Good afternoon, ladies and gentlemen. I'm Valshera, moderator for the conference call. Welcome to ONGC's Q2 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 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 and then zero on your touch-tone telephone. 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. Yeah, thank you very much. Good afternoon, ladies and gentlemen. To introduce, I'm Vivek Tongaonkar, Director of Finance at ONGC. I welcome you all in this ONGC earnings call for Q2 and H1 ended financial year 25. Thank you all for joining us on this call. I'm joined over here by my colleagues from ONGC, Mr. Ajay Kumar Singh, who is our Chief Corporate Planning; Mr. Satish Kumar Dwivedi, our Chief JV and BD; Mr. Devendra Kumar, Chief Corporate Finance; Mr. Akhilesh Tiwari, Head of Corporate Accounts; Mr. Prakash Joshi from Investor Relations; Mr. Lakshman Gora from OVL. We have Mr. Vinod Hallan and Mr. Raj Kumar. ONGC has compiled its financial results for the quarter and six months ended 30th September 2024, which have been reviewed by the statutory auditors. The financial results have already been released on 11th November 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'll present a brief synopsis of the results. The company has earned a net profit, that is, profit after tax, of INR 11,984 crore during the second quarter of financial year 25, as against INR 10,238 crore during the second quarter of financial year 24, which is an increase of INR 1,746 crore, that is, 17.1%. Correspondingly, for the H1 financial year 25, the profit after tax has increased by INR 157 crore, that is, 0.8%, from INR 20,765 crore in H1 financial year 24 to INR 20,922 crore in H1 financial year 25. The sales revenue for Q2 financial year 25 has decreased by INR 1,218 crore, 3.5%, as against the corresponding quarter of previous year due to lower crude prices. However, the same has increased by INR 276 crore, that is, 0.4%, for H1 FY25, as against the corresponding H1 of previous year, mainly on account of increased sale revenue from value-added product sales. The realization of crude in rupee terms stood at INR 6,561 per barrel in Q2 FY25, vis-à-vis INR 7,013 per barrel in Q2 FY24, that is, a decrease of INR 452 per barrel, 6.4% in INR terms. Similarly, realization for crude in rupee terms stood at INR 6,744 per barrel in H1 FY25, vis-à-vis INR 6,641 per barrel in H1 FY24, which amounted to an increase of INR 103 per barrel, 1.6% in INR terms. The expenditure on statutory levies, royalty, and excise duty have decreased during Q2 FY25 by INR 2,960 crore, 27.4%, and in H1 FY25 by INR 642 crore, 3.5%, in comparison with similar periods for the previous years. This decrease in statutory levies is attributable mainly to a decrease in average sale price of crude oil, levy of special additional excise duty by the Government of India on the production of petroleum crude at a rate revised every fortnight based on international crude prices. This SAD on crude has been levied with effect from 1st July 2022, and it amounted to INR 3,352 crore in Q2 FY24 and to INR 1,127 crore during Q2 FY25. SAD from the second fortnight of September 24 is nil. There is an increase of INR 4 crore in exploration costs written off in Q2 FY25 and INR 631 crore in H1 FY25, vis-à-vis the corresponding periods for the quarter and half year of the previous year. The increase is mainly on account of an increase in 3D data acquisition and to charging off of dry wells at Western Offshore Basin, Assam and Arakan Basin, and Vindhya Basin. The operating expenditure has increased by INR 277 crore, 4.5%, from INR 6,112 crore in Q2 FY24 to INR 6,389 crore in Q2 FY25. Similarly, the operating expenditure in H1 FY25 has also increased by INR 390 crore, that is, 3.2%, from INR 12,080 crore in H1 FY24 to INR 12,470 crore in H1 FY25. This increase is mainly on account of an increase in activities at KG-DWN-98/2 and an increase in repair and maintenance at Mumbai Offshore and other production expenditures. DD&A costs for Q2 FY25 and H1 FY25 stood at INR 5,598 crore and INR 11,495 crore, respectively, as against INR 4,721 crore and INR 9,718 crore during the corresponding period of previous years. This increase is due to an increase in ONGC assets, increase in depletion rate, and an increased number of work orders and major capitalizations of INR 166 crore at Western Offshore. At the consolidated level, the company has earned a net profit, that is, profit after tax, of ₹9,878 crore during the second quarter of FY25, as against ₹16,171 crore during the second quarter of FY24. This is a decrease of ₹6,293 crore, that is, 38.92%. At the consolidated level, the company has earned a net profit after tax of ₹19,689 crore during H1 FY25, as against ₹33,666 crore during H1 FY24. That is a decrease of ₹13,944 crore, which is a 41.52% decrease. This decrease is mainly due to a decline in profits from subsidiaries, HPCL and MRPL. After these profits, the board has approved an interim dividend of 