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

Good afternoon, ladies and gentlemen. I'm Felicia, moderator for the conference call. Welcome to ONGC's Q1 FY '25 Earnings Conference Call. We have with us today Mr. Vivek Tongaonkar, Director Finance and team, who will interact with investors and analysts to discuss Q1 earnings. [Operator Instructions] 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, Felicia. Good afternoon, ladies and gentlemen. I am Vivek Tongaonkar, Director Finance, ONGC. I welcome you all in this ONGC Earnings Call for Q1 Financial Year '25. Thank you all for joining us on the call. I am joined over here by my colleague from ONGC, Mr. Ajay Kumar Singh, Chief Corporate Planning; Mr. Devendra Kumar, Chief Corporate Finance; Mr. Ashok Kumar from BD JV, he is 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. Mr. Mukul Bhatnagar, Head of Planning and Strategy from ONGC Videsh Limited. ONGC has complied 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 '25 as against INR 10,527 crores during the first quarter of financial year '24. This is a decrease of INR 1,589 crores, 15.1% decrease. This decrease in net profit during Q1 financial year '25 is on account of lower sales revenue, mainly due to lower natural gas realizations and increase in exploration write-offs and increase in depletion. The sales revenue in Q1 Financial Year '25 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 4 of previous year. The billing net of VAT and CST for crude during the first quarter of the current fiscal was at USD 83.05 per barrel as against USD 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 vis-à-vis INR 82.21 in the first quarter of financial year '24. Thus, realization for crude in rupee terms stood at INR 6,928 per barrel in Q1 financial year '25 vis-à-vis INR 6,277 per barrel in Q1 financial year '24. That is an increase of 10.4%. The expenditure on statutory levies that is royalty and excise duty, et cetera, have increased during Q1 financial year '24 by INR 2,321 crores, 31% in comparison with similar period of previous year. This increase in statutory level, 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 first July 2023, which amounted to INR 2,835 crores in Q1 financial year '25, against INR 713 crores during Q1 financial year '24. That is an increase of INR 2,121 crores. The operating expenditure has increased by INR 111 crore, 1.9% only from INR 5,958 crore in Q1 financial year '24 to INR 6,079 crores in Q1 financial year '25. There is an increase of INR 627 crores in exploration cost written off in Q1 financial year '25 to rupees -- that is to INR 1,643 crores in Q1 financial year '25 from INR 1,016 crores in Q1 financial year '24. This increase is mainly due to increase in unsuccessful wells charge of mainly at Western offshore and KG basin. The increase in survey expenditure is due to increased active survey activities in the JV, Chennai HELP blocks and at Western Offshore. DD&I costs for Q1 financial year '25 stood at INR 5,897 crores as against INR 4,997 crores during the corresponding period of previous year. That is an increase of INR 900 crores. This increase is due to increase in depletion expenditure of INR 748 crores, mainly at Western Offshore. The increase in depreciation by INR 250 crores is mainly at Western offshore by INR 215 crores due to increase in ROU depreciation related to hiring of work over rigs, offshore IMR vessels. The company at a consolidated level has earned a net profit that is profit after tax of INR 10,236 stores during the first quarter of financial year '25 as against INR 17,893 crores during the first quarter of financial year '24. That is a decrease of INR 7,657 crores, 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 fees, 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 in the various stages of development. Crude production has already commenced from KG 98/2. Hopefully, we would be better placed with oil in Q3 and gap in the quarters thereafter. Well, with this, I finish my briefing of the first quarter results for financial year '24-'25. We will be very happy to take questions from you. We would request you to restrict your queries on financial results only.

[Operator Instructions] First question comes from Sabri Hazarika from Emkay Global.

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, you will see some uptick in some sort of like a 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 have made one statement also that in Q2, one more well will come in August? So how do we see from a number point of view oil production as well as gas production in KG-98/2?

For 98/2, currently, we are producing oil at the rate of 12,000 barrels of oil per day and gas is 1.5 MMSCMD. 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 another -- 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 you will hit that?

