Good afternoon, ladies and gentlemen. I am Valsia, moderator for the conference call. Welcome to ONGC's Q3 FY 2024 earnings conference call. We have with us today Mr. Manish Patil, Director HR, holding additional charge of Director Finance, and his team, who will interact with investors and analysts to discuss Q3 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 touchtone telephone. Please note, this conference is recorded. I would now like to hand over the floor to Mr. Manish Patil. Thank you, and over to you, sir. Good afternoon, ladies and gentlemen. Just to introduce, I am Manish Patil, Director HR, holding additional charge of Director Finance, ONGC. I welcome you all in this ONGC earnings call for Q3 and 9 months, FY 2024. Thank you all for joining us on the call. I'm joined here by my colleagues from ONGC, Mr. K.C. Ramesh, Chief Corporate Finance and Accounts, who has been designated as CFO. Mr. Pavan Aggarwal, Chief Corporate Planning. Mr. S. K. Dwivedi, Chief BD and JV. Mr. Devendra Kumar, Chief Commercial. Mr. B. R. Subudhi, Head Corporate Accounts. And Mr. Prakash Joshi, Head Corporate Budget and Investor Relations. Mr. Vinod Hallan, Head Finance, and Mr. Mukul Bhatnagar, Head Planning and Strategy, have joined me from ONGC Videsh Limited. ONGC has compiled its financial results for the quarter and nine months ended 31 December 2023, which have been reviewed by the statutory auditors. The financial results have already been released on 10 February 2024, through a press note and sent to stock exchanges. This has also been sent to the analysts who are there on our mailing list. Here is a brief synopsis of the results. The company has earned a net profit, that is profit after tax, of INR 9,536 crore during the Q3 of FY 2024, as against INR 11,045 crore during the Q3 of FY 2023, a decrease of INR 1,509 crore, that is 13.7%. The profit after tax, for nine months, FY 2024, has decreased by INR 9,310 crore to 3.8%, that is from profit after tax of INR 39,077 crore in nine months, FY 2023, to INR 29,767 crore in nine months, FY 2024. The decrease in net profit during Q3 FY 2024 and nine months FY 2024, is on the account of lower sales revenue, mainly due to lower crude oil, natural gas, and VAP price realizations and provisions of GST on royalty. The sales revenue for Q3 FY 2024 and nine months FY 2024, has decreased by INR 3,721 crore, that is 9.7%, and by INR 15,408 crore, that is 13%, as against the corresponding quarter and nine months of previous year. The billing that is net of VAT, GST or CST, for the crude oil during the Q3 of the current fiscal was at $81.59 per barrel, as against $87.13 per barrel in the same period of last year. That is a decrease of $5.54 per barrel. The exchange rate of rupee versus dollar stood at INR 83.27, vis-à-vis INR 82.20. Thus, realization for crude in rupee terms stood at INR 6,794 per barrel in Q3 FY24, vis-à-vis INR 7,162 per barrel in Q3 FY23. That is a decrease of INR 368 per barrel, that is 5.1% in INR terms. Similarly, gross billings for crude during the first nine months of the current fiscal was at $80.92 per barrel, as against $96.99 per barrel in the same period of last year. That is a decrease of $16.07 per barrel. The exchange rate of rupee versus dollar stood at INR 82.71, vis-a-vis rupee INR 79.77. Thus, realization for crude in rupee terms stood at INR 6693 per barrel in nine months, FY 2024, vis-a-vis INR 7737 per barrel in nine months, FY 2023, which amounted to a decrease of INR 1044 per barrel, that is 13.5% in INR terms. The expenditure on statutory levies, that is royalty, cess, and excise duty, have decreased during Q3 FY 2024 by INR 1,625 crore, 14.6%, and in nine months, FY 2024, by INR 8,629 crore, that is 23.7%, in comparison with similar period of previous years. This decrease in statutory levy is attributable mainly to decrease in sale price of crude oil and levy of special additional excise duty, SAED, by Government of India on production of petroleum crude at a rate revised on every fortnight based on international crude price. This SAED on crude have been levied with effect from first of July 2023, which amounted to INR 9,435 crore in nine months, FY 2023, and INR 6,710 crore during nine months, FY 2024. There is an increase of INR 721 crore in the exploration cost written off in Q3 FY24, that is from INR 1,607 crore in Q3 FY23, to INR 2,328 crore in quarter three, FY24. This increase is mainly due to increase in unsuccessful wells, charged off mainly at Western Offshore and Mahanadi Basin. The operating expenditure has increased by INR 105 crore, that is 1.7%, from 6,075 crore in Q3 FY23 to INR 6,380 crore in Q3 FY24. Similarly, the operating expenditure in nine months FY 2024 has also increased by INR 1,524 crore, that is 9%, from INR 16,935 crore in nine months FY 2023, to INR 18,459 crore in nine months FY 2024. The increase is mainly on account of the increase in contractual payment by INR 101 crore, mainly on KG-DWN-98/2. Other expenses, INR 356 crore, transport expenses, INR 61 crore, power and fuel by INR 79 crore, mainly at Western Offshore assets, repairs and maintenance, INR 323 crore, and water injection by INR 227 crore, mainly at Western Offshore, due to increase in activities. DD&I cost for Q3 FY 2024 and nine months FY 2024 stood at INR 5,078 crore and INR 14,785 crore respectively, as against INR 4,855 crore and INR 11,959 crore respectively, during the corresponding period of previous year. The depreciation for nine months FY 2024 has increased, mainly in Eastern Offshore 98/2, by INR 966 crore due to depreciation on ROU asset of FPSO. Similarly, the impairment for nine months FY 2024 has increased due to reversal of impairment amounting to INR 2,129 crore last year on certain discovered small fields of the company, falling under 10 contract areas, which were awarded by DGH to the winning bidders. The company, at a consolidated level, has earned a net profit, that is, profit after tax of INR 10,748 crore during the Q3 of FY 2024, as against INR 11,665 crore during Q3 of FY 2023. That is a decrease of INR 917 crore, 7.9%. Similarly, the company has a consolidated level, the company at a consolidated level has earned a net profit, that is, profit after tax of INR 44,685 crore during nine months FY 2024, as against INR 27,076 crore during nine months FY 2023. That is an increase of INR 17,609 crore, 65%. This increase in profit can be mainly attributed to our subsidiary, HPCL, MRPL, and OVL. Board has approved second interim dividend of 80%, that is, INR 4 on each equity share of INR 5. The total payout on this account will be INR 5,032 crore. This is in addition to payout of INR 7,234 crore, first interim dividend of INR 5.75 per share, and then 15% declared earlier in November 2023. 