120%, that is, ₹6 per share of ₹5 each. The total payout on this account will be ₹7,548 crore. In the previous year, the company had declared an interim dividend of ₹5.75 on each equity share of ₹5. The government has approved additional investment in OPaL by ONGC, and it has also allocated new well gas up to 3.2 MMSCMD. This gives assured feedstock supply and paves the way for the sustainability of OPaL. Investment totaling INR 18,365 crore by ONGC in OPaL will result in an increase in ONGC's stake from 49.36% to 95.69%. ONGC has already infused INR 13,200 crore in OPaL, which has been used to retire high-interest debts of OPaL. OPaL is now the seventh subsidiary of ONGC. Lastly, before I finish, I would like to add that with a focused approach and continuous thrust on increasing domestic production, ONGC has been able to reverse the declining trend in its crude oil production. The standalone crude oil production, excluding condensate during Q2 FY25, was 4.576 million metric tons, registering a growth of 0.7% over the corresponding quarter of financial year 2024. Similarly, the standalone crude oil production during H1 FY25 was 9.204 million metric tons, with an increase of 0.8% over H1 FY24. We are happy to mention that three oil wells of a field of deepwater block KG-DWN-98/2 have been opened on 30th October 2024, thereby enhancing the total oil production from the KG-DWN-98/2 field to 25,000 plus barrels of oil per day from eight flowing wells. We also plan to open the remaining five oil wells shortly. Similarly, on the gas production front also, ONGC has been able to arrest the degrowth. The decline, which was 3.6% in Q1 FY25 over Q1 FY24, has been brought down to 2.1% in Q2 FY25. Friends, with this, I finish my briefing of the second quarter results for financial year 2024-25 and H1 financial year 2025, and we will be happy to take questions from you. We would request you to restrict your queries on financial results only. Thank you very much, and the floor is open for questions, please. 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 Kirtan Mehta from BOB Capital Markets. Please go ahead. We have notified, mentioned about two contracts during this press release. One, we have awarded on the L&T, and second, we have awarded on the Mazagon Dock with the potential of 5 MMSCMD and 4 MMSCMD. Would you give us more color on the project timeline and the ramp-up that we can expect from these projects? Yeah. Both these projects have been awarded recently, and both these projects are likely to be completed by the end of 2025-26. Both would be producing gas majorly from Daman Upside project also, and as well as the DSF-2 project. So both these projects would be gas projects as such. These projects are primarily for the wellhead platforms. So are the drilling contracts also awarded? The drilling contracts, we charter hire rigs, or we have our own rigs which would be carrying out the drilling of the wells subsequently whenever these well platforms are ready. The amount of gas that we are looking at is 5 MMSCMD in case of Daman Upside and around 4 MMSCMD from DSF-2 project. So when we say about FY26, this is basically the completion of the wellhead platforms, and drilling contracts would be subsequently after that. So when do we start seeing the gas production? What would happen is, as the platforms get installed, we open them up for bringing our rigs over there and start the drilling of those wells from those particular platforms. So generally, what we will find is within about, say, six months latest from the completion date of all these platforms, we would have started with the production of crude oil or gas as such. Right. Understood. Second question was about the new well gas or well intervention gas. We understand that we have been allocated around 4 MMSCMD of gas as new well gas. How do we sort of is it basically that any decline over and above the 8% rate that we have been able to arrest that will get considered as the new well gas for us? And how do we expect this to ramp up over the next two, three years? The new well gas is the gas which is from any new wells that are drilled, or it is also from any interventions that happen in existing wells. That gas would be new gas qualified for new gas. Over a period of time, what we are seeing is that we expect a decline in our production to up to 6%-7%. With this new gas coming up, because we keep on drilling new wells as well as well interventions are carried out on a regular basis, we expect the quantum of new gas to increase. And what we are expecting is that over a period of, say, maybe seven to eight years, most of the gas which would be there from the existing field should qualify to be new gas as it replaces the existing gas coming out from the existing wells. Right. So as of now, there is no sort of the decline rate criteria that we have to meet also over and above this particular decline rate only this will be considered as the new wells. Is it any gas which comes out of the