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Oil and Natural Gas Corporation Ltd
Earnings Call Analysis
Q2-2025 Analysis
Oil and Natural Gas Corporation Ltd
ONGC reported a net profit after tax of INR 11,984 crores for Q2 FY '25, reflecting a significant year-on-year increase of 17.1% from INR 10,238 crores in Q2 FY '24. However, the revenue for the same quarter saw a decline of 3.5%, totaling INR 33,845 crores, primarily due to lower crude oil prices. Year-to-date, the profit after tax for H1 FY '25 is INR 20,922 crores, a modest increase of 0.8% from the previous year.
The realization of crude oil in INR terms stood at INR 6,561 per barrel for Q2 FY '25, down from INR 7,013 per barrel a year earlier—a decrease of 6.4%. This price reduction significantly impacted overall revenue, demonstrating the company's sensitivity to global oil price fluctuations.
ONGC benefitted from a substantial decrease in statutory levies, with expenditures dropping by INR 2,960 crores (27.4%) in Q2 FY '25 compared to the same period last year. This reduction stems from lower crude oil sale prices and the government's rolls on special additional excise duties. In contrast, operating expenditure jumped by INR 277 crores (4.5%) to INR 6,389 crores, attributed to increased activities in offshore projects.
ONGC achieved a commendable crude oil production of 4.576 million metric tonnes in Q2 FY '25, marking a 0.7% rise from the same quarter a year prior. This marks a critical reversal of the declining production trend, with the total production for H1 FY '25 reaching 9.204 million metric tonnes, also reflecting a 0.8% increase from the earlier period.
ONGC announced an additional investment of INR 18,365 crores in OPaL, which will increase its stake from 49.36% to approximately 95.69%. This funding is aimed at enhancing operational efficiency and ensuring a stable feedstock supply for OPaL. The utilization rates for OPaL have reached 94%, with revenues recorded at INR 3,664 crores.
The company set forth ambitious production targets, forecasting crude oil production to reach 22.8 million tonnes and gas equivalent to 22.1 million tonnes by FY '26. They anticipate their cumulative production for oil and gas equivalent at 44.9 million tonnes for FY '25. Additionally, guidance for gas production from the KG-DWN-98/2 block is projected to hit 10 MMSCMD by the end of FY '25.
In response to strong earnings, ONGC's board declared an interim dividend of 120%, equivalent to INR 6 per share, resulting in a total dividend payout of INR 7,548 crores. This marks an increase from the previous year's interim dividend of INR 5.75, reflecting increased shareholder value amid fluctuating market conditions.
ONGC is committed to reversing the production decline trend and aims to enhance domestic production through new investments and well interventions. The infusion of capital into OPaL, along with improved feedstock pricing due to government allocations, positions the company for better financial health moving forward. Analysts expect profitability for OPaL to significantly improve from FY '26 due to lower debt burdens and more competitive input costs.
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Good afternoon, ladies and gentlemen. I'm Felicia, moderator for the conference call. Welcome to ONGC's Q2 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 Q2 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.
Yes. Thank you very much. Good afternoon, ladies and gentlemen. To introduce, I'm Vivek Tongaonkar, Director Finance, ONGC. I welcome you all in this ONGC earnings call for Q2 and H1 ended financial year '25. Thank you all for joining us on this call.
I'm joined over here by my colleagues from ONGC, Mr. Ajay Kumar Singh, who is our Chief Corporate Planning; Mr. Satish Kumar Dwivedi, our Chief JV and BD, Mr. Devendra Kumar, Chief Corporate Finance; Mr. Akhilesh Tiwari, Head, Corporate Accounts; Mr. Prakash Joshi from Investor Relations, Mr. Lakshman Gora. From OVL, we have Mr. Vinod Hallan and Mr. Raj Kumar.
ONGC has compiled its financial results for the quarter and 6 months ended 30th September 2024, which have been reviewed by the statutory auditors. The financial results have already been released on 11th November '24 through a press note and sent to the stock exchanges. This has also been sent to the analysts, who are on our mailing list.
I'll present a brief synopsis of the results. The company has earned a net profit that is profit after tax of INR 11,984 crores during the second quarter of financial year '25 as against INR 10,238 crores during the second quarter of financial year '24, which is an increase of INR 1,746 crores, that is 17.1%. Correspondingly, for the H1 financial year '25, the profit after tax has increased by INR 157 crores, that is 0.8% from INR 20,765 crores in H1 financial year '24 to INR 20,922 crores in H1 financial year '25.