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 oil production, as you are aware, has already commenced from KG-DWN- 98/2. Hopefully, we would be better placed with oil in the last quarter of this FY, and gas in the coming financial year of 2024-25. We also wish to inform that the price for the gas in the coming financial year would be better improved as compared to this year. Well, friends, with this, I finish my briefing of the Q3 results for the financial year 2023-24. We'll be very happy to take questions from you. We would like to 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. I repeat, ladies and gentlemen, if you have any question, please press star and one on your telephone keypad. First question comes from Varatharajan Sivasankaran from Antique Stock Broking Limited. Please go ahead. Thanks for the opportunity, sir. So you mentioned about the production issue. If you can elaborate a little more on that. So our understanding is that, like, you know, KG Basin obviously is contributing to the oil increase this time around and will contribute to the gas increase next year. But subsequently, effectively, like, you know, in terms of compensating for the decline in production in the other fields, what would be the situation in, say, FY 2026 or 2027, with regard to the developments in the existing, like, you know, new reserves which you have found over the last few years, as well as any higher year activity? So what is the kind of a, you know, indication we can get in terms of a sustainable production from both on oil and gas? Vartha, just one second. ... Okay, Namaskar. With respect to your question about the future growth projections, with the start of the first oil from the KG-DWN-98/2 project and the upcoming programs, we anticipate that we will be ending this year on similar numbers as we were having in the FY 2023 or slightly better than that. But however, moving forward, we hope to have an increase by around 15% in the next three years by 2026-2027. And we have got a number of projects which are lined up. There were something around 22 development/infrastructure projects with a CapEx outlay of around INR 60,000 crore. And those projects will also contribute to our growth trajectory. Secondly, as you know, that we have got the old mature field, where we have got around 6%-7% decline. So we are making the consistent efforts to maintain those productions and to reverse this declining trend. We have given a focus on few of the activities, on the water injection prioritization, on the equipment availability, on the operational efficiency improvement, on the resource augmentation with respect to the drilling rates, the vessels or the helicopters, and the induction of the state-of-the-art technology in the drilling rigs. So these are the few measures which we are taking up on an aggressive basis to arrest the decline from the old mature fields. Secondly, we have got a number of development projects which are lined up, which will be contributing towards our growth trajectory. Thank you, sir. And so my second question was on the 20% premium to the incremental gas production, which is up with us reports. I understand it is still not been cleared and notified, but as and when it comes, what is the proportion of our APM production which will be eligible for this kind of a premium pricing currently? And if it can give some visibility as to how it can potentially increase over the next two to three years on gas. Currently, as per the definitions of the gas premium pricing, any well in the, any well intervention or the new well, which is coming up in the existing nomination field, will be eligible for this 20% gas premium pricing. Currently, during this year, FY 2023-2024, it is contributing something around 3%-4% of our current gas production. And moving forward, in the next three years, we hope that it will, the contribution from this new for, the gas coming towards the premium pricing will be in the tune of around 20%. Thanks a lot. Thank you. Thank you. Next question comes from Amit Rustagi from UBS Securities. Please go ahead. Yeah, thank you. Sir, thanks for posting a great set of numbers. My question relates to KG Basin field, like, what is the CapEx we have incurred till date? What is our remaining CapEx in this field? And how are we going to see the cost of production, both for oil and gas? And will it increase our DD&I expense as well? So if you can help us understanding these aspects. Yeah. As you are aware, the total CapEx that we had planned for KG 98/2 was around $5 billion, and the substantial part of which we have already spent. So around $2.8 billion is the amount, the progress till date that we have incurred on that. There are some small cost escalations happening because of some change orders and things like that, but they are not very substantial. So in terms of cost, we are comfortably placed as far as the KG 98/2 is concerned. Coming to your second question was with respect to- The production cost. Cost of production and Cost of production, see, the cost of production, as you know, is basically, the offshore is generally the cost is more, but it is a function of the production quantity that we get. So the per unit cost is normally like, you know, depending totally on the quantum of production. So considering that the current production that we are expecting from there, it is expected that it will be on a slightly higher side than the Western Offshore, but it will be, the range which is expected for the offshore. Sir, can you give us a