new wells or interventions will be treated as a new gas? Generally, the decline rate that is considered is 7.5%, what is specified by the government, and we would be making up any gas which comes above this decline rate would be the new gas as such. So in terms of the H1, we have just said that we have around 2.3% as sort of the gas decline. So roughly around 4.5%-5% would qualify as the new well gas as we end the FY25. Is that the way to think about this? No. See, whatever new gas we get from new wells that are drilled in existing fields, or if we do any well intervention on existing wells, all that gas would qualify for the new gas purposes. Fine. Sir, and the last question, if I may squeeze in one more. On the KG-DWN-98/2, would you sort of say the latest guidance on both oil as well as the natural gas ramp-up? We have already mentioned that we are producing 25,000-plus barrels of oil per day from KG 98/2, and we would be opening up new wells over there. Earlier on, we have given a guidance of 45,000 barrels of oil per day being the peak towards the end of this year, financial year 25. As of now, we believe we are on track for that guidance. As far as gas is concerned, we have from the East Coast about 2.5 MMSCMD being produced. We have mentioned that it would be around 10 MMSCMD towards the end of this financial year or just in the first in the new year, 26, 27 also. 25, 26. We expect. This will also be related to the five wells that we are planning to open up. So the same well will contribute to this new gas production growth? Yes, so these wells will contribute to the new production of oil and gas as such. Thank you, sir, for this clarification. There are three more wells that are being planned for this. Thank you. I request the participants to restrict with two questions in the initial round and join back to queue for more questions. Next question comes from Sabri Hazarika from Emkay Global. Please go ahead. Yeah. Congratulations on a good set of numbers. So I have a few questions. So first one is relating to this new well gas. So it has, I mean, this has been effective from 16 October. Is that right? I mean, in terms of accounting? Yeah. First week of 8th of August. 8th of August, it has been effective in your books, right? Exactly. Okay. Actually, if you see, this notification had come on 8th of August. Okay. And the billing has been started from September 2024. Yeah. Okay, so this quarter also some impact is there. I mean, some portion of the volumes is getting that $9-$10 price. Is that right? New gas is getting higher price. You see, from November 2024, previously it was 4 MMSCMD which was allocated. Currently, it is 4.68 MMSCMD. Out of that, C2, C3 plant is 2.76. Okay. So right now, if I have to do a modeling of this, then I have to basically take the total production minus this 4.68. This 4.68 will basically be $9-$10, and the remaining will be $6.5. Is that right? Yeah. Then you have to minus that HPHT and deep water also. Okay. So this includes HPHT and deepwater also, 4.68? No, no, no. No, no, no. What you said from the total, you are going to subtract it. It's not. That's right. I'm talking about, I mean, NELP, maybe like nominated from nominated block, this has to be deducted. Yes, yes, yes. Okay. And your KG 98/2, I think, I mean, that gas currently, what is the production of the? I mean, you mentioned 2.6. So this includes, I think, VA and S1 also, right? So pure 98/2 cluster 2 gas will be how much? That would be 1.85. That would be 1.85 MMSCMD, and that will go up to, say, 7-8 MMSCMD. Is that right? Yeah. Broadly, we are on track for that. There you are basically getting the sealing. You're getting the? Sorry? Selling price, right? Selling price. Yeah, yeah. Yes, yes. Okay. Is there anything specific formula? It's just the ceiling only which is being currently applicable? As of now, that is all. It's a formula based on Fuel Oil, LNG. It's got a basket. So it is based out of that. Right, sir. And this, I think this is also being sold as just one second, sir. So yeah, fair enough. And okay, fair enough. And second question is on your CapEx. I think from the government data, I think your CapEx for this year has, I mean, Q1 itself has been something like INR 24,000 crore. So any comments on that? I mean, given that full year number is generally INR 30-33 thousand crore for you? See, as you know, there you can see the amount which we have paid to OPaL. That is also part of it. So when you take INR 24,000 crore, out of that, roughly around INR 6,000 crore, if it is September, so the balance was for our CapEx. Okay, sir. So ideally, it should be INR 17-18 thousand crore only for each one. So INR 24,000 crore includes INR 6,000 crore of OPaL infusion as well. Okay. Yes. Okay, sir. Fair enough. Thank you so much. I'll come back in the queue. Yeah. Thank you. Thank you. Next question comes from Probal Sen from ICICI Securities. Please go ahead. Thank you for the opportunity. With respect to OPaL just following up on the briefing that was done. Hello? Yeah. Yes, yes. Any auditor check? Yes, yes. Yeah. So just wanted to understand if you can kindly, I did not get all the numbers in the, how much is the total done in OPaL till date by ONGC? Yeah. Just for what we have done now? Including what we have done now. So what is the total number? So currently, we have done 18,365. Total just now. Till date, we have done INR 10,655 crore. So out of 18,365, we have infused 13,200 just now for this year after getting. Till date. 14,200 has been infused and INR 18,350 added. 