We should be -- subsequent quarters, we should be achieving that 45,000 barrels per day of oil from KG 98/2.

What is the well yield currently? I mean, per well we are getting something like 5,000 to 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?

I'm Ajay Kumar Singh, I'm Chief Corporate Planning. Currently, we are producing 12,000 barrels of oil from 4 number of wells. And one more wells we are opening in this month. So we'll be operating with 5 wells with August '24.

Okay, sir. 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 of gas from East Coast. Out of that 0.4 million is from 98/2 and that will go to 1.4 million SCMD by August -- by the end of this month.

Sir, 1.4 MMSCMD is for this month, you are talking about, not for the tonne, right. I mean, I think 1.5 MMSCMD was the number that you gave?

Yes, I gave that number. Sorry, my mistake on that point.

Currently, we are at 0.4 MMSCMD, which is -- sorry, I mean 0.4 MMSCMD, which will go to 1.4 MMSCMD this month? And what is the trajectory, I mean, when will we hit 8 to 9 MMSCMD for gas?

By end of March, we'll be reaching to 6 million MMSCMD.

By March end, 6 million MMSCMD. And how many wells will be there by the time?

See, 98/2, we have 26 wells, out of that 13 is oil producing and 7 is gas producing. So we'll be opening all 13 plus 6 by end of March, entire one.

Next question comes from Kirtan Mehta from BOB Capital Markets.

In the press release, we've mentioned about 3 discoveries that we have identified. What is pull discovery, which is commercializing GS-6 and GS-8. Second one is the 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 the potential that this is establishing? And what is the further plan to sort of assess and take this discoveries forward?

See, these discoveries have happened recently. That development or that assessment of this discoveries, et cetera, will take some time. And it would be some time further on that we would be taking this on development plans and exploiting this discoveries as such. So that is the current state of it.

But is 0.2 million metric day (sic) [ million metric cubic meter per day ] is it a large flow rate compared to what we normally see from the discoveries. So does it indicate sort of a larger potential of the reservoir?

No, there is a potential for the reservoir. It is a decent floor rate that we have, and these are encouraging testing results that we have established, commercial hydrocarbon in that new formation for the first time. So further exploration, et cetera, would be further development also would have to be done in this particular formation for it to for establishing the potential of this formation as well as the flow rate that could be obtained from this formation.

Sure. And in terms of the pool discovery online when we mentioned that as a pool discovery, what's sort of the implication? And we have also said we have established commercial oil and gas, so what exactly are we sort of hinting at?

So pool discovery means it is a new area that has been found over there within that field itself. And 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 to develop it commercially or that we lose -- 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 a gist that we talk of when we say it's a commercial discovery.

So it will more likely be followed with a field development plan as well and we have reached at 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 wealth if the size is bigger or something like that. So it will take some time. It typically takes about 2 to 3 years for new areas or new fields to be sort of delineated and then finalize 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 -- there -- would you be able to share the details in terms of the size of the plant, time lines as well as potential CapEx involved?

I don't have that detail just now off hand. 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 online, but it is remote from any gas pipelines, et cetera. 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 -- this plan has been submitted to DGH. And once it is approved, we'll be able to go forward in the full fledge 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 track you on that...

Next question comes from Mayank Maheshwari from Morgan Stanley.

Sir, a couple of questions on the petrochemical side of the business and OVL. Can you just talk to us about what -- their 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, Mayank, I'll have Vinod Hallan -- Vinod Hallan from OVL is overe here, he'll respond to your question.

Actually, the production, 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 current. 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 really because of the lowering of the royalty expenditure in CPO-5 in Colombia.

So is the production number now adjusted for the royalty impact?

No. It remains the same. And...

So 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?

Mayank ji, we can come back to this question.

We will provide you the number later, but the current production from the block is something around -- we have 10 oil producers in the block. We are the operators in that block. We have a 70% share and the current JV level production is around 37,000 barrels with our share at 27,000.

