Good afternoon, ladies and gentlemen. I'm Thalassa, moderator for the conference call. Welcome to ONGC's Q1 FY25 earnings conference call. We have with us today Mr. Vivek Tongaonkar, Director of Finance, and team who will interact with investors and analysts to discuss Q1 earnings. As a reminder, all participants will be in the listen-only mode, and there will be an opportunity for you to ask questions after the presentation concludes. Should you need assistance during the conference call, please signal an operator by pressing star and then zero on your telephone keypad. Please note that this conference is recorded. I would now like to hand over the floor to Mr. Vivek Tongaonkar for his opening remarks. Thank you, and over to you, sir. Thank you, Thalassa. Good afternoon, ladies and gentlemen. I am Vivek Tongaonkar, Director of Finance, ONGC. I welcome you all in this ONGC earnings call for Q1 Financial Year 2025. Thank you all for joining us on the call. I am joined over here by my colleagues from ONGC, Mr. Ajay Kumar Singh, Chief Corporate Planning; Mr. Devendra Kumar, Chief Corporate Finance; Mr. Ashok Kumar from BDJV, he's Head Petrochemicals; Mr. Akhilesh Tiwari, Head Corporate Accounts; Mr. Prakash Joshi from investor relations. We also have Mr. Vinod Hallan, Head of Finance, and Mr. Mukul Bhatnagar, Head of Planning and Strategy from ONGC Videsh Limited. ONGC has compiled its financial results for the quarter ended 30th June 2024, which have been reviewed by the statutory auditors. The financial results have already been released on 5th August 2024 through a press note and sent to the stock exchanges. This has also been sent to the analysts who are on our mailing list. I present a brief synopsis of the results. The company has earned a net profit, that is, profit after tax, of INR 8,938 crores during the first quarter of Financial Year 2025, as against INR 10,527 crores during the first quarter of Financial Year 2024. This is a decrease of INR 1,589 crores, a 15.1% decrease. This decrease in net profit during Q1 Financial Year 2025 is on account of lower sales revenue, mainly due to lower natural gas realization and increase in exploration write-offs and increase in depletion. The sales revenue in Q1 Financial Year 2025 increased on account of increased sales revenue from crude oil by INR 1,864 crores, and the increased sales revenue from value-added products by INR 415 crore, as against the corresponding quarter of previous year. The billing net of VAT and CST for crude during the first quarter of the current fiscal was at $83.05 per barrel, as against $76.36 per barrel in the same period of the last year. That is an increase of 8.8%. The exchange rate of rupee versus dollar stood at INR 83.42 versus INR 82.21 in the first quarter of Financial Year 2024. Thus, realization for crude in rupee terms stood at INR 6,928 per barrel in Q1 Financial Year 2025, vis-à-vis INR 6,277 per barrel in Q1 Financial Year 2024. That is an increase of 10.4%. The expenditure on statutory levies, that is, royalty and excise duty, etc., have increased during Q1 Financial Year 2024 by INR 2,321 crore, 31%, in comparison with similar period of previous year. This increase in statutory levies is attributable mainly to increase in sale price of crude oil and levy of special additional excise duty by Government of India on production of petroleum crude at a rate revised every fortnight based on the international crude price. This SAED on crude has been levied with effect from 1st July 2023, which amounted to INR 2,835 crore in Q1 Financial Year 2025, against INR 713 crore during Q1 Financial Year 2024. That is an increase of INR 2,121 crores. The operating expenditure has increased by 111 crore, 1.9% only, from INR 5,968 crore in Q1 Financial Year 2024 to INR 6,079 crore in Q1 Financial Year 2025. There is an increase of INR 627 crore in exploration cost written off in Q1 Financial Year 2025 to INR 1,643 crore in Q1 Financial Year 2025 from INR 1,016 crore in Q1 Financial Year 2024. This increase is mainly due to increase in unsuccessful wells charged off mainly at Western Offshore and KG Basin. The increase in survey expenditure is due to increased survey activities in the JV Chennai HELP blocks and at Western Offshore. DD&A cost for Q1 Financial Year 2025 stood at INR 5,897 crore, as against INR 4,997 crore during the corresponding period of previous year. That is an increase of INR9 00 crore. This increase is due to increase in depletion expenditure of INR 748 crore, mainly at Western Offshore. The increase in depreciation by INR 250 crore is mainly at Western Offshore by INR 215 crore due to increase in RoU depreciation related to hiring of Rocover X offshore IMR vessels. The company at a consolidated level has earned a net profit, that is, profit after tax of INR 10,236 crore during the first quarter of Financial Year 2025, as against INR 17,893 crore during the first quarter of Financial Year 2024. That is a decrease of INR 7,657 crore, 42.79%. This decrease in profit can be mainly attributed to our subsidiaries, HPCL and MRPL. Lastly, before I finish, I would like to add that to counter the decline in production from some of the matured and marginal fields, ONGC is taking proactive steps by implementing well interventions and advancing new well drilling activities. The decline in production from matured fields will be compensated in upcoming quarters with commencement of additional production from upcoming projects, which are under various stages of development. Crude production has already commenced from KG 98/2. Hopefully, we would be better placed with oil in Q3 and gas in the quarters thereafter. Well, with this, I have finished my briefing of the first quarter results for Financial Year 2024-25. We will be very happy to take questions from you. We would request you to restrict your queries on financial results only. Thank you very much. 