The sales revenue for Q2 financial year '25 has decreased by INR 1,218 crores, 3.5% as against the corresponding quarter of previous year due to lower crude prices. However, [indiscernible] has increased by INR 276 crores, that is 0.4% for H1 FY '25 as against the corresponding H1 of previous year, mainly on account of increased sales revenue from value-added product sales.
The realization of crude in rupee terms stood at INR 6,561 per barrel in Q2 FY '25, vis-a-vis INR 7,013 per barrel in Q2 FY '24. That is a decrease of INR 452 per barrel, 6.4% in INR terms. Similarly, realization for crude in rupee terms stood at INR 6,744 per barrel in H1 FY '25 vis-a-vis INR 6,641 per barrel in H1 of FY '24, which amounted to an increase of INR 103 per barrel, 1.6% in INR terms.
The expenditure on statutory levies, the royalty and excise duty have decreased during Q2 FY '25 by INR 2,960 crores, 27.4% and in H1 FY '25 by INR 642 crores, 3.5%, in comparison with similar period for the previous years. This decrease in statutory levies is attributable mainly to a decrease in average sale price of crude oil, levy of special additional excise duty by Government of India on production of petroleum crude at a rate revised every fortnight based on international crude prices. This SAED on crude has been levied with effect from 1 July 2022, and it amounted to INR 3,352 crores in Q2 FY '24 and to INR 1,127 crores during Q2 FY '25.
SAED from the second fortnight of September '24 is nil. There is an increase of INR 4 crores in exploration cost written off in Q2 FY '25, and INR 631 crores in H1 FY '25 vis-a-vis the corresponding periods for the quarter and half year of the previous year. The increase is mainly on account of increase in 3D data acquisition and to charging off of drivers at western offshore basin, Assam and Arakan Basin and Vindhyan Basin.
The operating expenditure has increased by INR 277 crores, 4.5% from INR 6,112 crores in Q2 FY '24 to INR 6,389 crores in Q2 FY '25. Similarly, the operating expenditure in H1 FY '25 has also increased by INR 390 crores, that is 3.2% from INR 12,080 crores in H1 FY '24 to INR 12,470 crores in H1 FY '25. This increase is mainly on account of increasing activities at KG-DWN-98/2 and increase in repair and maintenance at Mumbai Offshore and other production expenditures.
DD&I costs for Q2 FY '25 and H1 FY '25 stood at INR 5,598 crores and INR 11,495 crores, respectively, as against INR 4,721 crores and INR 9,718 crores during the corresponding period of previous year. This increase is due to increase in O&G assets, increasing depletion rate and increased number of work over days and major capitalization of INR 166 crores at Western offshore.
At the consolidated level, the company has earned a net profit that is profit after tax of INR 9,878 crores during the second quarter of FY '25 as against INR 16,171 crores during the second quarter of FY '24. This is a decrease of INR 6,293 crores. That is 38.92%. At the consolidated level, the company has earned a net profit after tax of INR 19,689 crores during H1 FY '25 as against INR 33,666 crores during H1 FY '24, that is a decrease of INR 13,944 crores, which is 41.52% decrease.
This decrease is mainly due to a decline in profit of subsidiaries HPCL and MRPL. After this profits, the Board has approved an interim dividend of 120%, that is INR 6 per share of INR 5 each. The total payout on this account will be INR 7,548 crores. In the previous year, the company has declared an interim dividend of INR 5.75 on each equity share of INR 5.
The government has approved additional investment in OPaL by ONGC, and it has also allocated gas from new wells up to 3.2 MMSCMD. This assures -- this gives assured feedstock supply and pave the way for sustainability of OPaL.
Investments totaling INR 18,365 crores by ONGC in OPaL will result in an increase in ONGC stake from 49.36% to 95.69%. ONGC has already infused INR 13,200 crores in OPaL, which has been used to retire high interest debt of OPaL. OPaL is now the seventh subsidiary of ONGC.
Lastly, before I finish, I would like to add that with focused approach and continuous thrust on increasing domestic production, ONGC has been able to reverse the declining trend in its crude oil production. The stand-alone crude oil production, excluding condensate during Q2 FY '25 was 4.576 million metric tonnes, registering a growth of 0.7% over corresponding quarter of financial year '24.
Similarly, the stand-alone crude oil production during H1 FY '25 was 9.204 million metric tonnes, with an increase of 0.8% over H1 FY '24. We are happy to mention that 3 oil wells of A field of deepwater block KG-DWN-98/2 have been opened on 30th of October '24, thereby enhancing the total oil production from the KG-DWN-98/2 field to 25,000-plus barrels of oil per day from 8 flowing wells.
We also plan to open the remaining 5 oil wells shortly. Similarly, on the gas production front also, ONGC has been able to arrest the degrowth, the decline, which was 3.6% in Q1 FY '25 over Q1 FY '24 has been brought down to 2.1% in Q2 FY '25.