Got it. Okay. And I think the second question was more in terms of the petrochemical side. I think the -- on the restructuring front, are you guys completely done with it? Where is the progress on that? And what can we expect now going forward on an OPaL?

So on OPaL, we are still awaiting certain government clearances. So once we get those, we should be able to announce it. We are very -- we have put our case forward to the government, and we are hoping that it should -- we should get 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 brand, 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 why the volatility is happening like this quarter, the discount on oil versus the benchmark kind of widened quite a bit.

So Mayank, the bottom line is that at the end of the day, the government ends up paying us about -- around $75 for per day -- per barrel for crude oil. And 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 is that...

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 are marketing freedom on oil now. So I was thinking like whether you will be able to kind of get your gross realization up.

For KG basin, et cetera, yes, we have got better prices. It has been -- we have got a premium over Brent for this KG basin crude oil. It crude -- typically prices are a combination of demand and supply as well as availability and all the Indian refineries are having -- are able to process various different types of crudes, most of which they import also. So Mumbai high crude as well as East Coast crude or for that matter, onshore crude is the already tied up with these refineries. And yes, we do get a premium on our crude as such.

And the premium is over Dubai or Brent that you're looking at right now?

Over Brent.

Next question comes from Nitin Tiwari from PhillipCapital.

Sir, my question is a clarificatory one. I didn't get the number of the production from KG 98, right? So I suppose you mentioned that the current rate of production is 0.4 MMSCMD. Is that correct? 0.4 MMSCMD from 98/2.

Yes. Our gas production is what you're saying is correct. And 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 2 point -- from East Coast is 2.4 MMSCMD, of which 1.6 MMSCMD is 98/2 and 0.8 MMSCMD is S-1 and Vashishta. So now as you mentioned, that's the number for 98/2 is 0.4 MMSCMD. So what has changed?

Current production is 2.4 MMSCMD. Out of that, we have other fields also which are contributing, near by field is G-1 and Vashishta. That all took together, we have production as on date 2.4 MMSCMD. And out of that 0.4 MMSCMD is from 98/2 [Technical Difficulty].

So 98/2 is 0.4 MMSCMD, then what are the other fields which are contributing to production? How much is coming from S-1, Vashishta and other fields? I mean if you can give us a field-wise breakup?

U field we are getting about 1.2 MMSCMD, G-1 0.5 MMSCMD and Vashishta 0.2 MMSCMD.

Sorry, G-1 0.5 MMSCMD and Vashishta you mentioned?

0.2 MMSCMD.

0.2 MMSCMD, okay. So that adds up to about 1.1 MMSCMD. What about the remaining production, sir?

1.2 MMSCMD from U field.

Sorry, which field?

U, umbrella.

U field, okay, 1.2 MMSCMD from U, all right, sir.

Nitin, hold on. Nitin that clarification, I think, earlier what has been mentioned are the current productions of Eastern offshore is 2.4 MMSCMD of which 1.2 MMSCMD is from the existing fields earlier and U field, which was part of 98/2 considered earlier on. What we have opened are wells of oil over here in 98/2 field cluster 2, that is 0.4 MMSCMD gas is coming along with it. From the other fields, which are there in the East Coast, which is SP-HG, G-1, VA-DA, that is 0.8 MMSCMD. So this all adds up to about 2.4 MMSCMD.

Sorry, sir. You said that the field U 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.

This is KG-98/2 cluster 2 the field is -- and the 0.4 MMSCMD is coming from the other cluster, is it?

Yes, that's right. From the [Technical Difficulty] by choosing the well...

But the entire production can be considered that the KG-98/2 -- I mean we have like how many 2 clusters, so the combined production would be about 1.6 MMSCMD, is that the right way of looking at it?

Exactly.

The 0.8 MMSCMD is the other fields in the Eastern offshore.