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. Ladies and gentlemen, if you have any questions, please press star and one on your telephone keypad. First question comes from Sabri Hazarika from Emkay Global. Please go ahead. Yeah, good afternoon, sir, and congratulations on a steady set of numbers. So I have two questions. First one pertains to KG 98/2 only. You have mentioned that from Q3, we will see some uptake, some sort of good position in terms of oil production. So can you quantify, as of now, what is the current oil output of KG 98 / 2 as well as gas output in Q1? And I think you've made one statement also that in Q2, one more well will come in August. So how do you see from a number point of view, oil production as well as gas production in KG 98 / 2? Yeah, good afternoon. For 98 / 2, currently we are producing oil at the rate of 12,000 barrels of oil per day, and gas is 1.5 SCMD. So from the next quarter, we expect to open one more well during this quarter, this Q2. And subsequently, from the third quarter, we expect to open further wells, which would add to our oil production as such. So from the third quarter, third and the fourth quarter, we expect to have a production rate of about 30,000 barrels per day plus as the wells open up. Right, sir. And the peak of 45,000 barrels per day will be like at what point of time we will hit that? In subsequent quarters, we should be achieving that 45,000 barrels per day of oil from KG-DWN-98/2. Yeah, so I mean, what is the well yield currently? I mean, per well, we are getting something like 5,000-7,000 barrels per day of oil. Is it the kind of run rate from per well we are getting right now in KG 98 / 2? Yeah, very good afternoon. I am Ajay Kumar Singh. I am Chief Corporate Planning. Currently, we are producing 12,000 barrels of oil from four number of wells. One more well we are opening in this month. We'll be operating with five wells with August 2024. Okay, sir. Thank you. Secondly, on the gas front, same kind of a trajectory. Can you please give us? Gas also from this month, right now we are producing 2.4 million SCMD gas from East Coast. Out of that, 0.4 million is from KG 98/2, and that will go to 1.4 million SCMD by August, by the end of this month. 1.4 is for this month you are talking about, not for the current rate. I mean, I think 1.5 MMSCMD was the number that you gave? Yeah, yeah. Yeah, Yeah, yeah. I gave that number. Sorry, my mistake on that point. Currently, we are at 0.4 MMSCMD, which is sorry, I mean 0.4, which will go to 1.4 MMSCMD this month. What is the trajectory? I mean, when will we hit 8-9 MMSCMD for gas? By end of March, we'll be reaching to 6 million. By March and 6 million SCMD. And how many wells will be there by that time? See, in 98 / 2, we have 26 wells. Out of that, 13 is oil producing, and seven is gas producing. So we'll be opening all 13 plus six by end of March, entire month. Okay, sir. Fair enough. That's all from my side. Thank you so much and all the best. Thank you. Next question comes from Kirtan Mehta from BOB Capital Markets. Please go ahead. Thank you, sir, for the opportunity. In the press release, we have mentioned about three discoveries that we have identified. One is a pool discovery, which is commercializing GS-6 and GS-8. Second one is a prospect discovery in the C-Series where the well flow rate was 0.21 million metric cubic meter per day. Would you talk us through the sort of potential that this is establishing, and what is the further plan to sort of assess and take these discoveries forward? See, these discoveries have happened recently. That development or that assessment of these discoveries, etc., will take some time. And it would be some time further on that we would be taking these on development plans and exploiting these discoveries as such. So that is the current state of it. Is 0.2 million metric day a large flow rate compared to what we normally see from the discoveries? Does it indicate sort of a larger potential of the reservoir? No, there is a potential for the reservoir. It is a decent flow rate that we have. These are encouraging testing results that we have established commercial hydrocarbon in that new formation for the first time. Further exploration, etc., would be further development also would have to be done in this particular formation for establishing the potential of this formation as well as the flow rate that could be obtained from this formation. Sure. In terms of the pool discovery online, when we mentioned that as a pool discovery, what's sort of the implication? We have also said we have established commercial oil and gas. What exactly are we sort of hinting at? Pool discovery means it is a new area that has been found over there within that field itself. Commercial means that we can extract oil from it or gas from it at a rate which is commercially possible for us to withdraw and sell it over there. There could be