total cost, like what is the FPSO cost per day, and, so that we know, like what is the production, and we can calculate on our, ourselves? Yeah, FPSO, the day rate is currently, including GST, INR 718,000. That is the per day cost for FPSO. Apart from that, like as you know, we have the normal, other operating costs, like material consumption would be there, then there could be some work or operations. The normal, typical E&P industry cost, which we incur for producing. So those would be there. There could be some water injection cost as well....So the overall cost picture will be clear once we start producing fully. I mean, the gas production is now, you know, we are expecting, as earlier Mr. Pavan was saying, that, in the first half of next year, somewhere, maybe June, July. May, June. So, yeah. So, you know, based on that, the cost will crystallize. But yes, the substantial part of the cost there for oil is the FPSO. The other facilities are yet to be installed over there, so once it is installed, we'll have a clearer picture on that. So I think, The DNA, yeah. 25, 26, when we will be having the full scale production for the field. Hmm. 25-26 years? Yeah, how, like, how you're going to appropriate the $5 billion cost over how many years, basically? Yeah, normally, like, you know, the cost, the CapEx cost that we allocate is through by way of, you know, depletion, as well as the cost pertaining to FPSO is concerned, it's, like, you know, in days 116 on the basis of the lease. So we have already started booking the depreciation and depreciation part through the lease, the lease part. So which you might have seen that there is some substantial increase in the depreciation in the current quarter, as well, due to the lease booking, which you have already done for the FPSO. So some part of the hit we have already started taking on that. So that would be a regular expenditure by way of booking through lease. The facilities that we are going to install, that would be on the base of the reserve there and reserve to production ratio. Normally, on an average, around 10% is the reserve to production ratio, so 10% annual, the expenditure that we incur on the CapEx is by way of depletion. Okay, sir. Got it. And sir, I have a question relating to the offshore rigs. Basically, we have around 40 offshore rigs. And so could you give us... I think we were able to achieve a major cost saving program over 2021, when the rig rates were actually down. But now we have started to see rig rates moving up. So how much of it is already being renegotiated, and how much of it need to be re-renegotiated over the next 1 year? If you can give us some color on that. See, relatively, we have a longer, you know, contract periods, normally in the range of three years. So, the, the total rig that you're talking about, 40, is distributed over some of the, you know, cost which we had, the rates which we are currently having, they are continuing with the past contracts, and some of them are new. So it's a mix of new and old, as of now, the rates which are going on. So, as far as the, the rig cost is concerned, whatever cost that is incurring, is, is increasing on the base of the current contract rates, is compensated by the contracts which we had already entered in the previous year. We don't have any system of renegotiating the rates, rates as such. Normally, what we do is we enter into a new contract once the earlier contract expires. But yes, if there are opportunities where we can extend the current contract at a cheaper rate, that also we look into. But what I'm trying to ask is that, is there any increase in cost because of renegotiation in the last one year? Because when you entered into contracts in 2021, they were substantially at a lower rate, but now I think the markets have moved up quite a bit on the rig side. So what are the increase in rate we are experiencing right now in renegotiating the contracts? Yeah, no, we don't renegotiate, but if you are asking that with respect to the new current contract that we are entering, what is the rate, then that is in the range of around 10% high. 8-90. Just, just one sec. Yeah. Currently, the rate that we are getting on the new jackup rigs that we are hiring is around, you know, in the range of $70,000-$90,000 per day. That is the operating rate that we are getting. Yes, you know that during COVID period, it was around $45,000-$50,000, around that. So that is the increase that is coming currently in the market. But we are expecting that based on the projections, you know, the rates could cool down in future. Okay, great. Great, sir. Sir, thanks for answering my questions, and best of luck. Thank you, sir. Thank you. I request the participants to stick 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 very much for the opportunity, sir. Just I had one question with respect to the exploratory well, well write-offs. The directors have mentioned that this was due to higher unsuccessful well write-offs in Mahanadi and the Western Offshore. I just wanted to understand: does this change our assessment of reserves addition? Because I think Mahanadi Development and the Western Offshore are two of the major development projects that we have ongoing. So does, do these unsuccessful wells impact our, you know, assessment of reserve addition from these projects? Not exactly. Actually, unsuccessful wells are, basically, though we have discovered, in the Western Offshore, much in the past, we keep, you know, continuing to, go for further exploration there. So basically, as per the policy, like, you know, wells which we take up only for the purpose of investigation, like expendable wells that we charge off, irrespective of whether we have some find or not. You must have seen that recently we have had some finds in, Mahanadi. So, the- Mm-hmm. ... the development of the field further does not have any relation as well as the, the dry wells that we are, booking.... Dry well booking is basically based on the accounting policy that we have with respect to whether a particular well has been declared dry or whether, you know, that we are not going to use it any, anymore, like