So there is -- I mean mostly like that tally with what you said in the previous quarter, 1.6 MMSCMD is coming from 98/2 from the two clusters that we have over there, correct. 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 deal in the time to come?

So currently, as of date we have invested about $4 billion plus.

$4 billion plus?

$4 billion. Around $4 billion, which is about INR 30,000 crores, if you can say, INR 30,000 crores that we have invested in rupees. And what else you want, sorry?

So what is the kind of IRR we are looking at from this deal? I mean...

IRR as of now, we would like to [Technical Difficulty].

I'm sorry, sir, the audio quality is not good. I'm not sure if it's only for me or for everybody, but your voice is breaking.

Is it better now? Okay. IRR is better than the rate of return that we have been targeting. And we are on track to sort of get good returns on this field.

You wouldn't want to specify your numbers, sir, for the field?

We 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 like 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?

Just hold on. So Nitin, just coming back on to that production front, for '24-'25, we are expecting for ONGC stand-alone to be about 20.5 -- 20.59 MMT.

20.5 MMT, okay, sir.

Yes. The JV products, we expect to be about 1.71 MMT. Total is 22.3 MMT. And we expect an increase of about 12% over a period of 2 years. So we are targeting around 21.87 MMT for oil stand-alone one point -- and 23.08 MMT in totality for ONGC and JV as of now.

In FY '26, sir, you are saying?

'26-'27.

'26-'27 is 21.87 MMT ONGC stand-alone.

Yes, and 23.08 totality, ONCG plus JV.

Understood, sir. And the same numbers for gas, sir, that would be really helpful.

Gas would be 20.95 MMT for ONGC, 0.65 MMT for JV, which is 21.60 MMT. The targeted increase of 27% up to '26-'27 on a totality basis, it could be 25 BCM, 26 BCM with ONGC contributing most of it at 25.5 BCM.

25 BCM, 26 BCM would be the total production for you and JV in '27?

25.91 BCM.

Next question comes from Varatharajan Sivasankaran from Antique Stockbroking Limited.

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, but there has been feedback from the government, doing it a formality?

We have not paid it.

Secondly, on the redevelopment efforts, which Mr. Tongaonkar was highlighting, if you can give us some more details as to which all fields are let now? What is the kind of CapEx being deployed there?

On the field's CapEx?

Yes, on the redevelopment programs, the CapEx, which we are spending, field wise, if you have some numbers?

Yes, yes, 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 KG 98/2, which is currently under progress. We have Mumbai High North redevelopment Phase 4. Then we also have -- these are planned. This Mumbai Phase 4 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 Bechraji field, which is in Mehsana onshore.

Any completion schedule, if you can share with us?

Yes. Daman upside development project has been awarded in this May '24, and we expect it to complete by February '26. KG basis is already underway. We expect it to complete by this -- in this year. Mumbai High North Development would take about 3 years to come up because we are at the FR and FDP area. Redevelopment of Linch, Sobhasa, Kalol, these would also be another 2-year projects. Bechraji also would be another 2-year project. 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 EU also, development of DS-17 field, which is also offshore and Mumbai redevelopment Phase 5, which will come beyond after Phase 4 is completed.

Next question comes from Gagan Dixit from Elara Capital.

Sir, can I go with your presentation of this June presentation, retention around [ 16 projects ] under conceptualization that you mentioned it has a [ 86 million ] tonne potential. So as I assume this is something exploration prospect that you were talking about?

The June presentation.

Yes, sir.

Last year -- okay, okay.

There is one project under contractualization more than INR 50,000 crores with 86 million tonne potential.

Yes, yes, yes. Just give me a second. So what was informed in June presentation were those projects which are in the conceptualization. You're talking about [indiscernible] field, additional development of [indiscernible] field, those ones, right? Additional development [indiscernible]. All these are currently -- we are working on them, but they are not has been crystallized, and therefore I've not mentioned it to you. But yes, these are also under consideration and conceptualization. What I have informed just previously was those deals or those projects in which we have already started work and where we are already under tendering.