different sizes of these discoveries. If it is not good enough for us to develop it commercially or that we end up losing money on it, then we will not call it a commercial discovery. When we say it is a commercial discovery, it means I can extract oil or gas from that discovery, sell it, and recover all my costs and make money on that also. That is in sort of gist that we talk of when we say it's a commercial discovery. It will most likely be followed with a field development plan as well. We have reached a stage where we are able to say that it's commercial. Yes, we have reached that stage. And we would certainly be looking at developing such sort of pools and areas. Any indication in terms of the size of this pool? No. As of now, I would not be able to tell the size of the pool because this would entail additional work on that area, both through reinterpretation of the results that have been received from this well and also maybe drill more wells if the size is bigger or something like that. So it will take some time. It typically takes about 2-3 years for new areas or new fields to be sort of delineated and then finalized as to the size of the discovery in that to the full extent. One more question was on the field development plan that we have submitted for Hatta discovery with the small-scale LNG plant. Would you be able to share the details in terms of the size of the plant timelines as well as potential CapEx involved? I don't have that detail just now offhand. But the whole idea is that that FDP has been submitted to the DGH. It entails exploiting that field because it is a remote field. It is on land, but it is remote from any gas pipelines, etc. So to exploit that gas, what we are planning to do is we plan to tie up with IOCL and then transport that gas through LNG as LNG from that area. So this has already been submitted. This plan has been submitted to DGH. And once it is approved, we'll be able to move forward in the full-fledged way to develop this area as such. But commercially, we find it to be viable. In terms of the size of the reservoir, any indications on reserves or probable resources? I do not have those as of now. Let me come back. Let somebody will answer you on that. Sure. Thank you. But yes, it is commercially acceptable. Thank you, sir, for this clarification. So I'll get back in the queue. Sure. Thank you. Next question comes from Mayank Maheshwari from Morgan Stanley. Please go ahead. Sir, a couple of questions on the petrochemical side of the business and OVL. Can you just talk to us about what's the costs have come down quite a bit on the OVL front? Anything specific that you're seeing there in terms of operating costs? Good afternoon, Mike. I'll have Vinod Hallan from OVL is over here. He'll respond to your question. Actually, good afternoon. Mainly, the reason is because in Colombia, we have an operating block. And there, the royalty was paid earlier in cash. And now we have switched over to paying royalty in kind. So that has brought the royalty expense down. But it has also, at the same time, impacted our top line because it was coming in the revenue also. So the costs have come down mainly because of the lowering of the royalty expense there in Colombia. So is the production number now adjusted for the royalty impact? No, no, no, no. It remains the same. And would you roughly have an impact of how much is that in terms of royalty that you're paying in terms of in kind now as a percentage of production? If not, maybe. Thank you, we can come back to this question. If you provide me the number later, but the percent of the block is something around, we are 10 producers, oil producers in the block. We are the operators in that block. We have a 30% [share]. The third JV level production is around 37,000 barrels with our share at 27,000. Got it. Okay. I think the second question was more in terms of the petrochemical side. I think on the restructuring fund, are you guys completely done with it? Where is the progress on that? What can we expect now going forward on OPaL? So on OPaL, we are still awaiting certain government clearances. Once we get those, we should be able to announce it. We are very well, we have put our case forward to the government. We are hoping that we should get a positive response. But we have not got any communication from the government as yet. Okay. I think the last question I had was on the net realization on oil on the domestic side. I think it's been, I think, versus the discount versus Brent. Your net realization has been kind of sometimes the discount goes up quite a bit. Sometimes it comes down. So is there a specific reason of why the volatility is happening? Like this quarter, the discount on oil versus the benchmark kind of widened quite a bit. So the bottom line is that at the end of the day, the government ends up paying us around $75 per day per barrel, sorry, for crude oil. If the price moves up, crude oil price moves up, then the discount will be higher. If it is lower, it is lower. So they adjusted broadly what we have seen. I was looking at gross realization, not net realization. Sorry. I meant gross. Not the net realization. I completely agree with you. I think just the gross realizations have been because you have marketing freedom on oil now. So I was just thinking where you will be able to kind of get your gross realization up. For KG Basin, etc., yes, we have got better