Friends, with this, I finish my briefing of the second quarter results for financial year '24-'25 and H1 financial year '25. And we will be happy to take questions from you. We would request you to restrict your queries on financial results only. Thank you very much, and the floor is open for questions, please.
[Operator Instructions] First question comes from Kirtan Mehta from BOB Capital Markets.
We have notified -- mentioned about 2 contracts during this press release, one, we have awarded on the L&T and second, we were awarded on the Mazgaon Dock with the potential of 5 MMSCMD and 4 MMSCMD. Would you give us more color on the project time line and the ramp-up that we can expect from these projects?
Yes. Both these projects have been awarded recently. And both these projects are likely to be completed by the end of '25, '26. Both would be producing gas majorly from Daman upside project also and as well as the DSF-II project. So both these projects would be gas projects as such.
These projects are primarily for the wellhead platforms so are the drilling contracts also awarded?
So the drilling contracts, we hire -- charter hire rigs or we have our own rigs, which would be carrying out the drilling of the wells, subsequently whenever these well platforms are ready. And the amount of gas that we are looking at is 5 MMSCMD in case of Daman upside and around 4 MMSCMD from DSF-II project.
So when we say about FY '26, this is basically the completion of the wellhead platforms and drilling contracts will be subsequently after that. So when do we start seeing the gas production?
What would happen is as the platforms get installed, we open them up for bringing our rigs over there and start the drilling of those wells from those particular platforms. So generally, what we will find is within about, say, 6 months latest from the completion date of all these platforms, we would have started with the production of crude oil or gas as such.
Right, sir. Understood. Second question was about the new well gas or well intervention gas. We understand that we have been allocated on 4 MMSCMD of gas as new well gas. How do we sort of -- is it basically that any decline over and above the 8% rate that we have been able to arrest that will get considered as the new well gas for us? And how do we expect this to ramp up over the next 2, 3 years?
So the new well gas is the gas, which is any new wells that are drilled or it is also from any interventions that happened in existing wells. That gas would be new gas -- qualify for new gas. Over a period of time, what we are seeing is that we expect a decline in our production to up to 6% to 7% with this new gas coming up because we keep on drilling new wells as well as well interventions are carried out on a regular basis. We expect the quantum of new gas to increase, and what we are expecting is that over a period of, say, maybe 7 to 8 years, most of the gas, which would be there from the existing field, should qualify to be new gas as it replaces the existing gas coming out from the existing wells.
Right. So as of now, there is no sort of the decline rate criteria that we have to meet, also over and above this particular decline rate only this will consider it as new wells. Is it any gas which comes out of the new wells or interventions will be treated as a new gas? .
See, generally, the decline rate that is considered is 7.5%, what is specified by the government. And we make up -- we would be making up any gas which comes beyond -- above this decline rate would be the new gas asset.
So in terms of the H1, we have just said that we have around 2.3% as sort of the gas decline, so roughly around 4.5% to 5% would qualify as the new well gas, as we end the FY '25. Is that the way to think about this?
No. See, whatever new gas we get from new wells that are drilled in existing fields or if we do any well intervention on existing wells, all that gas would qualify for the new gas purposes.
Fine, sir. And the last question, if I may squeeze in one more. On the KG-DWN-98/2, would you sort of say the latest guidance on the both oil as well as the natural gas ramp-up?
So we have already mentioned that we are producing 25,000 plus barrels of oil per day from KG 98/2. And we will be opening -- further opening up new wells over there. So earlier on, we have given a guidance of 45,000 barrels of oil per day being the peak towards the end of this year, financial year '25. So as of now, we believe we are on track for that guidance.
As far as gas is concerned, we have from the East Coast about 2.5 MMSCMD being produced. We have mentioned that it would be around 10 MMSCMD towards the end of this financial year or just in the first -- in the new year '26, '27 also -- '25, '26. So...
This will also be related to the 5 wells that we are planning to open up. So the same well will contribute to this new gas production growth?
Yes. So these wells will contribute to the new production of oil and gas as such.
Thank you, sir, for this clarification.
There are 3 more wells that are being planned for this.
[Operator Instructions] Next question comes from Sabri Hazarika from Emkay Global.
Yes. Congratulations on a good set of numbers. So I have a few questions. So first one is relating to this new well gas. So it has -- I mean, this has been effective from 16 October. Is that right? I mean, in terms of accounting?
From -- yes, first week of -- 8th of August.
8th of August, it has been effective in your books, right? .
Exactly. Actually, if you see this notification has come on 8th of August, okay? And the billing has been started from September 2024, yes.
