amount of INR 5,000 crore for building our own asset. Beyond that, we are looking for both the organic also inorganic also. The plans will be known to you very soon. In a gist, what we are doing is we have planned for about 10 GW by 2030.
Sir, when we have our annual CapEx plan of INR 30,000 crore-INR 35,000 crore, this includes the renewables spend as well?
Come back a bit.
Sorry, come back.
Couldn't hear you.
Sir, in terms of CapEx, we plan to do INR 30,000 crore-INR 35,000 crore per year. So this includes that renewables also or?
No. This is standalone E&P CapEx.
Okay. So this INR 5,000 crore that we planned is over number this?
Would be additional to that.
Okay. Understood. Sir, also in terms of the production, just wanted a bit of clarification on KG basin. I think at the beginning, you mentioned oil is around 28 KGBD. It was at 30 KGBD, I think, a quarter back. When do we expect to reach the peak production of 45? That's one. Also, gas, I missed the number that you mentioned in terms of current KG basin gas. Also, the peak production of 10 SCMD, when is that expected to reach?
I've mentioned 3 SCM for gas currently. We had also been mentioning earlier on that this was constrained because we do not have that living quarter which has the compressor package, etc. That module is getting installed in December, January now currently. Once that is installed, we should be in a position to ramp up the gas production from KG basin as such. As far as this oil production is concerned, yes, it has gone down because that is how the well activities have happened. We need to take action as far as the wells are concerned. We are trying or we are doing already action on these wells. We are expecting that these should recover and production should increase. There is also that we would have to do certain additional works for this production to ramp up to 45 as such.
What we had earlier on start of initially in this project was around 35,000 barrels per day. With the current works that we are doing on these wells or actions that we are taking on the wells, we are expecting that it should improve. That production should improve.
Sir, would it be fair to say maybe mid of next calendar year, we'll be getting closer to the peak production, both oil and gas in KG?
By June, July, if you are asking, yes, we would start ramp up of the gas. We should be starting off for the gas up to 10 SCMD would be there in the next year. For the oil, we have to wait for the actions that we are taking, the results of the actions that we are taking. We would be in a position to sort of confirm on that. Although we are hopeful, as of now, it is still working progress.
Got it, sir. Sir, also when we are our guidance for FY 2027 in terms of both oil and gas. From gas standpoint, how much are we taking from Daman project of the 5 MMSCMD for FY 2027?
Near next year onwards, I think.
Yeah, 5.
Daman from 2026, 2027, it will be 5 MMSCMD.
Okay. Their 5 MMSCMD will come in 2026-2027.
Yeah. I hope you have been answered.
Yes, sir. Yes, sir. Aside from Daman project, NDID is expected to come in FY 2027. I just want to clarify on that. Got it.
Yes.
Sir, thank you, sir. Bye.
Thank you.
Thank you. The last question for the day comes from Vikash Jain from CLSA. Please go ahead.
Hi. Thanks for taking my question, sir. I have a few of them. Firstly, Forex loss, which is included in OpEx for this particular quarter. Can you please give me the number?
It's INR 1,045 crore.
Okay. The other question that I had was, we expect that sometime middle of next calendar, that is June of 2026 or so, we should go from 3 to 10 SCMD in KG. All of Daman's peak production of 5 should come by then. There is an extra of 12 SCMD that we believe should happen from now in the next six months or so. Is that what we are expecting for gas?
It will start off from June onwards. Daman, we start off from the last quarter of this year. Whether it will hit 5 immediately on the first day, no, I can't say that. Yes, it will ramp up, certainly. June 26 onwards, we would be ramping up that offshore, eastern offshore project gas and then move up to 10.
Is this more likely to happen by September quarter or so?
Okay. I would not be able to put a figure on it, but yes, next year it will certainly happen.
Okay. The other question was on oil. Incremental upside on oil production. Where do we get confidence on that now that the KG part will have to wait for results of the interventions that you're doing? Where can we expect that to happen?
I think one very prospective area is or promising area is ESP from Mumbai High field. There, as I mentioned already, from January onwards, we should see some production which would actually make a difference to our profits and all that also.
January 27, right?
26.
Okay. As soon as coming months. Okay.
Yeah.
Yeah. Okay. The incremental bigger gains from anything that BP is doing is still maybe more like a 2027 kind of a thing.
Okay. That is how the things stand today. Maybe it could be better. Could be earlier. No, I would not like to stick my neck out today.
Okay. Just one final thing. Something was mentioned about new wells gas share going to about 30-35%, which is from about, you said, 14% right now, right? Going to 35%, say, by in four years' time. Is that what was mentioned?
Yeah. Yes, it will be between three to four years.
From FY 2026 to, say, FY 2030, from 14% will go to about 30-35% or so. One third of the gas will be new well gas.
Vikas Jain, one thing what he was saying, 14% is currently there. Then we do have got that 7.5% if we maintain at the current production level, that 7.5% adds it up. Okay. In addition to that, what he had said was 5 MMSCMD of gas we are expecting from Daman upside, which would totally qualify for this 20% premium gas. There are some other projects also. We do expect it to increase gradually. That 35%-40%, saying four years, I don't think so. It would come earlier to that.
Yeah. Correct. Correct. Understood. Okay. I think that's it. Thank you so much for taking my questions.
Thank you.
Thank you.
Thank you.
Thank you. Now I hand over the floor to Sri Vivek Tongaonkar for closing comments.
Yeah. Thank you very much. Thank you all for joining on this console. We hope that we would be in a position to have maybe a better meeting the next time around that we are there. Just to remind everybody that our console has increased. Although net profit on standalone basis were a bit subdued, we do believe that with the actions that we are taking, we should have or we are likely to give some good results as such. Thank you very much as of now and see you again.
Thank you, sir. Ladies and gentlemen, this concludes your conference for today. Thank you for your participation and for using DURSABA's conference call service. You may disconnect your lines now. Thank you and have a good day.
Thank you.