prices. It has been we have got a premium over Brent for this KG Basin crude oil. Crude typically prices are a combination of demand and supply as well as availability. All the Indian refineries are able to process various different types of crudes, most of it which they import also. Mumbai High crude as well as East Coast crude or for that matter, onshore crude is already tied up with these refineries. Yes, we do get a premium on our crude as such. The premium is over Dubai or Brent that you're looking at right now? It's over Brent. Over Brent. Okay. Got it. Okay. Thank you. I'll come back to interview. Yeah. Thank you. Next question comes from Nitin Tiwari from Phillip Capital India Limited. Please go ahead. Hi, sir. Thank you for the opportunity. Sir, my question is a clarificatory one. I didn't get the number for the production from KG 98/2 right. So I suppose you mentioned that the current rate of production is 0.4. Is that correct? 0.4 MMSCMD from 98/2? Yeah. Gas production is what you are saying is correct. Oil production is more than 12,000 barrels per day. So sir, has the production in 98/2 come down? Because I remember in the previous quarter when we had discussed the same number, it was mentioned that the production from East Coast is 2.4, of which 1.6 is 98/2 and 0.8 is S-1 Vashishta. So now, as you mentioned, that the number for 98/2 is 0.4. So what has changed? Production is 2.4, no? Yeah, current production is 2.4. Out of that, we have other fields also which are contributing. Nearby field is G-1 and Vashishta. Then all put together, we are producing as of date 2.4. And out of that, 0.4 is from 98/2 current. So if KG 98/2 is 0.4, then what are the other fields which are contributing to production? How much is coming from S-1 versus Vashishta and other fields? I mean, if you can give us a field-wise breakup. Yeah. You feel we are getting about 1.2 million, G1.5, and S-1 0.2. Sorry. Sorry. G1.5 and Vashishta you mentioned? 0.2. Okay. So that adds up to about 1.1. What about the remaining production field? Yeah. 1.2 from U Field. Sorry, which field? U, U. Umbrella. U Field. Okay. 1.2 from U. All right, sir. Actually, just Nitin, just hold on. Hold on. So Nitin, that clarification, I think earlier what has been mentioned or the current production from Eastern Offshore is 2.4 HCMD of which 1.2 is from the existing fields earlier and U field which was part of 98/2 considered earlier on. What we have opened up wells of oil over here in 98/2 field Cluster 2, that is 0.4 HCMD gas is coming along with it from the other fields which are there in the East Coast, which is S-1, G-1, [Vashishta, etc.], that is 0.8. So this all adds up to about 2.4. So sorry, sir, you said that the field you was part of 98/2 earlier. Is it something like that? No, no. U Field has been always part of KG 98/2 Cluster 2. Okay. All right. So this is KG 98/2 cluster 2, and the 0.4 is coming from the other cluster, is it? Yes, that's right. Okay. All right. But the entire production can be considered that the KG 98/2, I mean, if we have two clusters, so the combined production would be about 1.6. Is that the right way of looking at it? Exactly. Yes. All right. 0.8 is other fields in Eastern Offshore. So I mean, mostly that tallies with what you said in the previous quarter. 1.6 is coming from 98/2 from the two clusters that we have over there. Correct. All right. And secondly, sir, my second question is again related to 98/2. So what is the investment that we have incurred till date in development of 98/2, and what kind of return are we expecting from the production profile that we have envisioned for this field in the time to come? Currently, as of date, I think we have spent about $4 billion+. $4 billion +? $4 billion. All right. Around $4 billion, which is about INR 30,000 crore if you can say, INR 30,000 crore that we have in rupees. All right. Okay. What else you want? Sorry. So what is the kind of IRR we are looking at from this field? I mean. IRR as of now, we would be definitely. I'm sorry, sir, the audio quality is not good. I'm not sure it's only for me or for everybody, but your voice is breaking. One moment. Is it better now? Is it better now? Yeah, yeah. Better. Okay. So the IRR is better than the rate of return that we have been targeting. And we are fully on track to sort of get good returns on this field. You wouldn't want to specify a number, sir, for the field? I would, as of now, not like to quantify that number as of now because we are still in that phase when we are yet to complete that project. Understood, sir. And sir, secondly, just wanted to get the guidance of production for crude and natural gas for FY 26 and 27. If you can break it down sorry, FY 25 and 26, if you can also break it down between your production and JV production for the entire year. Okay. Just hold on. Yeah. And Nitin, once just hold on. Yes, sir. So, Nitin, just coming back onto that production front, for 2024, 2025, we are expecting for this is standalone. It will be about 20.5 MMT, 2.59 MMT. 20.5 MMT. Okay, sir. Yeah. And we expect it to, sorry. The JV product will be about 1.71 MMT. All right, sir. The total is 22.3. Okay. We expect an increase of about 12% over a period of two years. We are targeting around 21.87 for oil standalone, and 23.08 in totality for ONGC and JV as of now. In FY 26? Yes, sir. 26, 27. 