13,200. Got it. And the total investment end result is 18,350, which will happen over H2 as well, I think. 18,365. Now, if I can ask, after this investment is fully done, what will be the residual net debt in OPaL, if I can get a sense? Yeah, yeah. Just give it a moment. Sure, sir. Just a second. Oh, sorry. Yeah, sure, sir. I'm sorry. I thought I had gotten disconnected. My apologies. OPaL, after this infusion of 18,365, you would be left with around 14,000 odd crore as debt balance after we input 18,000 crores. Got it, sir. Got it. So almost 30,000, 32,000 plus of debt will get reduced to the extent of our infusion, right? Yeah. Just hold on for a second. Sure, sir. Yeah. Good. Good. Yes, sir. Yeah. Right. So, sir, in terms of just looking forward at what OPaL's performance would look like now that we are resolving two things, one is the debt burden as well as getting gas also at a slightly more competitive rate thanks to being allotted, what kind of profitability are we expecting from this business? Let's say over FY26, 27 versus where we are now. Yeah. 2024, 2025, we are still expecting that the figures may be a little bit subdued. But from next year onward, we are expecting that things should be a turnaround in OPaL, barring any unforeseen changes to product prices, etc., or feedstock prices. Any number in terms of EBITDA per ton, even in U.S. dollars, you can put on it, sir, as a range? I would not be able to give any distinct. No problem, sir. And secondly, with respect to the gas production, has there been any change in terms of the gas production ramp-up from previous guidance, or are we sort of this is what we have sort of been working with for the last six months? Currently, the ramp-up or whatever that we are expecting has already been mentioned that it will come from KG 98/2, which we have already given a guidance that it is likely to go up to from the East Coast up to 10 MMSCMD by the year end. So that is as of now, we are looking at those gas figures. Got it, sir. Thank you so much for the detailed answer. I'll come back to you. Thanks. Thanks. Thank you. Next question comes from Varatharajan Sivasankaran from Antique Stock Broking Limited. Please go ahead. Thank you for the opportunity, sir. So if you can revisit the overall production guidance. Overall production guidance. Okay. Yeah. Good afternoon, everybody. I'm Ajay Kumar Singh. I'm Chief Corporate Planning. The guidance for next two years, we are expected to produce and enhance from current year production to 22.8 million tons of oil and similarly 22.1 million tons of gas equivalent. So both put together is about 44.9 million tons of oil and oil equivalent in 2025, 2026. And next year, we are planning to have cumulative production of 46.2 million tons of oil and oil equivalent in 2026, 2027. This is the guidance. Any breakup between oil and gas, sir, for 2026, 2027? Yeah. This is 41.9 from the current year and 44.97 is the next year, 2025, 2026, the oil and gas equivalent, both put together. Okay. So if you can provide an update on our OVL assets, all of them, each of them, looking at fuel and oil equivalent status, which you can highlight. Yes. Mr. Hallan will provide that update on OVL assets. Yeah. OVL, we have currently 32 assets in 15 countries, and of those, there are three assets in Russia, one in Mozambique. Am I audible? Yes, sir. If you can be a little louder. Yeah. So we have 32 assets in 15 countries. And of these, we have 11 exploratory, 14 producing, four development, and three pipeline assets. And the country-wide distribution is three assets in Russia, one in Mozambique, two in Venezuela, two in Colombia, and six in Myanmar, and two in Vietnam. This is a broad distribution. And our production last year was 10.518 oil plus oil equivalent. And the guidance for this year is around the same number, 10.5. Of this, we have already H1 produced 5.039. And the Russian assets, three assets, because of the conflict, Russia, Ukraine, the production is slightly lower than as it used to be in the year 2023, 2024. The other assets are producing better than average, which has been targeted for the year 2024, 2025. The current year average production is something around 194,000 barrels per day against a yearly average of 201,000 barrels in 2023-24. Yeah. Okay, then, sir. Look, any update on Venezuela or and? Venezuela, Venezuela, we are still actually in Venezuela, the sanctions were lifted from October to April, 18th