an expendable well. So that's, that's the basis on which we write off. It has nothing to do with the reserve that we, you know, accrete from the field. Reserves are totally based on the findings and further investigation by the exploration group. Our assessment of whatever growth we assume or we have built into our MOUs or projection, they remain unchanged as of now from these two projects, right? Yes, yes. Okay. Sir, the second question is with respect to, you know, the projections. You did mention that you are aiming still to end the year at roughly flat oil production and, you know, which would be somewhere around 16.9 million tons, if I'm not mistaken, and that was the run rate in FY 2026. I wanted to understand, so FY 2025, you know, what kind of exit rate should we actually be building in realistically? Assuming that oil production would be, you know, ramping up steadily from KG, and some element of around 6 months of gas production should also be there. So, you know, against the 16.9 million tons of oil and about, I think, 15.3 or BCM that we should do in gas this year, what is the exit rate we should build in for FY 2025? If you can give any sense on that. in the FY 2024 Mm-hmm. As you may be knowing that earlier years- Twenty-five. Oh, yeah, yeah, I'm confused. As you know that in the earlier years, we were facing a decline rate to the tune of around 4%-5%. Right. However, last year, we were able to manage it with around 0.5% decline. Mm-hmm. This year we'll be above that. We'll be maintaining the numbers of the last year or slightly above that. Right. Now moving forward with this 98 by 2, because the FY 2024-2025, we will be getting the partial production. So we'll be getting the peak production for the partial year. So in FY 2024-2025, we hope to increase our current production by around 5%-6%, and we will be getting the full plateau production from the 98 by 2 in FY 2026. The 15% improvement that we are talking about over the next three years essentially can be divided up into 5%-6% increase pretty much every year that we expect over the next three years, correct? That's right. In FY 2027, we are expecting a slightly higher increase, because by that time we will be getting another project of Daman Upside. From there also, we expect around 4 million cu m gas per day, equivalent to around 1.5 BCF. Mm-hmm. It will be 98/2 plus Daman Upside will be the two major projects which will be contributing towards around 14%-15% production increase by FY 2027. I apologize, sir, I did not get the name of the other asset other than KG 98/ 2. What was the other asset? There is a Daman Upside project. That's on the Western Offshore. Western offshore. Daman? Daman upside. Yeah, yeah. Yeah. Daman. Okay. Sir, last question, if I may squeeze in: What is the kind of plateau period once the asset hits peak production of 10 MMSCFD and, let's say, somewhere around 40,000 bbl of oil produced on KG? What is the kind of plateau period that we are expecting for this production to sustain? We anticipate a plateau of around two years. Plateau of two years, and then a steady decline thereafter, assuming no other well interventions happen. The other project, other infill wells will be coming up with the Cluster 1. Mm-hmm. -We’ll be adding up, in FY 2028. So that will make up for the- Mm-hmm. for the decline. Understood. Thank you very much, sir, for the detailed answer. I appreciate that. I'll come back if I have more questions. Thanks. Thank you. Next question comes from Mayank Maheshwari, from Morgan Stanley. Please go ahead. Thank you for the call, sir. Two questions from my end. First was more related to capital allocation. Can you just talk a bit about of how are you thinking on a net cash standalone balance sheet? And I suppose you are seeing some improvement in terms of receivables on OVL, as well as subsidiaries doing reasonably okay now. Anything on the dividend policy that you can talk about in terms of how you are thinking about DPS and growth in DPS with the volume growth that you are expecting? And if you can also talk on the same page on OVL and the collections on OVL, in terms of issues you had in the past, how are that kind of panning out in Russia, Venezuela, or Sudan? Thank you. So I think first, OVL would like to answer your question. After that, the first question will be answered. Yeah, regarding OVL, regarding OVL, you have asked actually the position regarding Russia and the Venezuela assets, what is the current situation? So on the Russia, we still have, due to the Singapore being an unfriendly jurisdiction, our dividends are still held up in Russia. However, we are at advanced stage of trying to pursue with the Rosneft to accept the abandonment obligation upon OVL for getting back our 20% shares, to be squared up in rubles. So our application with the Russian authorities is expected to be heard very soon, and we hope to clear the close this transaction of meeting the abandonment obligations. Regarding Venezuela, you are aware that the sanctions have been lifted, lifted, and they will remain open until the eighteenth of April 2024. We have received a kind of proposals from the PDVSA, which are under negotiations. We are also exploring the banking route and trying to open up the bank accounts for easing up the fund flow, remittance inward and outward remittance from the country. So, given that the situation continues to ease up, we hope that we will be able to secure our... We are seeking balance from Venezuela for the dividend, outstanding dividends, and we hope to actually secure those rights to receive balance. Regarding other projects also, we, the outlook is positive. Yeah, just one. So we are other projects also. The outlook is positive, and we hope to gain positive positions in those projects also. Mayank, now I think, first question will be answered by our CFO, sir. Yeah, your question was with respect to the dividend and the capital allocation. You know that we have been a consistent dividend paying company. You know, over the last few years, we have been paying around 40%. So currently, and also you might have seen that we have already paid INR 9.75, it is