Okay. So this quarter also some impact is there. I mean some portion of the volumes is getting that $9 to $10 price, is that right?
New gas is getting higher price. .
You see from November 2024, previously, it was 4 MMSCMD, which was allocated. Currently it is 4.68 MMSCMD. Out of that, C2-C3 plant is 2.76.
Okay. So right now, if I have to do a modeling of this, then I have to like basically take the total production minus this 4.68. This 4.68 will be basically be $9 to $10, and the remaining will be $6.5. Is that right? .
Yes, this -- then you have to minus that HPHT and deepwater also.
Okay. So this includes HPHT and deepwater also, 4.68?
No, no, no. What you said from the total you're going to subtract it, it's...
Yes, that's right. That's right. I'm talking about, I mean ex-NELP. Maybe from nominated block, this has to be...
Yes, yes.
Okay. And your KG 98/2, I think -- I mean, that gas currently, what is the production of -- I mean you mentioned 2.6. So this is like -- this includes, I think, VA and S1 also, right? So pure 98/2 cluster 2 gas will be how much?
That would be 1.85.
That would be 1.85 MMSCMD and that will go up to say 7 to 8 MMSCMD, is that right?
Yes, broadly, we are on track for that.
And there, you're basically getting the ceiling?
We're getting the, sorry?
Ceiling price, right?
Ceiling price, yes, yes.
Okay. Is there anything specific formula. It's just the ceiling only, which has been like currently applicable? .
As of now, that is all.
It's a formula based on fuel oil, LNG, it has got a basket. So it is based out of that. .
Right, sir. And this -- I think this is also being sold as -- just one second, sir. Yes, fair enough. And -- okay, fair enough. And second question is on your CapEx. I think from the government data, I think your CapEx for this year has -- I mean, H1 itself has been like something like INR 24,000 crores. So anything -- any comments on that? I mean, given that full year number is generally INR 30,000 crores to INR 33,000 crores for you?
See, as you know, there, you can see the amount which we have paid to OPaL, that is also part of it. So when you say INR 24,000 crores, out of that INR 6,000 crores -- roughly around INR 6,000 crores, if it is September, so its balance was for our E&P.
Okay, sir. So ideally, it should be INR 17,000 crores, INR 18,000 crores only for H1. So INR 24,000 crores includes INR 6,000 crores of OPaL infusion as well? Okay.
Next question comes from Probal Sen from ICICI Securities.
With respect to OPaL, just following up on the briefing that done -- so just wanted to understand if you can kindly -- I did not get all the numbers in that. How much is the total investment done in OPaL still date by ONGC?
For what we have done now?
Including what we have done now sir, what is the total number?
So currently, we have done INR 18,365 crores...
Till date, we have [indiscernible] crores.
So out of INR 18,365 crores, we have infused INR 13,200 crores just now for this year after...
Till date.
INR 13,200 crores has been infused and INR 18,350...
INR 13,200 crores.
Got it. And the total investment envisaged is INR18,350, which will happen over H2...
INR 18,365 crores.
Now if I can ask, after this investment is fully done, what will be the residual net debt in the -- in OPaL, if I can get a sense?
Just give us a moment.
Sure sir. Hello?
Just a second.
Sure sir. I'm sorry, I thought I had got disconnect my apologies.
OPaL, after this infusion of INR 18,365 crores, you would be left with around INR 14,000-odd crores as debt balance after we input INR 18,000 crores.
Got it, sir. Got it. So almost INR 30,000 crores, INR 32,000 crores plus of debt will get reduced to the extent of our infusion, right?
Yes. Just hold on for a second.
Sure, sir.
Yes, go ahead.
So sir, in terms of just looking forward at what OPaL's performance would look like, now that we are resolving 2 things. One is the debt burden as well as getting gas also at a slightly more competitive rate, thanks to being allotted. What kind of profitability are we expecting from this business, let's say, over FY '26, '27 versus where we are now?
Yes. '24-'25, we are still expecting that the figures may be a little bit subdued. But from next year onwards, we are expecting that things should be a turnaround in OPaL barring any unforeseen changes to product prices, et cetera, or feedstock prices.
Any number in terms of EBITDA per tonne, even in U.S. dollars you can put on it, sir, as a range?
No, we would not be able to give any this thing.
No problem, sir. And secondly, with respect to the gas production, has there been any change in terms of the gas production ramp-up from previous guidance? Or are we sort of -- this is what we have sort of been working with for the last 6 months?
Currently, the ramp-up or whatever that we are expecting is already been mentioned that it will come from KG 98/2, which we have already given a guidance that it is likely to go up to -- from the East Coast up to 10 MMSCMD by the year-end. So that is -- as of now, we are looking at those gas figures.