2026, 2027 is 21.87 ONGC standalone. Yeah. And 23.08 totality ONGC plus JV. Understood, sir. The same numbers for gas, sir, that would be very helpful. Gas would be $20.95 for ONGC, $25 for JV, which is $21.60. All right, sir. The targeted increase of 27% up to 26-27. On a totality basis, it would be 25-26 BCM, which is contributing most of it at 25.5 BCM. 25-26 BCM would be the total production for you and JV in 2027? 25.91. Got it, sir. Okay. Thank you, sir. This is very helpful. I'll get back in a bit. Thank you. Next question comes from Varatharajan Sivasankaran from Antique Stock Broking Limited. Please go ahead. Thank you for the opportunity. Sir, on the KG Basin oil, are we now very clear about the applicability of the windfall tax? Sorry. Applicability of? Windfall tax on KG Basin? We don't anticipate any windfall tax as of now in the current scenario on this oil. I mean, you don't anticipate it, but is there been no feedback from the government to giving it a penalty? We have not paid it. Fair enough. Secondly, on the redevelopment efforts which Tongaonkar was highlighting, if you can give us some more details as to which all fields and what is the kind of CapEx being utilized there? On the fields CapEx? Yeah. On the redevelopment program, yeah, the CapEx which you have put in or field-wise if you have some numbers? Yeah, yeah. Just hold on. So the major fields that we are looking at currently is basically one is Daman Upside Development Project in Tapti. This is offshore. The second one is what is currently going on is the KG-DWN-98/2, which is currently under progress. We have Mumbai High North redevelopment phase four. Then we also have these are planned. This Mumbai High phase four has not started. Redevelopment of Santhal Field. Then redevelopment of Linch Field, which is on onshore. Redevelopment of Sobhasan Complex, which is again at onshore. Kalol redevelopment project, which is in onshore west. And we also have a commercial Polymer Flooding project in Becharaji Field, which is in Mehsana, onshore. Any completion schedule, if you can share with us? Yes. Daman Upside Development Project has been awarded in May 2024, and we expect it to complete by February 2026. KG Basin is already underway. We expect it to complete in this year. Mumbai High North development would take about three years to come up because we are at that FR and FDP area. Redevelopment of Linch, Sobhasan, Kalol, these would also be another two-year projects. Becharaji also would be another two-year project. Thank you, sir. Very good. We have some projects which are under tendering also. So those will also come up by September 26, which are some development of offshore areas, DSF contract here. Then some portion in EOA also, development of DS-17 field, which is also offshore. And Mumbai High redevelopment phase five, which will come beyond after phase four is completed. Great, sir. Thank you, sir. Thank you. Thank you. Next question comes from Gagan Dixit from Elara Capital. Please go ahead. Yeah. Yeah. Thanks for taking my question, sir. Sir, when I go with your presentation of this June presentation, it mentioned around 16 projects under conceptualization that you mentioned it has an 86 million ton potential. So as I assume, this is something exploration prospect that you were talking about? In the June presentation? Yes, sir. Last year. Okay, okay, okay. Okay. There is one project under conceptualization worth more than INR 15,000 crore with 86 million tonnes. Yeah, yeah, yeah. Yeah. Just give a second. So. Yeah. So what was informed in the June presentation were those projects which are under conceptualization. You're talking about MVP phase additional development of Mukta Field, those ones, right? Additional development North Tapti, additional development SBA-4. All these are currently we are working on them, but they are not as being crystallized. And therefore, I have as of now mentioned it to you. But yes, these are also under consideration and conceptualization. What I have informed just previously was those fields or those projects in which we have already started work and where we are already under tendering. Okay. So my next question is about this Mozambique project. So recently, this TotalEnergies that's the operator of the Mozambique, they have told that basically they have settled all the this everything has been settled with the contractor. That's what they told. But they mentioned that they are waiting for the Mozambique election to conclude. So it's something like I'm following them. So last year, they were telling that works should start somewhere in the early 2024. But now, I think they are also waiting. So can I assume it's a one-year delay almost in the Mozambique project? So how long would you? Correct, sir. There is a delay. It was earlier talked about for an election in January 2024, but that has gone far behind. And now, as you said, it's talking about elections, which are in October. And there is some linkage with the U.S. election as well. So we hope that October to January 2025 is the period where we can expect resumption of the work. Yes. My final question about this ONGC Green Limited, where I think you had some CapEx plan of INR 100,000 crore over the next 7-8 years. Can you elaborate, sir? What are the infrastructure or something that you want to target? I mean, how much is the green hydrogen or ammonia capacity up? I mean, renewable capacity that you are targeting over the next 6-7 years? Yeah. So