April 2024. During that period, negotiations were on, and Venezuela PDVSA had proposed for taking over the operatorship. But again, the sanctions have been imposed after April. We have sought this OPEC approval, and in case that is coming, we'll try to make further progress on that, whether we can actually operate those assets. And then because right now, the restrictions are in place for oil movement as well as the fund restrictions. Thank you. Again, just one more question, sir. Look, with regard to the recent offshore Mumbai High Technical Assistance tender you floated, is there anything which you can provide us an update? And also, when the technical assistance does come through, any kind of best case and worst case upside in terms of production we can actually look at? And just to get a quantum of improvement we can get. Okay. So that tender is still on. It has not yet been closed, but it should reach maturity in December. That is what we are expecting. And once that is done, we will be having some technical service provider to work with us. It would be a long-term process. As of now, we would not be able to quantify any gains, etc., that are likely because it would depend from TSP to TSP and what sort of work goes in after they have looked into all the data that is available for Mumbai High. Thank you, sir. Thanks a lot. Thank you. I request the participants to restrict to two questions in the initial round and join back the queue for more questions. Next question comes from Mayank Maheshwari from Morgan Stanley. Please go ahead. Thank you for the call, sir. My first question related to OVL. If you see this significant increase in depletion, and also highlight what is the net realization after taxes on. Mayank, there is an issue with your. We are not able to hear you properly. Hello? Can you hear us? Yeah. Now better. Yeah. I was just on OVL. I had a couple of questions. One was on the depletion side, increase in depletion against this quarter. I'm sorry to interrupt. Can you join back the queue, sir? Your voice is not clear. Depletion of OVL? Can you increase in depletion? Thank you. The next question comes from Gagan Dixit from Elara Capital. Please go ahead. Yeah. Thanks for taking my question, sir. Am I audible, sir? Yeah, Gagan, you are. Yeah, yeah. Sir, so you mentioned in the press release that you are getting the 12% of the price of the Indian crude basket that's from the new well gas. So is this new well gas is the new wells from the nominated blocks or this KG block or it's something other field? Nominated blocks. Okay, okay. What I know is that it's some 20% premium that was the idea that was the case is over the $6.5. So is there anything missing, something here, sir? Can you come back? What you mentioned in the last statement, 30% what? He said 20% change. No. What I know is that 20% premium over the $6.5 gas on the nominated blocks, that's the case. So it should be at $7.8. That should be the case. Gagan, the issue is it is 12% on the Indian basket, crude oil basket. So what the government has also said that gas price in India would be 10% of that Indian crude oil basket. Now, Indian crude oil but there was a ceiling of $6.5/MMBtu. If it is $70 crude oil basket, then उसके हिसाब से it should be $7 per MMBtu, but the government restricts it to $6.5 as of now. New Well Gas, it would be 20% above the price that is there for the APM gas. So if it is $70 per barrel is the Indian crude, then 12% of that because 10% plus 20% of that is 12%, 12% of barrel $8.4 per MMBtu would be the price, not 12% on $6.5. Okay, okay. It's not 20% over 6.5. It's okay. It's 12% of the current crude basket. Okay, okay. Of the Indian crude basket, and this is basically announced every month. Yes. Okay. And sir, my second question is you mentioned just that your natural decline rate is 7.5%. So is it safe to assume that this nominated block old gas, I mean $6.5 gas, that production will continue to decline at 7-8% rate YY from now on? And it will increase by the new well something. Yeah. That is what I mentioned earlier on that if you consider 7.5 as the decline on a normal basis, and then we are able to maintain the production at current levels, it effectively means we are replacing all the old gas with the new gas for nominated fields over a period of time. Okay. So how much is the percentage of your, I mean, in the, I mean, the $6.5 old gas, how much is the percentage of that at present? So as of now, the new gas would not be very substantial. But it will be continuously increasing on. Because we started off in September, we said as we said that we started billing in September only. So over a period of time, they should increase. From next year onward, I think we would see a marked difference in the revenue generated from this new gas. Okay, so older gas is somewhere around 1-2 MMBtu, something like every year it will decline. Okay. Broadly. Okay. Yeah. Okay. That's all my answer. Thank you. Yeah. Thank you. Next question comes from Vikash