almost 41%, in this nine-month period. Maybe in the last couple of years, probably it was slightly lesser. But, yes, we have the plan to have that numbers continuing, and being a good dividend paying company. So that will continue. As well as the capital allocation is concerned, given the current price and, you know, that we have a comfortable price, even after considering SAD, and, as earlier we were saying that, you know, on the additional gas, we are going to get a substantial higher price of almost $9-$10 per MMBTU. So with this, we expect that, you know, we will have a good cash flow position going forward as well. So whatever that we have, the normal CapEx that we have is around INR 30,000 crore annually for the our normal E&P operation. So apart from that, the dividend that we are paying, so what, you know, over and above that, we have some surplus cash available, which we going forward plan to, you know, slowly, move out to, venture into other areas as well, apart from the conventional, E&P. So you might have already seen the announcement with respect to our, investment in OPaL, you know, green energy initiatives that we are taking. So with all those things, we would be, you know, slowly moving ahead, utilizing our, future cash flows in those areas as well for the CapEx. sir, can you just give us a guidance on the CapEx for the next couple of years, for fiscal 2025 and maybe beyond, of how much you are thinking about allocating each year apart? Is that the same INR 30,000 crore that we can assume now going forward? Mayank, what you can expect, it could rise in the current year, say, in the range of INR 33,000 crore, and next year it would be somewhere in the range of INR 33,000-INR 35,000 crore. This I'm talking of the standalone CapEx. Standalone. That's only for the- Yeah, standalone CapEx of ONGC. Other than the integration for the standalone CapEx. Okay. Sir, can you just give it a bit of a holistic picture across the ONGC group of what kind of CapEx and the shift in capital allocation between upstream, downstream, midstream, and renewables that you will have? Roughly a big, big picture sense. It would be difficult for us to, you know, talk about the CapEx plan for the subsidiaries currently at this juncture. But as we said, as far as ONGC is concerned, the conventional investment of around INR 30,000 crore, normally INR 30,000 crore, so INR 32,000 crore-INR 33,000 crore is the next two years, as Prakash was saying now, as far as ONGC is concerned. But the allocation for other investment, there are, like, you know, the OVL, we are planning to, I mean, OVL is- OVL, before this, the FM situation in Mozambique, we were having a budget of INR 8,000-INR 8,100 crores. For after that, the two years budget was scaled down, and current year be something around INR 3,300 crores. But with the resumption, likely restart in the next year, we will have a budget of around $1 billion, around going back to, say, INR 9,000 crores, on the OVL side. And that level of budget will continue for the next 3-5 years. As far as renewable energy is concerned, we have already announced that, you know, we would be planning to spend around INR 100,000 crore by 2030. So that plan is there, but that's a relatively a longer term plan, so the things, you know, are being worked out in integrity. Yeah, fair enough, sir. So just the last thing on this point on Mozambique, can you just help us understand the restructuring that you've announced, and what are the implications in terms of earnings, taxes, et cetera, on the recent restructuring that you announced? Restructuring of the operator organization, right? That's correct. Mozambique, yeah. So actually, you see that that restructuring has got not much to do with the taxation. It has got rather actually, because Mozambique is a big size energy project with a very high level of CapEx, which was actually announced at $15.4 billion-$1 billion in June 2019. And this project development has been secured through project finance. So the project finance was agreed for $16 billion. Now to have that kind of debt on the partners, on the partners' books, an asset holdco model, AssetCo model has been evolved, under which the assets of the project and the debt will remain in the AssetCo and will not get transferred to the respective partners' books. So that actually is the purpose for which the AssetCo model has been created. Because right now the project is, like Indian Oil Corporation has 30% participation in the project, of which OVL holds 16% and 10% is OVRL. So OVRL has assets of 10%, and our associate, BREML, has assets of 6%. These will get transferred to the AssetCo model company, Moz LNG, and the debt will also remain in that company only. Got it. Clear. Thank you, sir. Thank you. Next question comes from Sabri Hazarika from Emkay Global. Please go ahead. Yeah, good afternoon, sir. So two questions. First one is, so what is the current oil production in KG-98/2? Currently, we are producing something of 12,000 bbl per day. 12,000 bbl? Yeah. Okay. Gas is around 1.75 million cu feet per day. Gas is around? 1.75. 1.7 MMSCFD is gas, and 12,000 bbl per day is oil? Right. You are selling it also, or is it, I mean, or you are, like, storing it right now, this oil, 12,000 bbl per day? The oil, we have got a tie-up. We are in the process of making a tie-up with MRPL for the first load of the tanker. Okay. So, so does it mean that, I mean, you have something like 450,000 bbl per day of oil, so this 12,000 will add into there, right? I mean, it will be reflected, in Q4 numbers, whatever, whenever they come, right? Q4 numbers will be reflecting this 12,000 bbl. Okay, sir. And secondly, what was your nine months cumulative ninety-eight bar two gas production? 