our strategy has been that we plan to have about 10 gigawatts of green energy by 2030, which would comprise 60%-70% of solar, 30%-40% of onshore wind. Then we are also targeting green hydrogen, then CBG or biogas, offshore wind, some storage plants, CCUS. And the total investment that we are anticipating over here is about INR 100,000 crore, including reduction in flare reduction and increase in energy efficiency. So that is the target till 2030. Sir, how much is the green hydrogen or green ammonia that you are targeting to produce, I mean, by 2030? We plan to have 1 MMTPA of green ammonia, which is about 80 KT of green hydrogen. Okay. Okay. That's fine. Thank you. Thank you. I request the participants to restrict with two questions in the initial round and join back the queue for more questions. Next question comes from Probal Sen from ICICI Securities. Please go ahead. Thank you for the opportunity. Good afternoon, sir. Just a simple housekeeping question from my side. If you can have the CapEx guidance for FY 25 and 26 broken down into standalone, and if you can get a sense of what the consolidated CapEx would look like. Consolidated, are you looking at also HPCL, MRPL, waghera? Sir, if you can give any guidance, that's fine. Otherwise, if you stand alone, I would appreciate it. Hello. Hello. For this current year, we are planning around $4 billion odd to be spent on CapEx over here at ONGC only. Okay. It would be around INR 32,000 crore-INR 33,000 crore. We would expect similar amounts to be spent as of now on ONGC standalone for the future year, next year also. I'm not counting green and all those in this one as of now. Okay. Any sense you can give on OVL, sir? What kind of CapEx is from there, at least? Yeah. The OVL CapEx in this budget estimates 2024, 2025, INR 5,600 crore. And once we have Mozambique back on the wheels, this CapEx number is up to INR 600 crore and INR 8,500 crore will end up. Sir, I cannot hear you. Sorry. INR 8,500 to INR 9,000 when Mozambique comes, if Mozambique comes. No worries. INR 5,600 crore. Budget estimates. Okay. So INR 5,000-INR 6,000 crore except Mozambique. Once Mozambique comes, an additional INR 2,500-INR 3,000 crore will get added. Correct? Yes. Correct. The second question I had, sir, if you can get a sense of what the subsidies, OPAL and OMPL have done in Q1? OMPL is no longer a separate company. It is already merged. It is part of MRPL. It is MRPL only now. Right. And what about OPaL, sir? Yeah. OPaL is still a separate company. One moment. They had a bit of positive for the Q1, but on the PAT basis, they were negative. Just let me get the figures. Okay. Figures for OPaL were the PAT for this Q1 was negative minus INR 983 crore. For the financial year 2024, it was minus INR 3,456 crores. Okay. And what was the EBITDA, sir? Is it EBITDA positive this quarter? For EBITDA for this year, Q1 was INR 29 crores positive. For the financial year 2024, it was a loss of INR 479 crores. INR 479 crore loss? Last year. Right. Sir, if you can get some operational data in terms of volumes per now utilization right now? Utilization last year was 92%, and for this first quarter was 89%. Okay. All right, sir. I'll come back if I have more questions. Thank you so much for your time. Thank you. Thank you. Ladies and gentlemen, if you have any questions, please press star and one on your telephone keypad. Next question comes from Puneet Gulati from HSBC. Please go ahead. I repeat, question comes from Puneet Gulati from HSBC. Please go ahead. Yeah. Thank you so much. Can you talk about when do you see higher gas supply utilization from your nomination blocks given that you are drilling new wells? Sorry? Come back. Higher gas realization from? Yeah. So from the nomination blocks, there was this proposal where the new fields will attract higher pricing. Are you getting any benefit of that? So this is currently we have already submitted those details to the government, and the government is to come back to us on that issue. So we do expect that we should be able to get this additional markup on that nominated field gas shortly. And. Sorry. There's some more addition. Just hold on. Devendra, you can add on to it, please. Good afternoon. I'm Devendra Kumar from Commercial. This additional price, 20% additional price from additional wells and well intervention, that is already notified. Only the mechanism to measure that is not in place. DGH has been authorized to look into it. So they are working on the modalities how to measure that. So once that is put into the picture of measurement, that what exactly constitutes a well intervention, there are various technical aspects to it. So they need to differentiate on that. So we expect some movement on this front by end of this year. It will take some time. Will it be prospective or retrospective? See, notification is already there. Ha. So we would like it to be from the date of that notification, but we are not sure as of now. Okay. Understood. That's it. Secondly, if you can talk a bit about what's driving this bit of a little slower ramp-up in production from the KG Basin field, and what has it done to your cost estimates versus a year back, both OpEx and CapEx? So that slower implementation is partly due to weather. Weather has been quite rough during this year as such, and that is what has the delay. But we are hoping that we should be able to make up for all these delays