Jain from CLSA India. Please go ahead. Thanks for taking my questions. I have a couple of them and maybe one suggestion as well. If we look at your guidance for the KG field, can you just give a sense of the broad guidance at which you will reach 45,000 barrels? Can I take that as end of this fiscal, that is March 2025 roughly, or? And what is the guidance to broadly when you will reach 10 MMSCMD? When you said end of the year, does that mean end of 2025 or the gas guidance? When we are saying oil 45K is what we are targeting for this year-end, financial year-end broadly. We already have got 25,000 plus producing. That with the existing wells that are there and which we are going to open, we should be reaching our target at the peak production around that time. Coming to gas, new wells are being opened up, and these along with the oil and gas, along with the oil gas would also be produced. We are expecting that this gas production, what we have mentioned, would be around end of this year, financial year 25, and maybe it may spill over to the 25, 26. But it will be there towards the end of this financial year. So basically, I mean, let's keep it broadly. So somewhere around before the middle of calendar year 2025, somewhere around March, April, May, you are thinking you're targeting to get to 10 MMSCMD. Yes. We are estimating that as of now. Okay. And the second question that I have is just for this calculation of decline rate to get to the volume of gas which will get the higher 12% slope, is FY23 the right starting point of what your production was from nomination fields? And then if you are declining less than 7.5%, for example, to keep it simple, is FY23 nomination field is 100, and if in FY25, or is it FY24? What is the starting base that I should be looking at firstly? It's FY23. FY24. FY24, 2023, 2024, 2024. So FY24, so if it is 100, and in FY25, your average production stays at 100, then 7.5 units of gas will be getting a 12% slope starting FY26. Is that what it means? No. It would be from whenever that gas gets produced. Yes. No. So what I'm missing is that when do you the decline rate is to be 7.5% for the year. So it's average to average. So FY26 is when you start getting the higher volumes, or that is the bit that I'm not able to understand. So it could also happen that I have drilled new well in this year. That gives me gas. So that would also earn me that higher price. Okay. So any kind of new wells that you drill, even in your existing areas. Nomination fields. So, nomination fields. So that you can separate out and say that this is volumes coming from new fields, right? Yes. Yes. So it is not just a simple 7.5% formula, but even that interventions that you do, which will give that extra volumes, which will get that extra price, right? So finally, sir, just one suggestion. Since now we have three different prices operating and no real easy way for us to know for sure what is the volume that you're getting from intervention, of course, there could be a simpler formula, which is not the complete solution. Why don't we give a breakup of our gas volumes and the gas price for each of those three things? Maybe that will become more significant starting a couple of quarters from now as well. Because when KG field also comes in, then there is that significant proportion, which is the HPHT formula. Plus next year onwards, there'll be a big proportion, a reasonably large proportion, which will have the 12% slope, which will be almost as the almost similar price as HPHT effectively. So why can't we split those volumes out separately for ease of everybody to kind of be able to model and look at things differently? Okay. We'll have a look at it, and if possible, we'll certainly try and provide those figures if possible. But roughly, so from your understanding, what is the volume likely to be in FY26, which will get this 12% slope? Is it 5 MMSCMD, 7 MMSCMD, any rough numbers? As of now, it would be very difficult to say that because it depends upon the new wells that I drill, whether I get new gas out of it or the interventions that are done, and whether we get gas out of it, so as of now it would be maybe difficult for us to hazard a guess. Next year onwards, we may get a better sort of idea about this thing because we have just started from September onwards, rather August this got the notification came up. September we have started the billings, and because this also requires us to look into what are the new wells and what production is likely to come up. Sorry, currently what is the volume, roughly? 4.68 MMSCMD. 