Oil and Natural Gas Corporation Ltd

NSE:ONGC

Earnings Call Analysis

ONGC Q3 FY24: Decreased Profit, Lower Sales Revenue

ONGC reported a net profit of INR 9,536 crores in Q3 FY24, a 13.7% decrease from the previous year, mainly due to lower crude oil, natural gas, and value-added product (VAP) price realizations, alongside GST on royalty provisions. Over nine months, their profit decreased by 23.8%, with sales revenue down by 9.7% for Q3 and 13% for the nine-month period. Realizations for crude oil fell both in USD and INR terms, and expenses like statutory levies and exploration costs varied, with exploration costs increasing due to unsuccessful wells. Despite this, ONGC is proactively advancing new drilling activities to compensate for the decline in production from mature fields.

Overview of Financial Performance

The company reported a net profit of INR 9,536 crores for the third quarter of FY '24, showing a 13.7% decrease from the same quarter last year. The profit after tax for the first nine months of FY '24 also dropped by 23.8% to INR 29,767 crores. The decline in profits was mainly due to lower sales revenue resulting from diminished crude oil, natural gas, and value-added product price realizations, alongside provisions for GST on royalty.

Revenue and Sales Declines

Sales revenue fell by 9.7% for the quarter and 13% for the nine-month period compared to last year. The decrease was reflected in a drop in crude billing from USD 87.13 to USD 81.59 per barrel for the quarter, equating to a 5.1% reduction in INR terms for the quarter.

Statutory Levies and Exploration Costs

Expenditure on statutory levies, such as royalties and excise duty, decreased by 14.6% for the quarter and 23.7% for the nine-month period due to falling crude sales prices and government-imposed special additional excise duty (SAED) adjustments. Exploration costs written off increased due to more unsuccessful wells, particularly in the Western Offshore and Mahanadi basin, contributing to higher operating expenditures.

Depreciation, Depletion, Impairment, and Consolidation Effects

Depreciation costs rose mainly due to assets in the Eastern Offshore sector, while impairment for the nine-month period increased due to a reversal of last year's impairment on certain small fields. At a consolidated level, the company reported a net profit of INR 44,685 crores for the nine-month period, a significant 65% increase over the previous year, largely attributable to contributions from subsidiaries HPCL, MRPL, and OVL.

Proactive Measures and Future Projects

To counteract production declines in mature fields, the company is implementing well interventions and advancing new drilling activities. Production from new projects in development is expected to compensate for the declines, with oil production already commenced from KG 98/2. The company anticipates better placement for oil in the final quarter of the current financial year and for gas in FY '24-'25. They also expect improved gas pricing in the coming year.

Capital Allocation and Dividend Payments

The company has paid out dividends of 41% during the nine-month period and plans to continue as a strong dividend payer. With substantial surplus cash from good cash flow and normal capital expenditures (CapEx), the company plans to venture into areas beyond conventional E&P operations. The expected annual standalone CapEx for the next 3 to 5 years will be around INR 33,000 to 35,000 crores, with an additional INR 1 lakh crores planned for spending on renewables by 2030.

Financial Management and Debt

A project finance agreement for $16 million was reached with the debt to be retained within a specifically created AssetCo model, thus not transferred to partner companies' books. The current production is approximately 12,000 barrels of oil per day and 1.7 MMSCMD of gas. There are plans for a tie-up with MRPL regarding the first load of production, which may lead to increased costs in the next year.

Cost Guidance and Policy Pursuits

OpEx numbers have been relatively steady, and the company doesn't expect substantial cost increases despite the increase seen over the last nine months, attributed mainly to development expenses such as water injection, which is expected to boost production. They are also pursuing government review for the SAED policy, and they expect rig prices to cool down, which will affect drilling costs. There are no plans or production assets in Libya currently.

Earnings Call Transcript 2024-Q3

[Operator]

Good afternoon, ladies and gentlemen. I'm Pelcia, moderator for the conference call. Welcome to ONGC's Q3 FY '24 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. [Operator Instructions] 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.

[Manish Patil, executive]

Good afternoon, ladies and gentlemen. Just to introduce, I am Manish Patil, Director HR, holding additional charge of Director Finance ONGC. I will welcome you all in this ONGC earnings call for Q3 and 9 months FY '24. 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 9 months ended 31st December 2023, which have been reviewed by the statutory auditors.