and start our productions, as I mentioned earlier on, in this quarter from one more well and also from oil wells, which we plan to do, which are already completed, but we will have to sort of start producing from them and from the third quarter this year. In terms of equipment and platforms, all those are now tied up. There is no performance on that. Most of the whatever is required for operations has already been sort of put in place, and we should be able to start operations. That's why we are saying that this oil production and gas production will start from this quarter as well as from the third quarter, what I mentioned earlier. Understood. Lastly, if you can add a bit on the crude oil production, do you envisage a scenario where for gross ONGC except OVL basis, you will see an increase in production, or do you think one should pencil in a regular decline on the production side? The net production is some total of that regular decline as well as the additions that we do. We are looking forward for additional additions in this year. As I said, we are expecting production of 30,000+ from this new field, new wells that we are planning to put on stream in Q3 as such from KG Basin. We are anticipating that we should be having better production in this year over the previous year. Understood. That's very helpful. Thank you so much and all the best. Yeah. Thank you. Thank you. Next question comes from Vishnu Kumar from Avendus Spark. Please go ahead. Thanks for the time, sir. Actually, my question is similar to the previous caller's question. Thanks. Hello. Am I audible? Yeah. Yeah. You are audible. Yeah. So even in Q1, if we look at the past couple of quarters also, despite we have some element of ramp-up in KG 98/2 with an oil and gas, we still have our production continuing to decline as we speak. At least calculated number tells me that 3%-4% base decline growth is there. So even if, let's say, this growth kind of this kind of decline continues, even if we hit 30,000 on oil, we may end up being at this flat or negative. So just trying to get a sense that what efforts are being done or how confident are we of reaching a positive growth target, at least on oil from this side. Yeah. So just to mention to you that the first quarter of every year is usually marked with slightly lesser production because the Western Offshore gets affected due to monsoons. So wherever you have got well closures or some problem with the well, you are not able to go over there and do that well intervention or open up those wells, etc., or attend to that eventuality because of the rough seas as well as the rain and rain over there at offshore. So that contributes for lesser production every quarter, every year's quarter, first quarter as such, typically. So that we are sure that these sort of shutdowns or closures of individual wells that happen on different platforms would get addressed immediately whenever the weather clears, as well as whenever monsoon gets over, that is typically from 15th September onwards. So that production comes back on stream. East Coast also, as I've mentioned, that we are anticipating new wells coming up over here, and therefore those production would increase. As I have mentioned, the production pre-production is likely to go up to 45,000 barrels per day, which is a very substantial increase even if you consider ONGC as a whole. So that is why we are pretty confident that at the end of the year, we should be marking up better production over this previous year. Got it, sir. Secondly, on the production to sales ratio, obviously, we have some hello. Yes, yes. Please go on. Yeah. So the amount of volume produced to the volume sold, for the new incremental volumes, will the number directly flow down to the same number? Because from a modeling perspective, typically, we have a ratio. That's what we look at. So. Sorry. For East Coast, we have the production going to an FPSO, and from there, it would be sort of going on to different evacuated through other tankers to the refineries. So typically, I suppose our production quantums and the field quantums would be very pretty close to each other as far as oil is concerned. For gas, sir? Gas also, I don't anticipate any very major differential to happen between the production and sales until unless there is some flaring or technical flaring that takes place. Understood, sir. Thank you. Thank you. Thank you. Next question comes from S. Ramesh from Nirmal Bang Equities. Please go ahead. Good evening and thank you very much. So when you gave the production target between FY 25 and 27, is it possible to indicate what will be the oil production in FY 26 and same way for gas? So just to understand how it will go from the 22.3 to 23.08 between 25 and 27, what will be the number for 26, similarly for gas? Okay. Broadly, as I said, 12%. So I'm just mentioning that it would be 22, 23. Sorry. It would be in the same range for 25, 26, also somewhere in between. And for gas also, between 21.6 and 25.9, it would be around 23, 24 BCM as such. Okay. So when you look at the KG gas volume of 6 million by end of FY 2024, is that the exit rate, or will you achieve that on average for the fourth quarter? Come back. Sorry. I didn't get your call. So you mentioned that you will achieve 6 million cubic meters a day of gas production in 98/2 by end of FY 2025, right? So is that going to be the exit rate, or will you be able to