Next question comes from Varatharajan Sivasankaran from Antique Stockbroking Limited.
Sir, if you can once again revisit the overall production guidance?
Overall production guidance? Okay.
Yes. Good afternoon, everybody. I'm Ajay Singh. I'm Chief Corporate Planning. Guidance for next 2 years, we are expected to produce and enhance from current year production to 22.8 million tonnes of oil. And similarly, 22.1 million tonne of gas equivalent. So both put together is about 44.9 million tonne of oil and oil equivalent in '24 -- '25, '26. And next year, we are planning to have cumulative production of 46.2 million tonne oil and oil equivalent in '26, '27, is the guidance.
Any breakup between oil and gas, sir, for '26, '27?
Yes. This is -- 41.9 is from the current year, 44.97 is the next year '26 -- '25-'26, the oil and oil equivalent both put together. .
And so if you can provide an update on the -- our OVL assets, all of them -- each of them, like if you have any specific status, which you can highlight?
Yes. Yes. Mr. Hallan will provide that update -- update on OVL assets.
Yes. OVL, we have currently 32 assets in 15 countries and those -- there are 3 assets in Russia, 1 in Mozambique. Am I audible? .
Yes, sir. If you can be a little more louder.
Yes. So we have 32 assets in 15 countries. And of these, we have 11 exploratory, 4 producing, 4 development and 3 pipeline assets. And the country wise distribution is 3 assets in Russia, 1 in Mozambique, 2 in Venezuela, 2 in Colombia, and 6 in Myanmar and 2 in Vietnam. This is a broad distribution. And we -- our production last year was 10.518 oil plus oil equivalent. And the guidance for this year is around the same number, 10.5. Of this, we have already -- H1, we have already produced 5.039 and the Russian assets, 3 assets, because of the conflict Russia, Ukraine, the production is slightly lower than as it used to be in the year '23-'24. The other assets are producing better than the average, which has been targeted for the year '24-'25. And the current year average production is something around 194,000 barrels per day against a yearly average of 201,000 barrels in '23-'24.
Fair enough, sir. Any update on Venezuela or -- and...
Venezuela, we are still -- actually Venezuela, the sanctions were lifted from October to 18th April 2024. During that period, negotiations were on and Venezuela PDVSA has proposed for taking over the operatorship. But again, the sanctions have been imposed after April. We are -- we have sought this OPEC approval. And in case that is coming, we'll try to make further progress on that whether we can actually operate those assets. And then -- because right now, the restrictions are in place for oil movement as well as the plant restrictions.
If I can squeeze one more question, sir, with regard to the West offshore Bombay high technical assistance tender you floated. Is there anything like which you can provide us an update? And also when the technical assistance does come through, any kind of best case and worst case upside in terms of production we can actually look at? I mean just to get the quantum of improvement we can get.
Okay. So that tender is still on. It has not yet been closed, but it should reach maturity in December. That is what we are expecting. And once that is done, we will be having some technical service provider to work with us. It would be a long-term process. As of now, we would not be able to quantify any gains, et cetera, that are likely -- because it would depend from TSP to TSP and what sort of work goes in after they have looked into all the data that is available for Mumbai High.
[Operator Instructions] Next question comes from Mayank Maheshwari from Morgan Stanley.
My first question [Technical Difficulty]
Mayank, there is an issue with your...
We are not able to hear you properly.
Can you hear me now?
Now better.
I was just on OPaL. I had a couple of questions. One was on the depreciation side, the increase in depreciation [Technical Difficulty].
I'm sorry to interrupt. Can you join back the queue, sir? Your voice is not clear. The next question comes from Gagan Dixit from Elara Capital.
Sir, so you mentioned in the press release that you are getting the 12% of the price of the Indian crude basket that from the new well there. So is this new well -- new wells from the nominated block or this KG block or it's something other fields?
Nominated blocks.
Okay, okay. What I know is that it's some 20% premium that was -- earlier that was the case over the $6.5. So is there any -- anything missing something here, sir?
Can you come back what you mentioned in the last statement. 30% what?
No, what I know is that 20% premium over the $6.5 gas on the nominated block that is the case, so it should be at $7.8 that should be the case.
Gagan, the issue is it is 12% on the Indian basket -- crude oil basket, so what the government has also said that gas price in India would be 10% of that Indian crude oil basket. Now Indian crude oil -- but that -- there was a ceiling of $6.5 per MMBtu. If it is $70 crude oil basket, then [Foreign Language], it should be $7 per MMBtu, but the government restricts it to $6.5 as of now. .