The financial results have already been released on 10th 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 crores during the third quarter of FY '24, as against INR 11,045 crores during the third quarter of FY '23, a decrease of INR 1,509 crores, that is 13.7%.

The profit after tax for 9 months FY '24 has decreased by INR 9,310 crores, 23.8%, that is from profit after tax INR 39,077 crores in 9 months FY '23 to INR 29,767 crores in 9 months FY '24. The decrease in net profit during Q3 FY '24 and 9th month FY '24 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 '24 and 9 month FY '24 has decreased by INR 3,721 crores, that is 9.7% and by INR 15,408 crores, that is 13% as against the corresponding quarter and 9 months of previous year. The billing that is net of VAT or CST for the crude oil during the third quarter of the current fiscal was at USD 81.59 per barrel as against USD 87.13 per barrel in the same period of last year. That is a decrease of USD 5.54 per barrel. The exchange rate of rupee versus dollar stood at INR 83.27 vis-a-vis INR 82.20. Thus, realization for crude in rupee terms stood at INR 6,794 per barrel in Q3 FY '24 vis-a-vis INR 7,162 per barrel in Q3 FY '23. That is a decrease of INR 368 per barrel, that is 5.1% in INR terms.

Similarly, gross billing for crude during the first 9 months of the current fiscal was at USD 80.92 per barrel as against USD 96.99 per barrel in the same period of last year. That is a decrease of USD 16.07 per barrel. The exchange rate of rupee versus dollar stood at INR 82.71 vis-a-vis INR 79.77. Thus, realization for crude in rupee terms stood at INR 6,693 per barrel in 9 months FY '24 vis-a-vis INR 7,737 per barrel in 9 months FY '23, which amounted to a decrease of INR 1,044 per barrel, that is 13.5% in INR terms.

The expenditure on the statutory levies that is royalties and excise duty have decreased during Q3 FY '24 by INR 1,625 crores, 14.6%. And in 9 months FY '24 by INR 8,629 crores, that is 23.7% in comparison with the period of previous years. This decrease in the statutory levies is attributable mainly to decrease in sales price of crude oil and levy on 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 the 1st of July 2023, which amounted to INR 9,435 crores in 9 months FY '23 and INR 6,710 crores during 9 months FY '24. There is an increase of INR 721 crores in the exploration cost written off in Q3 FY '24, that is from INR 1,607 crores in Q3 FY '23 to INR 2,328 crores in quarter 3 FY '24.

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 crores that is 1.7% from INR 6,275 crores in Q3 FY '23 to INR 6,380 crores in Q3 FY '24.

Similarly, the operating expenditure in 9 months FY '24 has also increased by INR 1,524 crores, that is 9% from INR 16,935 crores in 9 months FY '23 to INR 18,459 crores in 9 months FY '24. The increase is mainly on account of the increase in contractual payment by INR 101 crores mainly on KG 98/2. Other expenses to INR 356 crores; transport expenses INR 61 crores; power and fuel by INR 79 crores, mainly at western offshore assets, repairs and maintenance, INR 323 crores; and water injection by INR 227 crores, mainly at Western Offshore due to increase in activities.

DD&I cost for Q3 FY '24 and 9-month FY '24 stood at INR 5,078 crores and INR 14,785 crores, respectively, as against INR 4,855 crores and INR 11,959 crores, respectively, during the corresponding period of previous year. The depreciation for 9 months FY '24 has increased mainly and Eastern Offshore 98/2 by INR 966 crores due to depreciation on ROU asset of FPSO.

Similarly, the impairment for 9 months FY '24 has increased due to reversal of impairment amounting to INR 2,129 crores 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 crores during the third quarter of FY '24 as against INR 11,665 crores during third quarter of FY '23, that is a decrease of INR 917 crores, 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 crores during 9 months FY '24 as against INR 27,076 crores during 9 months FY '23, that is an increase of INR 17,609 crores, 65%. This increase in profit can be mainly attributed to our subsidiary, HPCL, MRPL and OVL.

Board has approved a 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 crores. This is in addition to a payout of INR 7,234 crores first interim dividend of INR 5.75 per share, 115% 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 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 '24, '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 third quarter results for the financial year 2023, '24. We'll be very happy to take questions from you. We would like -- we would request you to restrict your questions -- queries on financial results only. Thank you.