achieve that average run rate of 6 million cubic meters a day for the fourth quarter of FY 2025? As gas production of 6 million from 19-22, production will be achieved in the last fortnight of March 2025. So it is not averaged out? It is not averaged. That answers your question. Okay. So from 6 million, what can we expect, say, over FY 2026 and 2027? Yeah. We can expect the entire. That is what he wants to clarify. So you mean to say when we would be picking 98/2, right? Yeah. It would be towards the end of this year and then continuing from that onwards. Yes. That's what. So the question is, from 6 million cubic meters a day, we have seen numbers of 12-15 MMCMD. So what is the actual number you can achieve, say, by 2026, 2027, and what is the kind of peak volume we're expecting based on the current plan? For these details, we'll come back to you separately. Is that okay? Okay. Yeah. That's fine. So before I move to the next question on KG, now, is it still work in progress, or have you capitalized and booked some revenue and income from the KG Basin? When do you expect the commercial impact to be shown in your P&L? When do we expect, sorry? See, in terms of the 98/2 production of oil and gas, when do we see those numbers being commercialized and booked in your P&L? We are already selling crude oil from there, 12,000 barrels per day. So it is already coming in our revenue. So is there any profit you are making there as of date? And will we be able to end the year with a? No. I would not be able to tell you any profit, so to say, for that field if you are asking that. We would not be able to do that. We do it only on an ONGC basis only. Yeah. But But just to understand, at what level of production you will break even at EBITDA or PBT level? No. I wouldn't be able to give that figure just now. Okay. Fine. One thing we could highlight is the majority of the cost is being booked. That is already there. Okay. In OVL, what can we expect in terms of growth and in terms of incremental contribution to your cash flows, or will you continue to require backstopping from ONGC in terms of additional equity and debt, especially given that Mozambique is now just going to get ramped up? Do you see any reduction in EBITDA during the CapEx phase in Mozambique, or will the current commercial fields still be generating cash flows from OVL? OVL is generating sufficient cash flows to manage its operations, and last. Hello. I can't hear you. Okay. Sorry to interrupt you, sir. So your voice is not audible, sir. One moment. Some interference also in that line, I think. OVL generates sufficient revenues to manage its operations. Last year, 2023-24, our oil and gas production was 10.518 MMT, let alone from the 2020-23 number of 10.17. This year, 2024-25, our target is 11. The Q1 production is almost we are sailing to the target. It is 2.252. So as regards to Mozambique, as you said, we don't see any reduction in that. Rather, there will be some improvement as the force majeure costs, which are hitting the P&L, will not be hitting when the Mozambique force majeure is lifted. And there is an upside in the production also expected as we continue good progress in the CPO -5. We are also doing good in the two blocks in South Sudan, with both GPOC and SPOC showing good results. SPOC, in fact, has clocked 13,000 barrels this year from the average of 6,000 barrels in 2023, 2024. Okay. Thank you very much, and wish you all the best. Thank you. Thank you. The last question for the day comes from Vipulk umar Shah from Sumangal Investments. Please go ahead. Hi. Thanks for the opportunity. Hello. Hello. Yes, yes. Thank you. Yeah. So line was back, so I could not note down the figures given by you. So what should be our standalone and plus OVL oil and gas production target for FY 2025 and FY 2026? Would you repeat it, please? So for 2025, 2026, if you are saying it is INR 20.72, INR 1.45, which is around 22 + 23, around 22, 20+ figure for oil. Gas is INR 23.83 and INR 0.53, which is INR 24.35. That is for 25, right? 25, 26. Okay. For 2026, 2027? That was INR 21.87 and INR 1.21, which is INR 23.08. Gas is INR 25.49 and INR 0.42, which is INR 25.91. Okay, sir. Thank you very much, and all the best. Thank you. Thank you. Now, I hand over the floor to Vivek Tongaonkar for closing comments. Please go ahead. Yeah. Thank you very much. And thank you all for the interest that you have with ONGC. We are looking at newer horizons. We are also looking at better production numbers from our new project, the currently undergoing project, which 98/2. We are very confident that, yes, we will be able to ramp up the production that we have and achieve what we have mentioned during this year also. So that would add substantially to our production figures. We are also looking very. We are very focused on our green projects also. We have put up ONGC Green as such, and we hope that we would be in a position to look at projects which would generate returns also and give us the green tag. So we are already working towards those goals as such. And we thank all the analysts who track our company. Also, we wish all our stakeholders a very bright future as such. Thank you very much. Thank you, sir. Ladies and gentlemen, this concludes your conference for today. Thank you for your participation and for using Chorus Call's conference call service. You may disconnect your lines now. Thank you, and have a pleasant day.