Sir, my next question is about this Mozambique project. So recently, is TotalEnergies 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 to last year. Last year, they were telling them, what, should they start, somewhere in the early 2024, but now I think they are also waiting. So can I assume it's a 1-year delay almost in the Mozambique project?

Hallan will be able to...

[indiscernible]. It was earlier talked about for reduction in January '24, but that has gone far behind. And now, Gagan, as we said, is talking about elections, which are in October. There is some [indiscernible] with the U.S. election as well. So the hope that October to January '25 is the opinion that we can expect resumption of the work.

Sir, my final question about ONGC Green Limited, where I think you had some CapEx plan of 1 lakh crore, which is over the next 7, 8 years. So can you elaborate what are the infrastructure something that you want to target, i.e., how much is the green hydrogen ammonia capacity for the -- I mean development capacity that we are targeting over the next 6 to 7 years?

Yes. So our strategy has been that we plan to have about 10 gigawatts of energy, green energy, by 2030, which would comprise 60% to 70% of solar, 30% to 40% of onshore well, then we are also targeting green hydrogen, then CPG or biogas, offshore wind, [indiscernible] plant, CCUS. And the total investment that we are anticipating over here is about 1 lakh crore, including flare reduction and increase in energy efficiency. So that is the target in 2030.

And sir, how much is the green hydrogen or green ammonia that you are targeting to produce, I mean, by 2030?

So we plan to have 1 MMtpa of green ammonia, which is about 180 kt of green hydrogen.

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

Just a simple housekeeping question from my side. If you can have the CapEx target for FY '25 and '26 broken down into stand-alone, and if we can get a sense of what the consolidated CapEx would look like.

When you say consolidated, are you looking at also SEZ in Mangalore?

Well, if you can give any guidance [indiscernible] stand-alone, I would appreciate.

For this current year, we are planning around $4 billion-odd to be spent on CapEx over year at ONGC only. It would be around INR 32,000, INR 33,000 crores. We would expect similar amounts to be spent as of now on ONGC stand-alone for the future in 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 [indiscernible]?

OVL CapEx, in this -- by my estimate, '24, '25 year time, over INR 600 crores, and once we have Mozambique back on the wins, this CapEx number [indiscernible].

Sir, I cannot hear you. Sorry.

INR 8,500 to INR 9,000 when Mozambique comes -- if Mozambique comes.

[indiscernible] INR 5,600 crores, by our estimate, but...

So INR 5,000 crores to INR 6,000 crores ex of Mozambique, once Mozambique comes, an additional INR 2,500 crores to INR 3,000 crores will get added, correct?

Yes. Correct.

And the second question I had, sir, if you can give a sense of what the subsidies OPaL and OMPL have done in Q1?

OMPL is no longer a public company. It is already part of [indiscernible].

What about OPaL, sir?

OPaL is still a separate company. One moment. They had an EBITDA positive for the Q1, but on the [indiscernible] basis, they were negative. Just let me get the figures. So figures for OPaL were, the [indiscernible] for this Q1 was negative minus INR 983. And for the financial year '24, it was minus INR 3,456 crores.

Okay. And what was the EBITDA, sir? Is it EBITDA positive this quarter?

EBITDA for this year, for Q1 was INR 29 crores positive, and for the financial year '24, it was a loss of INR 479 crores.

479 crores [ lakh ]?

Last year.

And sir, if you can give some operational data in terms of volumes or on utilization right now?

Utilization last year was 92% and for this first quarter was 89%.

[Operator Instructions] Next question comes from Puneet Gulati from HSBC.

Can you talk about when do you see higher gas supply generation from your nomination blocks, given that you're drilling new wells?

Sorry, come back? Higher gas realization cost?

Yes. So from the nomination blocks, because there was this proposal where the new field will attract higher prices. 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. There's some more addition. Just hold on. Devendra, can you just add on to it, please.