4.68. That is the number that you mentioned. Sorry. Thank you so much. Thanks a lot for taking the question. It will change every month, basically. Correct. But it is likely to go up, and the share of the 6.5 will keep coming down, right? Yes. Exactly. Thank you so much. Thank you. Next question comes from Nitin Tiwari from PhillipCapital (India) Private Limited. Please go ahead. Good evening, sir. Thank you for the opportunity. So just a few clarificatory questions. So staying on the topic of new well gas, just wanted to understand the mechanism. So how does the gas get certified as new well gas? Is there basically approval required from DGH? And then how does the mechanism with the customer work? I mean, when you're offering that gas, does this gas get offered under the usual APM mechanism, or is it free to market, and you're marketing it on IGX? And the reason I'm asking is that would the NWG gas be marketed by you, or would it be marketed by GAIL on your behalf? How would the marketing angle work? Broadly, if you say the new gas that is being produced would be marketed by DGH or would be nominated? Sorry, your voice is breaking, sir. I'm not able to hear you properly. Actually, there is a lot of background noise from your side, Nitin. Actually, Nitin, no. I'll mute my line, sir. I'll mute mine. Yeah. Nitin, there would be DGH would be looking into this new gas figures also. And then accordingly, it would be declared as new gas. There would also be the next question was whether we market it ourselves or we give it to GAIL. Whatever it is, we are selling it to GAIL. And if these new wells are connected to or sold to GAIL, then GAIL will market it at the higher price. They will buy it from us at a higher price. And if it is a direct customer, we would be selling it directly to the customer at this new price because this is what has been mandated by the government. Okay, sir. So there is no fixed sort of marketing mechanism which is mandatory for NWG gas. Great. And secondly, sir, on OPaL, I wanted to understand it's a dual feed cracker. Correct me if I'm wrong over there. So given that it can also process naphtha, so what was actually the need for allocation of domestic NWG gas for basically the cracker to be profitable? It can work on naphtha as well as gas then. What was earlier planned was that naphtha was from ONGC, Uran as well as Hazira. The LNG which was being imported from that C2, C3 was being extracted by our Dahej plant and then being supplied to this OPaL plant. However, once these LNG prices have gone up, now today LNG prices are $14 per MMBtu broadly. With this, instead of that, if you can get a new gas which is still at around $8.4 or maximum $9 as of now, it is much cheaper as far as OPaL is concerned. They save around $4-5, $4.5-$5 dollars in this process. It becomes that they have a short feed also as well as a cheaper rate. This allocation by the government makes OPaL plant more sustainable and viable. So why I'm asking that question is that I just wanted to understand that when you say dual feed cracker, so is it the same cracker which can I mean, you can take in both naphtha and natural gas, or you have to separate crackers when taking naphtha, when taking natural gas? And secondly, a corollary to that, did the company explore the option of importing ethane and then using that as a feed rather than banking upon NWG gas domestically? Just a second, Nitin. So it is a dual gas cracker, dual cracker, which can be used both naphtha as well as gas. Earlier, the gas portion was through C2, C3 portion was being imported through rich LNG, which was coming from Qatar, RasGas, and which was out of which part of this C2, C3 was being extracted by Dahej plant and provided to OPaL. And the balance used to be returned back to GAIL, who was the owner of that gas as such. And the differential between those two was being made up through ONGC gas, makeup gas. However, that allocation of gas was stopped earlier on by the government. And now this has been made good again. So it is at $9.8-$9. It is cheaper than importing LNG and providing it back to us. So if your question is why it cannot use ethane, bringing in ethane requires much more infrastructure, which would take some time to build up also. And as of now, we are not sure whether it will come out to be cheaper than this allocated gas. Understood. Lastly, on the Daman guidance that you provided, that 5 MMSCMD of gas from Daman and another 4 from another field, like, is mainly expected. If you can give some timeline regarding that production. I said completion of these projects is expected in 2026, FY 2026. The gas from those fields should start coming up in 2026, 2027 onwards. 