[Operator]

[Operator Instructions] First question comes from Varatharajan Sivasankaran from Antique Stockbroking Limited.

[Varatharajan Sivasankaran, analyst]

So you mentioned about the production issue. If you can elaborate a little more on that. So our understanding is that KG basin obviously is contributing to the oil increase this time around and will contribute to the gas increase next year. But subsequently, effectively in terms of compensating for the decline in production in the other fields, what would be the situation in, say, FY '26 or '27 with regard to the development in the existing new reserves which you have found over the last few years as well as [indiscernible]. So what is the kind of indication we can get in terms of a sustainable production curve both on oil and gas?

[Manish Patil, executive]

Varatharajan, just one second. Okay. [Foreign Language] with respect to your question about the future growth projections, with the start of the [indiscernible] KG 98/2 project and the upcoming programs, and -- we say that we will be ending this year on our similar numbers as we were having in the FY '23 or slightly better than that. But however, going forward, we hope to have an increase by around 15% in the next 3 years by '26, '27.

And we have got a number of projects, which are lined up. There was something around 22 development/the infrastructure project with a CapEx outlay of around INR 60,000 crores. And those projects will also contribute to our growth trajectory. And secondly, as you know that we have got the old matured field, where we have got around 6% to 7% decline, so we are making the consistent efforts to maintain those productions and to reverse this declining trend.

We have given our focus on a 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 rig, the vessels or the helicopters and the induction of the state-of-the-art technology in the drilling rigs. So these are a few measures which we are taking up on an aggressive basis to address the decline from the old matured field. And secondly, we have got a number of development projects, which are lined up, which will be contributing towards our growth trajectory.

[Varatharajan Sivasankaran, analyst]

And my second question was on the 20% premium to the incremental gas production, which is of course proposed. I understand it has 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 be some visibility as to how it can potentially increase over the next 2 to 3 years for gas?

[Unknown Executive]

Currently, as per the definition for 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. Presently, during this year, FY '23, '24, it is contributing something around 3% to 4% of our current gas production. And moving forward, in the next 3 years, we hope that, it is a contribution from this new -- the gas -- towards the premium pricing, will be in the tune of around 20%.

[Operator]

Next question comes from Amit Rustagi from UBS Securities.

[Amit Rustagi, analyst]

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&A expense as well? So if you can help us understanding these aspects.

[Unknown Executive]

As you are aware, the total CapEx that we had planned for KG 98/2 around 5 billion. And the substantial part of which we have already spent, so around 28,000 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 costs, we are comfortably placed as far as KG 98/2 is concerned. Coming to your second question was with respect to...

[Amit Rustagi, analyst]

Cost of production and...

[Unknown Executive]

Cost of production -- see this cost of production, as you know, is basically the offshore 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 depending totally on the quantum of production. So considering that the current production that we are expecting from that, 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.

[Amit Rustagi, analyst]

Can you give us the 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 ourselves?

[Unknown Executive]

Yes. FPSO, the day rate is currently including GST INR 7,18,000, 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 core operations. The normal typical E&P industry costs, which we incur for producing. So those would -- 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 -- we are expecting, as earlier, Mr. Pavan was saying that the first half of next year summer, maybe June, July. So yes -- so based on that, the cost will crystallize. But, yes, the substantial part of the cost for OVL 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.

[Unknown Executive]

So I think the cost -- '25, '26 when we will be having the full scale production for the...

[Amit Rustagi, analyst]

Yes. How -- like how you're going to appropriate the $5 billion cost over how many years, basically?

[Unknown Executive]

Yes, normally, like the cost -- the CapEx cost that we allocate us through by way of depletion as well as the cost pertaining to FPSO is concerned, it's like in days of 116 on the base of the lease. So we have already started booking the depreciation and -- depreciation part through the lease -- the lease parts. So you might have seen that there's some substantial increase in the depreciation in the current quarter as well due to the lease bookings which we 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. And the facilities that we are going to install that would be on the pace of the reserve there and reserve the production ratio. Normally, on an average, around 10% is a result to production ratio. So 10% annual, the expenditure that we incur on the CapEx is by way of depletion.

[Amit Rustagi, analyst]

Okay. 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 renegotiated over the next 1 year, if you can give us some color on that?