98/2 cumulative? Gas production for nine months. Okay, Sabri, we will come back to you. If you- Yeah, Go ahead with that. Yeah, yes. Okay, I, I'll touch base with you personally, sir. So second question is regarding your windfall tax. So now it's, like, largely established that the government is like... government has allowed you around $75 of an acceleration. But given the fact that we are almost like one year down the line, and next year your cost and all will also go up, so have you gone to the ministry or to the government, saying, asking for an increase in this hurdle rate in order to, like, take care of whatever cost escalation happens in the oil side? I know in gas, I think from FY 2026 onwards, $0.25 is something which was given in the guidelines. But for oil, are you, like, requesting the government to look into this, or have you got any indication, or do you expect that the windfall hurdle rate will be increased from 75, from FY 2025 onwards? Yeah, just, just one second. See, as far as SAED is concerned, it's, you know, government policy. We have been pursuing with the government for reviewing this. But currently, it will be difficult for us to say exactly what will happen as far as SAED is concerned. But yes, yes, we have been pursuing it with the government. But you might have seen that our cost figures also that way, like, the way you are apprehending it, it's not that, you know, costs are going to escalate very high. We, the OpEx numbers have been, you know, more or less steady as far as ONGC is concerned. So we don't expect that the cost would be substantially higher that way. Really, the price that we are currently getting is also, you know, a comfortable price for us. Okay. So any guidance on the cost side can you give? Because if I look at 9 months, 2023, so your total other expenditure was around INR 13,600 crore. So 9 months, 2024, has been like INR 16,000 crore. So it has actually increased. So FY 2025, do you expect it to be, like, similar? Or, is it like, I mean, you see it a normal increase, or can it increase higher, given that rig rates and all are, like, higher? Yeah, one major reason that you find that, you know, the expenditure in totality has gone up compared to last year is because we started taking a hit on GST on royalty. Last year, a substantial amount has been booked into, you know, INR 9,000 crore we took for pertaining to previous years and INR 3,000 crore of last year. So, that now the expenditure is around, say, INR 2,300-2,400 crore annually that regularly now we have decided to take a hit. Though we have been pursuing with the government, and we are very hopeful that the nine bench, you know, has been constituted at the Supreme Court, and we are still hoping that we'll have a favorable decision on that. So in the past, we were just showing it as a deposit, and we were not taking a hit in the P&L, which we started in the annual accounts last year. Apart from that, if you see the expenditure that we have, the cost escalation is coming through mainly, you know, for development purpose only. Like, you know, if we say, for example, in the offshore we spent, we have decided to spend money on water injection, which will result into, you know, for we are expecting that from the existing mature field, we'll have more production. So those kind of expenditure only, it is not like expenditure which are in the nature of, you know, infrastructure expenditure. Yes, as you said, drilling cost is one major component in the cost, which in the current year it has gone up more, but we are expecting that the prices for the rigs also, we are expecting that based on the projections, it will cool down. Okay, sir. And just one small question: so SAED is being imposed on 98 by 2 crude also? Yeah. Right now, we are getting it reviewed. This applicability of SAED and other taxes, it is under review. Right now, the preliminary view is that it may not be applicable, but it is not final. It is under review. Okay. So, right now, the rough cut view is that SAED may not be imposed at all on 98 by 2 crude. That is 12,000 bbl per day. Okay. Okay, sir, thank you so much, and all the best. Yeah. Thank you. Thank you. I request the participants to stick with one question in the initial round and join back the queue for more questions. Next question comes from Gagan Dixit from Elara Capital. Please go ahead. Yeah, yeah, thanks for taking my question, sir. Sir, there is a news that ONGC planning to drill a well in the Andaman Basin, this from bidding. So what I read in the earlier details, reports that it is a potential of, like, under 80 million ton or 1 billion bbl, something. So, am I assume this is something similar resource that you are targeting from the exploratory well, from that basin? It's the exploratory well under the OALP bid round, what we have got the block there, and we are taking our first exploratory well in this calendar year. Resource estimation from this well, we will be able to communicate later on. Okay, okay, because I thought that might be you have some idea about based on your 2D, 3D surveys, so, that's something minimum target that you are targeting. Okay. So it's exploratory well, you know, so let's- Okay, sir. Hope and wait and watch that we get a good result from this one. My second question is, sir, that there's also the news that this ONGC is in talks with restarting its production in Libya that they exited 13 years back. So, any status of it, if you can just point it out, please? ONGC Videsh does not have any production asset in Libya. So, we don't, I mean, have any option to produce from there. I don't know. Okay. That, that's from my end, sir. Yeah, thank you. Thank you. Next question comes from Vikas Jain, from CLSA. Please go ahead. Hi, sir. Thanks for taking my questions, sir. Firstly, sir, your OpEx is very, very high for this particular month, even this particular nine month, even after we adjust for your GST on royalty. It is for this particular quarter, it's at about, you know, at this nine month, it's 25% up year-over-year, which comes on top of 11% increase that we saw in FY 2023, full year. And this is even before Q4, which typically has been a pretty, a quarter where you and typically have ended up booking large OpEx for the last 5-6 years. So what exactly is happening? Because my worry is that in most cases, whether it is our oil realization or gas realization, they are capped at a particular level. But if OpEx keeps rising and production anyways, we've been struggling to grow it, how, you know, how will profits kind of improve