I'm Devendra Kumar from commercial. This additional rate, 20% additional price from additional wells and well intervention, that is already notified. Only the mechanism to measure that is not in place, and 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, then what exactly constitutes 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.

And will it be prospector or [indiscernible]?

We received notification already there, so...

We would like it to be from the date of that notification, but we are not sure as of now.

And secondly, if you can talk a bit about what's driving the split of a little slower ramp-up in production on the KG basin field? And what has it done to your cost estimates versus a year back, both OpEx and CapEx?

OpEx slower implementation is partly due to weather. Weather has been quite rough during this year as such, and that is what has caused the delay. But we are hoping that we should be able to make up for all these delay and start-up productions, as I mentioned earlier on, in this quarter, from [indiscernible] and also for oil wells, which we plan to do, which are already completed, but we have to sort of start producing from them and from the third quarter this year.

And in terms of equipment and platforms, all those are now tied up. There's no portfolio [indiscernible].

Most of the -- whatever is required for operations has already been sort of put in place, and we should be able to start off 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. And lastly, if you can add a bit on the crude oil production, [indiscernible] scenario there for gross ONGC ex 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, and we are looking forward for additional additions in this year, as I said that we are expecting a production of 30-plus -- 30,000 plus from this new well that we are planning to put on [indiscernible] field 3 aside from the [indiscernible]. So we are anticipating that we should be having better production in this year over the previous year.

Next question comes from Vishnu Kumar of [indiscernible] Spark.

Actually, my question is on -- is related to the previous caller's question. So even in 1Q, if we look at the past couple of quarters also despite we have some element of ramp up in KG-98/2 in oil and gas, you still have production continuing to decline as we speak. At least calculated number tells me the 3% to 4% base decline growth is there. So even if let's say, this kind of decline continues even if we hit 30,000 on oil, we may end up being at least flat or negative. So just trying to get a sense that what efforts are being done or how confident are we of reaching the positive growth target, at least on oil from this side?

Yes. So just to mention to you that first quarter of every year is usually marked with a slightly lesser production because 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, et cetera, or that eventuality because of the rough sea as well as the rain over there at offshore. So that contributes for lesser production every quarter. Every year's quarter, first quarter 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 those the other players as well as whenever monsoon gets over, that is typically from 15th September onwards. So that production comes back onstream. East Coast also, as I've mentioned, that we are anticipating new wells coming up over here, and therefore, the production would increase. As I have mentioned, the production, feed production, is likely to go up to 45,000 barrels per day, which is a very substantial increase even if you consider ONGC FPSO. 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.

And secondly, on the production to sales ratio, obviously, we have some -- so the amount of volume produced with the volumes sold. For the new incremental volumes, will the number directly flow down to the [ sale ] number? Because from a modeling perspective, typically, we have a ratio, that's what we look at.

So for East Coast, we have the production going to an FPSO, and from there, it would be sort of going on to different -- we evacuated 2 other tankers to the refineries, so typically, I suppose your power production quantums and the sales quantums would be very pretty close to each other as far as oil is concerned.

And for gas, sir?

Yes, also I don't understand any very major differential to happen between the production and sales unless there is some flaring or technical flaring that takes place.

Next question comes from an from S. Ramesh from Nirmal Bang Commodities.

Good evening, and thank you very much. So when you gave the production target between FY '25, '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 will go from that 22.3 to 23.08 between '25 and '27. What was the number for '26 similarly for gas?

Okay. So broadly, as I said, 12% of -- I'm just mentioning that it would be 22 -- 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 will be around 23, 24 BCM as such.

Okay. So when you look at the KG gas volume of 6 million by end of FY '24, 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 your -- you'll achieve 6 million cubic meters a day of gas production in KG-98/2 by end of FY '25, right? So is that going to be the exit rate? Or will you be able to achieve an average run rate of 6 million cubic meters a day for the fourth quarter of FY '25?

The gas production of 6 million from 98/2, we achieved the -- production will be achieved in last fortnight of March '25. So it is not averaged out. It is not -- hope that answers your question.