[Unknown Executive]

See, relatively, we have a longer contract periods, normally in the range of 3 years. So the total rig that you're talking about 40 is distributed over some of the costs, which we had -- the rates which we 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 rig cost is concerned, whatever cost that is incurring -- is increasing on the base of the current contract rate. It's compensated by the contracts, which we are already entered in the previous year. We don't have any system of renegotiating the rate assets. Normally, what we do is we enter into a new contract once the early contracts expires. But yes, if there are opportunities where we can extend the current contract at a cheaper rate, that also we look into.

[Amit Rustagi, analyst]

But what I'm trying to ask is that is there any increase in cost because of renegotiation in the last 1 year? Because when you entered into contracts in 2021, they were substantially at the 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 contract?

[Unknown Executive]

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, and that is in the range of around -- just one sec. Yes, currently, the rates that we are getting on the new jack-up rigs that we are hiring is around -- in the range of $70,000 to $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 the market, but we are expecting that based on the projections, the rates could cooldown in future.

[Operator]

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

[Probal Sen, analyst]

Just I had one question which the respect to the exploratory well write-offs. The directors are 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 on this so does -- do these unsuccessful wells impact our assessment of reserve additions from these projects?

[Unknown Executive]

Not exactly. Actually unsuccessful wells are basically though we have discovered in the Western Offshore much in the past, we keep continuing to go for further exploration there. So basically, as per the policy like wealth, which we take up only for the purpose of investigations, like expandable wells that we charge of irrespective of whether we have some find or not. You must have seen that recently, we have had some finds in Mahanadi. So the development of the field person does not have any relation as well as 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 that we are not going to use it any more like an expandable well. So that's the basis on which we write off. It has nothing to do with the reserve that we accrete from the field. The reserves are totally based on the findings and further investigation by the exploration group.

[Probal Sen, analyst]

So our assessment of whatever growth we assume or we have built into our MOUs or projections, they remain unchanged as of now from these two projects, right?

[Unknown Executive]

Yes, yes.

[Probal Sen, analyst]

Okay. Sir, the second question is with respect to the projections. You did mention that you are aiming still to end the year at roughly flat oil production and -- which would be somewhere around 16.9 million tonnes, if I'm not mistaken, that was the run rate in FY '23. I wanted to understand for FY '25, what kind of exit rate should we actually be building realistically, assuming that oil production would be ramping up steadily from KG and some element of around 6 months of gas production should also be there so -- against the 16.9 million tonnes of oil and about, I think, 15.3 what we see and that we should do in gas this year, what is the exit rate we should build in for FY '25, if you can give any sense on that?

[Unknown Executive]

In the FY '24, as you may be knowing that earlier years -- as you know that in the earlier years, we were facing a decline rate to a tune of around 4% to 5%. However, last year, we were able to manage it with around 0.5% decline. This year will be above that. We'll be maintaining that numbers of the last year or slightly above that. .

And now moving forward with this 98/2 -- because the FY '24, '25, we will be getting the partial production so we'll be getting the peak production for the partial year. So in FY '24, FY '25, we hope to increase our current production by around 5% to 6% and we'll be experience -- getting the full plateau production from the 98/2 in FY '26.

[Probal Sen, analyst]

So the 15% increase that we are talking about over the next 3 years essentially can be divided up into 5% to 6% increase pretty much every year that we expect over the next 3 years, correct?

[Unknown Executive]

That's right. In FY '27, we're expecting slightly higher increase because by that time, we will be getting another project of Daman upside. From there also, we expect around 4 million cubic meter gas per day, equivalent to around 1.5 this year. So it will be 98/2 and Daman upside, this is the 2 major projects, which will be contributing towards around [ 40%, 15% ] production increase by FY '27.

[Probal Sen, analyst]

Apologize, sir, I did not give the name of the other asset. Other than KG-98/2, what was the other asset?

[Unknown Executive]

That's the Daman upside project...

[Unknown Executive]

That's on the Western Offshore.

[Probal Sen, analyst]

Daman upside? Okay. Sir, last question, if I may squeeze in. What is the kind of plateau period once the asset hits peak production of 10 MMSCMD and let's say somewhere around 40,000 barrels of oil produce on KG. What is the kind of plateau period that we are expecting for this production to sustain?

[Unknown Executive]

We say the plateau of about 2 years.

[Probal Sen, analyst]

Plateau as of 2 years and then a steady decline thereafter, assuming other interventions happening...

[Unknown Executive]

Other project -- other expandable wells will be coming up with a cluster 1, will be adding up in FY '28 so that will make up for the -- predecline.