if that is really the case? So any particular reason why one can imagine that this 25% increase in 9 months is a one-off? And secondly, Q4, will it again see a jump, which typically it has seen in the last 4, 5 years? Yeah, just a second, Vikas ji. ... Yeah, you were talking about the increase in OpEx over the nine-month period, right? That's correct. Basically, if you have seen that, you know, in this quarter, Q3, by Q3, the OpEx increase is only about INR 105 crores. We are more or less on the same level that we had for the last year. As far as nine months is concerned, the increase is mainly because, you know, during the COVID period, we had the operations were down, and then we had some, you know, damages happened, which happened in the offshore. So one-off expenditure in terms of repair and maintenance, almost INR 323 crores is on account of that. And then, as I said earlier, to another question, you know, we have now we are focusing more on water injection, which is, you know, more like a development expenditure, though we are booking that in the OpEx. So that's around INR 224 crore, on water injection we are spending on the Western Offshore. So these are, you know, one-off expenditure which are contributing. It's not that, you know, they are a regular, you know, expenditure. In addition to that, you know, on VAT amnesty scheme also, we have decided to go ahead with one case, and where we are paying about INR 160 crore. Apart from that, you know, some of the old blocks that we had, where we, exploratory blocks, where there were certain claims with respect to LD and other things, which we mutually decided to go through eminent committee. On the basis of the recommendation, we have decided to pay some amount. So most of the increase that has happened is, you know, in the nature of one-off expenditure. They are not a regular, you know, increase on the basis of the production numbers. They are not directly variable with the production numbers. Sorry. So when you say, like, water injection, that would not be one-off, right? I mean, now, now you will account for it every quarter, whenever that happens, right? No, what I'm saying is that once we... Yeah, yeah, once we pick up a field and we decided to go. See, water injection is not something which we incur on the basis of the production every year. Certain fields where we have, where we feel that the need for water injection was there, we had been postponing it for some time in the past, and now in the current year, we have decided to go for it. Okay. No, so the last part that you mentioned around some provisions that you've thought of accounting, that- Yeah. that has all increased the CapEx, the OpEx number for this particular quarter. How much is that total number? I mean, is there provision or whatever you said that you have... Or is that an ongoing thing that you have decided to charge every quarter from here on? No, not in the nature of ongoing things which we decided. Earlier, like, you know, we were having certain dispute with respect to completion of some of our exploratory schemes, which we could not, like, you know, for reasons beyond our control, things got delayed, so the applicability with respect to LD and other things were in dispute. So we decided to go for a dispute resolution mechanism, and we had constituted an internal committee of eminent experts, who are mostly like, you know, eminent people from this industry. Through them, we decided that, okay, let us close this. Similar to the VAT amnesty scheme, which you are aware, so that's also a one-time solution to, you know, mutually agreeable solution, which we decided to go for. So they are not in the nature of recurring expenditure. This, the numbers which I told is that with respect to this LD for 9+ was INR 136 crore, and the VAT amnesty scheme was around INR 180 crore, which we have booked in the current. Sir, I mean, see, what I'm worried about is if you see a simple lifting cost has gone up from, for nine months is, versus $10 is about $12 or so. Okay? And if we also look at our you know the exploration write-offs, et cetera, and this is even before the Q4. Q4, typically over the last 5-6 years, has been a quarter where there's been very big charges which typically come in, both in terms of exploration write-off as well as operating expenditure. So is there any change that we may not see something like that in Q4? Because even on an ongoing basis, OpEx has been higher through this nine months or that, you know, that's something, you know, that's, that this is the new OpEx number we should be working with. Yeah. See, as I said, you talked about the lifting cost. In fact, precisely the water injection that we are doing is also forming part of the lifting cost. Whatever the water injection that we do in the reservoir, that is basically adding to my lifting cost. So again, that is one reason why the cost has increased. As far as the exploratory write-off is concerned, in this particular quarter, we have taken a hit of about, you know, one well in Mahanadi, where which was an expendable well, that is almost INR 500 crore for one well. So these are not the expenditure that we expect that, you know, will happen regularly. This kind of industry, such things do happen. One-off expenditure once in a while do come largely, but we don't expect that the dry wells that we are going to be charged in the last quarter, that you are asking me, that we are not expecting to be high. Okay. And, just one more thing, the new change in Mozambique in terms of the way the ownership has been structured. So this will now allow us to book reserves as well, because earlier, from what I remember, part of that, you know, 10% was owned by... The 10% where 6 was owned by you and 4 by Oil India, that was in the form of an investment, so reserves could not have been booked. So that will change now, right? I mean, we'll be able to book reserves. Is that correct? Yes, yes, correct. ... Yeah. Okay. So that should, yeah. Okay. Sixteen percent. Sure. Sure. Thank you so much. Thank you. Next question comes from Somaiya V. from Avendus Spark. Please go ahead. Yeah, thanks for the