Okay. So from 6 million, what can we expect, say, over FY '26 and '27?

Yes, we can expect [indiscernible].

That is what we want to clarify.

So you mean to say when we would be kicking [indiscernible] part 2, right?

Yes.

It would be towards the end of this year and then continuing from that onwards.

The question is from 6 million cubic meters per day, we have seen numbers of [ 12 to 15 CBM ]. So what is the actual number you can achieve, say, by '26, '27, and what is the kind of peak volume you're expecting based on the current plan?

For these details, we'll come back to you separately. Is that okay?

Yes, that's fine. So before I move to the next question on KG, now, is it still a work in progress? Or are you capitalized and book some revenue and income from the KG basin? And when do you expect the commercial impact to be shown in your P&L?

When do we expect, sorry, the?

In terms of the KG-98/2 production of oil and gas, when do we see those numbers being commercialized and booked in your P&L?

Already been -- we're already selling crude oil from there. 12,000 barrels per day. So it is all coming in our revenue.

Is there any profit you're making there as on date? And would we be able to end the year with...

No. I would not be able to tell you any profit, obviously, from that field, if you are asking that. We would not be able to do that. We do it only on a [indiscernible] basis only.

Yes. But just to understand, at what level of production you will break even at EBITDA or EBT levels?

No, I wouldn't be able to give that figure just now. But one thing we could highlight is a majority of the cost is being booked. That is already there.

Okay. So in OVL, what can we expect in terms of growth and in terms of incremental contribution to your cash flows? Or will it continue to require backstopping from ONGC in terms of additional equity, and [indiscernible] Mozambique is now going to get ramped up? And do you see any reduction in EBITDA during the CapEx phase in Mozambique? Or will the current commercial deal maybe generate cash flows from OVL?

We are generating sufficient cash flows, cash flows to manage operations and...

I can't hear you.

[Technical Difficulty] We are generate sufficient revenues to manage this operations, and last year, '23, '24, our oil production -- oil and gas production was 10.518 MMT, a little up from the '22 to '23 number of 10.17. This year, '24, '25, our target is 11. And the Q1 production is almost -- we are selling to the target, it is [ 25252 ]. So as regards to Mozambique, as you said, we don't see any reduction in that other. There will be some improvement as the force majeure costs which are hitting the P&L will be -- will not be hitting then the production when the Mozambique [indiscernible]. So -- and there is 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 [ VPOC ] and SPOC showing good results. SPOC, in fact, has clocked 13,000 barrels this year from the average of 6,000 barrels in '23, '24.

The last question for the day comes from [ Vipul Kumar Shah ] from [ Sumangal Investments ].

Yes. So line was bad, so I could not note down the figures given by you. So what should be our stand-alone and JV plus JV oil and gas production target for FY '25 and FY '26? Would you repeat it, please?

So for '25, '26, if we are saying it is 20.7 to 1.45, which is around [ 22 plus 23 ] -- around 20 to 20-plus figure for oil, gas is 23.83 and 0.53, which is 24.35.

That is for '25, right?

'25, '26.

Okay. And for '26, '27?

That was 21.87 at 1.21, which is 23.08, and gas is 25.49 and 0.42, which is 25.91.

Now I hand over the floor to Vivek Tongaonkar for closing comments.

Yes. Thank you very much, and thank you all for the interest that you have with ONGC. What we are looking at newer horizons, we are also looking at better production numbers from our new projects which are currently underway, project which is 98/2. We are very confident that, yes, we will be able to ramp up the production that we have, and actually 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 a green path. So we are already working towards those goals. And we thank all the analysts who track our company, and also we wish all our stakeholders a very bright future as such. Thank you very much.

Thank you, sir. Ladies and gentlemen, this concludes the conference for today. Thank you for your participation and for using Door Sabha's conference call service. You may disconnect your lines now. Thank you, and have a pleasant day.