New case in new gas, it is -- it would be 20% above the price that is there for the APM gas. So if it is $70 per barrel is the Indian crude, then 12% of that -- because 10% plus 20% of that is 12%, 12% of [indiscernible] $8.4 per MMBtu would be the price, not 12% on $6.5.
Okay. Okay. It's not like 20% over $6.5. It's -- okay. It's a 12% of the current crude bucket? Okay, okay.
Of the Indian crude basked and this is basically announced every month, yes.
Okay, okay. And sir, my second question is you mentioned just that your natural decline rate is 7.5%. So is it fair to assume that this nominated block old gas, I mean $6.5 gas that production will continue to decline at 7% to 8% rate Y-o-Y from now on and it will [ increase ] by the new well or something?
Yes. That is what I mentioned earlier on that if you consider 7.5% as the decline on a normal basis and then we are -- if we are able to maintain the production at current levels, it effectively means we are replacing all the old gas with the new gas for nominated fields over a period of time.
Okay. So how much is the percentage of your -- I mean, in the -- I mean the $6.5 old gas, how much is the percentage of that at present?
So as of now, the new gas would not be very substantial.
But it will be continuously increasing on...
Because we started off in September. We said -- as we said that we started billing in September only. So over a period of time, they should increase -- from next year onwards, I think we would see a marked difference in the revenues generated from this new gas. .
Okay, okay. So older gas is something around 1 to 2 MMT, is something like every year it will decline? Okay.
Broadly.
Next question comes from Vikash Jain from CLSA India.
I have a couple of them and maybe one suggestion as well. If we look at your guidance for the KG field, it is -- can you just give a sense of the broad guidance at which you will reach 45,000 barrels. Can I take that as end of this fiscal, that is March '25, roughly? Or -- and what is the guidance to broadly when you will reach 10 MMSCMD. When you said end of the year, does that mean end of 2025 or the gas guidance?
So when we are saying oil 45,000 is what we are targeting for this year-end -- financial year-end, broadly. We already have about 25,000 plus producing. We believe that with the existing wells that are there and which we are going to open, we should be reaching our target at the peak production around that time.
Coming to gas, new wells are being opened up. And this, along with the oil and gas -- along with the oil, gas would also be produced. We are expecting that this gas production, what we have mentioned, would be around end of this year -- financial year '25 and maybe it may spill over to the '25, '26, but it will be there towards the end of this financial year.
So basically -- I mean, let's keep it broadly. So somewhere around May -- before the middle of calendar year 2025 somewhere around March, April, May, you will -- you are thinking -- you're targeting to...
We are estimating that as of now.
Okay. And the second question that I have is just for this calculation of decline rate to get to the volume of gas, which will get the higher 12% slope. Is FY '23 the right starting point of what your production was from nomination fields? And then if you are declining less than 7.5%, like, for example, to keep it simple, is FY '23 nomination field is 100 and is -- if in FY '25 -- or is it FY '24, what is the starting base that I should be looking at firstly? .
It's FY '23.
FY '24.
FY '24.
'23, '24 -- '24.
So FY '24, so if it is 100, and in FY '25, your average production stays at 100, then 7.5 units of gas will be getting a 12% slope starting FY '26. Is that what it means?
No, it would be from whenever that gas gets produced, yes.
No. So what I'm missing is that when do you -- your decline rate is to be 7.5% for the year. So it's average to average. So FY '26 is when you start getting the higher volumes? Or that is the bit that I'm not able to understand.
So it could also happen that I have drilled new well in this year that gives me gas so that would also on me at a higher price. .
Okay. So any kind of new wells that you drill even in your existing areas, so nomination fields so that you can separate out and say that this is volumes coming from new fields, right?
Yes.
So it is not just a simple 7.5% formula, but even that interventions that you do, which will give that extra volumes, which will get that extra price, right? So finally, sir, just one suggestion, since now we have 3 different prices operating and no real easy way for us to know for sure what is the volume that you're getting from intervention. Of course, there could be a simpler formula, which is not the complete solution.
Why don't we give a breakup of our gas volumes and the gas price for each of those 3 things? Maybe that will become more significant starting a couple of quarters from now as well because when KG field also comes in, then there is that significant proportion, which is the HPHT formula, plus next year onwards, there will be a big proportion -- a reasonably large proportion which will have the 12% slope, which will be almost -- as the almost similar price as HPHT effectively. So why can't we spill that volumes out separately for ease of everybody to kind of be able to model and look at things differently?
Okay. We'll have a look at it. And if possible, we'll certainly try and provide those figures, if possible. .
But roughly, sir, from your understanding, what is the volume likely to be in FY '26, which you will get this 12% slope. Is it 5 MMSCMD, 7 MMSCMD, any rough numbers?