27 onwards. Understood. Thank you. Thank you. Next question comes from Yogesh Patil from Dolat Capital. Please go ahead. Thanks for an opportunity. Sir, question related to survey cost. Survey cost decline? Any particular reason? And sir, your plans to drill number of wells in FY25? Just a moment. So, second quarter, you are talking, there's a decline in survey cost. That is the question? Yes, sir. Broadly, it is because of monsoon only. But sir, we have seen the decline on a YOY basis also. So last year also, we have seen the monsoon. Yeah. So the quantum, if it is lesser in this period, what has been planned, that would result in lesser quantum of expenditure on it. So sir, my second question is related to other income. So other income also gone up sharply. Can you share the dividend part of that other income which you have received during the quarter? Yes. Yes. Just one. So the quantum that we have received is from IOC 1404, from OVL 75, from HPCL 1285, MRPL 251, Petronet LNG 56, and this is totally 3071. Okay. Thanks. Sir, second question is related to, again, a 4.6 MMSCMD, which is notified by the government recently as NWG gas. So is this allotted to consumer for the next five years? I mean, as per my last reading, it will be allotted for the next five years. So just wanted to confirm the time frame. Is it a five-year allotment or lesser than that? So it is the allocation for five years is for OPaL only. That is one thing. For the rest of the cases, whatever would be the contract duration for that period, the price of that gas, if I am supplying partly from APM and partly from this new gas, accordingly, the price will change for that quantum that are being supplied to the customer, whether it's existing, and it would be for the term of the contract with that existing customer. Okay. And lastly, on the OPaL side, if you could share some numbers on the EBITDA levels, PAT levels for the first half of FY25, OPaL plant utilization levels? Yeah. You can do that. The utilization for Q2, as far as OPaL was concerned, was 94%. Revenue was INR 3,664 crore. EBITDA was INR 78.67 crore. And PAT was negative, but that was minus INR 637 crore. It was lesser than the previous quarter PAT, might have lost rather. Previous quarter in Q1, it was INR 983 crore loss, whereas in this, it has improved to INR 637 crore loss. Okay. And do we expect, based upon the new NWG gas allocation to the OPaL, we will come into the profitability in the second half of FY25? And based upon the current trend, you might guide us. Like I mentioned earlier on, we are not expecting any but we would not be able to comment upon that as of now, but we do expect that from next year onwards, we should be in a much better position. OPaL should be in a much better position because the interest cost also will go down substantially for OPaL. And with ONGC pumping in or being the main shareholder, we are looking at ensuring that there is sort of a turnaround or the performance goes up and the capacity utilization also goes up. Okay. Thanks a lot, sir. Thank you. Next question comes from Kishan Mundhra from DAM Capital. Please go ahead. Hi, sir. Sir, you were exploring setting up a new oil refinery at Prayagraj. So is there any update on that? Have you made any progress? So as far as Prayagraj is concerned, I don't think we have declared anywhere that we are doing any refinery as such. What we have already mentioned earlier on in the press is that we would be looking at petrochemical projects as such. On that also, we have not yet declared where it would be there. The studies are still going on. So I would not be able to comment about a refinery in Prayagraj. Okay. Understood. So second question is on OPaL. If you could give the bifurcation between how much naphtha did you use last year in FY24 and how much gas did you use? I think it is broadly 60, 40, 60 naphtha, 40 LNG, but for exact figures, I may have to check that out again. So this works. 60, 40 works. And lastly, sir, on CapEx guidance, if you could give the CapEx numbers for FY26 and 27. Yeah. Just hold on. 26, 27, it is INR 36,000-odd crores as of now. For both the years? No. Which one? 26, 27, I told you. Okay. 25, 26. 25, 26 and 26, 27 would be in the same range. More or less. From 34 to 36,000. Understood. Understood. Thank you. Thank you. The last question of the day comes from Hemang Khanna from Nomura. Please go ahead. Hi sir. Thank you for taking my question. So I just wanted a clarification on the new gas volume. So 4.68 MMSCMD new gas does not include 1.85 from KG, right? No, no, no. It does not include that 1.85 from KG. Yes, sir. Okay. So entire 4.68 is roughly at $9 per MMBtu of utilization. That is basically HPHT deepwater gas, what you are talking about, KG-DWN-98/2. Right, sir. This is from our nominated field, what we were talking about, the 20%. Correct. Correct. So the entire 4.68 is roughly at about, let's say, $9 odd. Exactly. Got it. Got it. Thank you so much. Very clear. Thanks. Thank you, sir. Now I hand over the floor to Mr. Vivek Tongaonkar for closing comments. Yeah. Thank you very much. And thank you all for those questions also and the interest that is being shown in our company. If you want any further clarifications or if the clarifications given here do not meet or you require further information also, please feel free to contact our IR cell and we would be happy to come back to you and provide you the necessary information. Thank you all and thank you from ONGC over here. Thank you, sir. Ladies and gentlemen, this concludes the conference for today. Thank you for your participation and for using uncertain conference call service. You may disconnect your lines now. Thank you and have a good day.