opportunity, sir. Sir, in terms of the new projects that we have lined up, besides KG Basin, can you just give some color on next three years or so, what are we expecting in terms of incremental production from these projects, and what is the CapEx spend related to them? Incremental production from KG 98/2 or the total project, what we are planning in the next three years? No, outside, outside of, I mean, KG 98, the incremental projects that are coming online next 2-3 years. So what is the production expected from them, and what is the CapEx that we need to spend for? The total CapEx, as I earlier said, that is, is in the, the ongoing projects, value something of INR 60,000 crore, which will be materializing in the next 2-3 years. They will be having a lifecycle gain of around 80 million tonnes of oil equivalent. Moving forward in the next 3 years, we will be expecting something around 5 million tonnes of oil equivalent from these new projects, of which the major chunk will be coming from ninety-eight bar two, to the tune of around 4 MMTOE. Around 1.5 MMTOE from Daman upside. Then we have got the CBM project in Jharia and Bokaro, which will be contributing around 0.5 MMTOE. We have got the S1-Vashishta, which will be again contributing around 0.5 MMTOE. We have got a few other projects of development of contact areas under this DSF-II blocks are there. We have got Mumbai High Redevelopment Plan phase V, which is upcoming. Daman upside. Daman Upside, I already told you. There are various IOR projects which are upcoming in the onshore projects, which will be again adding up to something around 0.3 or 0.3-0.4 MMTOE. So these are the projects which we are looking forward to for completion in the next three years. Got it, sir. So one question on the CapEx, this INR 30,000 crore-INR 35,000 crore run rate that we are mentioning, can you just give some color on... You did mention that now in terms of new projects, this is a INR 60,000 crore spend probably over a 3-year timeframe. So what is the level of maintenance, exploration and new project spend, if you can give a rough breakup in this INR 30,000-INR 35,000 crore for the next 2, 3 years? So if you broadly, if you see, that whatever our CapEx outlays there, our development projects contribute something around 60% of our total CapEx outlay, in the development drilling as well as the capital projects, what we are taking on. Yeah, so to be specific, basically, if you see, survey would be around 11%, okay? And explorative drilling would be somewhere in the range of 22%, and development drilling would be in the range of 25%-27%. And the balance would be on infrastructure and other capital, which would be around 37%. Sir, also, any update on the OPaL equity infusion? See, we have already drawn up a plan of infusing around INR 19,000 crore of capital. The proposal has got approval of our board, and we have already submitted to the government. But it is under active consideration at the government level. And the CapEx number that we are saying, INR 30,000-INR 35,000 crore, is a standalone level. It does not include any equity infusion? That includes a minimum equity, not the OPaL, what sir was talking about. Understood, sir. Thank you. Thank you. Next question comes from Manish Oswal from Nirmal Bang. Please go ahead. I repeat, the question comes from Manish Oswal from Nirmal Bang. Please go ahead. go ahead. There is no response, sir. Thank you, sir. Yeah. There are no further questions. Now, I hand over the floor to Mr. K.C. Ramesh, CFO, for closing comments. Yeah, thank you. Thank you all for joining this call today. It has been a pleasure for us to take all your questions. As was said in the initial remark by our Director of Finance, we are expecting that, going forward, you know, in this particular quarter itself, with the KG 98/2 commencing production, the production number that we have for last quarter of the last year, we would be able to maintain in the last quarter of current year, though for the first three quarters, it has, you know, it's slightly on the lower side. But we are hoping that for, you know, better outlook and, we are very confident about the future that, whatever initiative that we are taking in terms of further foraying into other areas apart from the conventional oil industry, they would be paying us, good dividends. The investments have been well, you know, planned, on a well-thought-out, basis. So, with this, the price outlook for gas is also pretty, I mean, good, that we have already got based on the Rangarajan Committee. We are expecting that, the incremental production, which is coming through gas, will be fetching us almost $9-$10 per MMBTU. So gas would be adding substantially to, you know, our, top line and bottom line, as well. With our persistent, you know, we will be trying to keep taking up with the government with respect to the SAED applicability, and hopefully, if you can get something positive on that as well. On the oil front also, we would be doing comfortably, well. So, you know, with controlling the cost is one area that we have been focusing now, and we hope that we'll be able to identify certain areas where we can focus and reduce the cost as well. So both on the cost and revenue front, we hope that we can substantially add to the bottom line. So with that, we hope that, you know, in future, from 98 bar 2 adding the Daman upside, which Mr. Pavan Aggarwal was saying earlier, that that is also going to come. So the production numbers, as well as the new initiatives that we are taking, that will pay us dividends. And we keep, you know, continue to pay good dividends, which we have been doing in the past as well, and the current year, we have already given an indication of where we are in terms of paying dividends. So with all this, the outlook looks quite good for us, and we hope you all will be there with us in this journey. Thank you. Thank you, all. Thank you so much. Thank you, sir. Ladies and gentlemen, this concludes your conference for today. Thank you for your participation and for using DuraSabha Conference Call Service. You may disconnect your lines now. Thank you, and have a good day.