As of now, it would be very difficult to say that because it depends upon the new wells that I drill, whether I get new gas out of it or the interventions that are done and whether we get gas out of it. So as of now, we would be -- it would maybe difficult for us to hazard a guess.
Next year onwards, we may get a better sort of an idea about this thing because we have just started from September onwards. Rather August, this notification came up. September, we have started the billings and -- because this also requires us to look into what are the new wells and what production is likely to come up.
Sorry, currently, what is the volume, roughly?
4.68 MMSCMD.
4.68? That is the number that you mentioned.
And it will change every month basically.
Correct. But it is likely to go up and the share of the 6.5 will be -- will keep coming down, right?
Exactly.
Next question comes from Nitin Tiwari from PhillipCapital India Limited.
So just a few clarification questions. So staying on the topic of new well gas, just wanted to understand the mechanism. So how does the gas gets certified as new well gas? Is there basically approval required from DGH? And then how does the mechanism with the customer works? I mean when you're offering that gas, does this gas gets offered under the usual APM mechanism or it is free to market and you're marketing it on [indiscernible] reason I'm asking is that would the NWG gas be marketed by you? Or will it be marketed by GAIL on your behalf? how would the marketing angle work?
So broadly, if you say the new gas that is being produced or would be set by DGH or [Technical Difficulty]
Sorry. Sir, your voice is breaking, sir. I'm not able to hear you properly.
Actually, there's a lot of background from your side, Nitin.
I'll mute my line, sir.
Nitin, there would be -- DGH would be looking into these new gas figures also. And then accordingly, it would be declared as new gas. There would also be -- the next question was whether we market it ourselves or we give it to GAIL. Wherever it is GAIL, we are selling it to GAIL and if this new wells are connected to or sold to GAIL, then GAIL will market it at the higher price. They'll buy it from us at a higher price. And if it is a direct customer, we would be selling it directly to the customer at this new price because this is what has mandated by the government.
Okay. So there is no fixed sort of marketing mechanism which is mandatory for NWG gas. Great, sir. And secondly, sir, on OPaL, I wanted to understand, it's a dual feed cracker, correct me if I'm wrong over there. So given that it can also process naphtha, so what was actually the need for allocation of domestic NWG gas for basically the cracker to be profitable?
So it can work on naphtha as well as gas ethane. And what was earlier plan was that naphtha was from ONGC, Uran as well as Hazira. And the LNG, which was being imported that from that C2-C3 was being extracted by our Dahej plant and then being supplied to this OPaL plant. However, once this LNG prices have gone up -- now today, LNG prices are $14 per MMBtu broadly. So with this, if you -- instead of that, if you can get a new gas which is still at around $8.4 or maximum $9 as of now, it is much cheaper as far as OPaL is concerned. They save around $4 to $5 -- $4.5 to $5 in this process. So it becomes that they have an assured feed also as well as a cheaper rate. So this allocation by the government makes OPaL plant more sustainable and viable. .
So why I'm asking that question is that I just wanted to understand that when you say dual feed cracker, so is it the same cracker which can -- we can take in both naphtha and natural gas or you 2 separate crackers, one taking naphtha, one taking natural gas. And secondly, a corollary to that, that -- did the company explore the option of importing ethane and then using that as a feed rather than banking upon NWG gas domestically?
Just a second, Nitin.
So it is a dual gas cracker -- dual cracker so -- which can be used both naphtha as well as gas. Earlier, the gas portion was through -- C2-C3 portion was being imported through rich LNG, which was coming from Qatar, RasGas and which was -- out of which part of this C2-C3 was being extracted by Dahej plant and provided to OPaL and the balance used to be returned back to GAIL, who was the owner of that gas as such. And the differential between those 2 was being made up through ONGC gas -- makeup gas.
However, that allocation of gas was stopped earlier on by the government. And now this has been made good again. So it is at $9 -- $8.4, $9. It is cheaper than importing LNG and providing it back to us. So if your question is why we have not used ethane, bringing in ethane requires much more infrastructure and which would take some time to build up also. And as of now, we are not sure whether it will come out to be cheaper than this allocated gas.
Understood, sir. And lastly, on the Daman guidance that you provided that 5 MMSCMD gas from Daman and another 4 from another field, I missed the name sorry, is expected. So if you can give some time line regarding that production?
So I said completion of these projects is expected in '26 -- FY '26. And gas on those fields should start up coming in '26, '27 onwards.
'27? All right sir. Understood.
Next question comes from Yogesh Patil from Dolat Capital.
Sir, question related to survey cost. Survey costs declined, any particular reason? And sir, your plans to drill a number of wells in FY '25?
Just a moment.
So second quarter, you are talking, there's a decline in survey costs. That is the question?
Yes, sir.
So broadly, it is because of monsoon only.
But sir, we have seen the decline on a Y-o-Y basis also. So last year also, we have seen the monsoon.
Yes. So the quantum -- if it is lesser in this period, what has been planned, that would result in lesser quantum of -- sorry, there's a quantum of expenditure one.
My second question is related to other income. So other income also gone up sharply. Can you share the dividend part of that other income, which you have received during the quarter?
Yes, yes. So the quantum that we have received is from IOC 1,404, from OVL 75, from HPCL 1,285, MRPL 251, Petronet LNG 56, and this is totally 3,071.
Sir, second question is related to, again, a 4.6 MMSCMD, which is notified by the government recently as NWG gas. So is this alluded to consumer for the next 5 years? I mean, as per my last reading, it will be allotted for the next 5 years. So just wanted to confirm the time frame? Is it a 5 years allotment or lesser than that?
So it is -- the allocation for 5 years is for OPaL only. That is one thing. For the rest of the cases, whatever would be a contract duration for that period, the price of that gas, if I am supplying partly from APM and partly from this new gas, accordingly, the price will change for the quantum that are being supplied to the customers, whether it's existing. And it would be for the term of the contract with that existing customer. .
Okay. Okay. And lastly, on the OPaL side, if you could share some numbers on the EBITDA levels, PAT levels for the first half FY '25 OPaL plant utilization levels? .
Yes, we can do that. So the utilization for Q2 as far as OPaL was concerned was 94%. Revenue was INR 3,664 crores. EBITDA was INR 78.67 crores, and PAT was negative, but that was minus INR 637 crores. It was lesser than the previous quarter PAT -- lost rather. Previous quarter in Q1, it was INR 983 crores loss, whereas in this, it has improved to INR 637 crores loss. .
Okay. And do we expect, based upon the new NWG gas allocation to the OPaL, we will come into the profitability in the second half FY '25? And based upon the current run rate, you might guide us?
Like I mentioned earlier on, we would -- we are not expecting any -- we would not be able to comment upon that as of now, but we do expect that from next year onwards, we should be in a much better position. OPaL should be in a much better position because the interest costs also will go down substantially for OPaL, and with ONGC pumping in or being the main shareholder, we are looking at ensuring that there is sort of a turnaround or the performance goes up and the capacity utilization also goes up.
Next question comes from [ Kishan Mundra ] from DAM Capital.
You were exploring setting up a new oil refinery at Prayagraj. So is there any update on that? Have you made any progress?
So as far as Prayagraj is concerned, I don't think we have declared anywhere that we are doing any refinery or et cetera, as such. What we have already mentioned earlier on in the press is that, we would be looking at petrochemical projects as such. On that also, we have not yet declared where it would be there. The studies are still going on. So I would not be able to comment about a refinery in Prayagraj.
Okay. Understood. Sir, second question is on OPaL. If you could give the bifurcation between how much naphtha did you use last year in FY '24 and how much gas did you use?
I think it is broadly 60-40. 60 naphtha, 40 LNG, but for exact figures, I may have to check that out again.
No sir, this 60-40 works. And lastly, sir, on CapEx guidance. If you could give the CapEx numbers for FY '26 and '27?
Yes. Just hold on. '26-'27 it is INR 36,000-odd crores as of now.
For both the years?
No. Which one? '26-'27 I told you.
'25-'26 and '26-'27 would be in the same range. Yes, more or less. From INR 34,000 crores to INR 36,000 crores.
The last question of the day comes from Hemang Khanna from Nomura.
Sir, I just wanted a clarification on the new gas volumes. So 4.68 MMSCMD, new gas does not include 1.85 from KG, right?
No, no. It does not include that 1.85 from KG.
Okay. So entire 4.68 is roughly at $9 per MMBtu of realization.
See, that is basically HPHT deepwater gas what you are talking about, KG 98/2. This is from our nominated field is what we were talking about, the 20% segment.
Correct. So the entire 4.68 is roughly at about, let's say, $9 odd?
Exactly.
Thank you, sir. Now I hand over the floor to Mr. Vivek Tongaonkar for closing comments. .
Yes. Thank you very much, and thank you all for those questions also and the interest that is being shown in our company. If you want any further clarifications or with the clarifications given here do not meet or do you require further information also, please feel free to contact our IRC cell, and we would be happy to come back to you and provide you the necessary information. So thank you all, and thank you from ONGC over here.
Thank you, sir. Ladies and gentlemen, this concludes your 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 good day.