[Operator]

Next question comes from my Mayank Maheshwari Morgan Stanley.

[Mayank Maheshwari, analyst]

Two questions from my end. First was more related to capital allocation. Can you just talk a bit about 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 were that kind of panning out in Russia, Venezuela or Sudan.

[Unknown Executive]

So I think, first, OVL would like to answer your question. After that, the first question will be answered.

[Unknown Executive]

Yes, regarding OVL, you have asked actually the position regarding Russia and 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 in hold up in Russia. However, we are at advanced stage of trying to pursue with the -- to accept the abandonment obligation upon OVL for getting back out 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 -- close this transaction of making the abandonment -- meeting the abandonment obligation. Regarding Venezuela, you are aware that the sanctions have been listed -- lifted and they will remain open until 18th of April '24. And we have received kind of proposals from the PDVSA, which are under negotiations.

And we are also exploring the banking root and trying to open up the bank accounts for easing of the funds 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 barrels from Venezuela for the dividend -- outstanding dividends and we hope to actually secure those rights to receive with balance. Regarding other projects also, the outlook is positive. We are -- the other projects also the outlook is positive, and we hope to gain positive positions in those projects also.

[Unknown Executive]

Mayank, now I think the first question will be answered by our CFO, sir.

[Manish Patil, executive]

Yes, your question was with respect to the dividend and the capital allocation, you know that we have been a consistent dividend paying company. Over the last few years, we have been paying around 40%. So current year also, if you might have seen that we have already paid 9.75. It is almost 41% in this 9-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 far as the capital allocation is concerned, given the current price and that we have a comfortable price even after considering SAED. And as earlier, we were saying that on the additional gas, we are going to get a substantial higher price of almost 9 to 10 per MMBTU. So with this, we expect that 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 crores annually for our normal E&P operation.

So apart from that, the dividend that we are paying so -- over and above that, we have some surplus cash available, which we, going forward, plan to 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, green energy initiatives that we are taking. So with all those things, we would be slowly moving ahead, utilizing our future cash flows in those areas as well for the CapEx.

[Mayank Maheshwari, analyst]

So sir, can you just give us a guidance on the CapEx for the next couple of years for fiscal '25 and maybe beyond of how much you're thinking about allocating each year but is that the same INR 30,000 crores that we can assume now going forward?

[Unknown Executive]

So Mayank, what you can expect, it would rise in the current year in the range of INR 33,000 crores and next year it would be somewhere in the range of INR 33,000 crores to INR 35,000 crores. This, I'm talking of the standalone CapEx -- yes, standalone CapEx of ONGC.

[Unknown Executive]

Other than the integration project, standalone CapEx.

[Mayank Maheshwari, analyst]

Okay. And sir, can you just give us 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 we will have, roughly a big picture sense?

[Manish Patil, executive]

It would be difficult for us to talk about the CapEx plan for the subsidiaries currently at this juncture. But as we said that as far as ONGC is concerned, the conventional investment of around -- normally 30,000. So 32, 33 in the next 2 years as Prakash was saying now as far as ONGC is concerned, but the allocation for other investments, there are like -- the OVL, we are planning to -- I mean, OVL...

[Unknown Executive]

OVL -- before this -- the FM situation in Mozambique, we were having a budget of INR 8,100 crores. After that, the 2-year budget was scaled down and current year is 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 to 5 years. And as far as renewables is concerned, we have already announced that we would be planning to spend around INR 1 lakh crores by 2030. So that plan is there, but that's a relatively longer-term plan so things are being worked out nitty gritty.

[Mayank Maheshwari, analyst]

Sir, 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?

[Unknown Executive]

Restructuring of the operator organization, right?

[Mayank Maheshwari, analyst]

That's correct, Mozambique, yes.

[Unknown Executive]

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 LNG project with a very high level of CapEx, which was actually announced at $15.421 billion in June 2019, and this project development has been secured to project finance. So the project finance was agreed for $16 million. Now to have that kind of debt on the partners or the partners books, asset -- HoldCo model, AssetCo model has been evolved under which the assets of the project and debt will remain in the AssetCo and will not get transferred to their respective partners' books.

So that actually is the purpose for which the AssetCo model has been created. Right now, the project is -- like Indian Consortium has 30% participation in the project, of which OVL holds 16% and 10% OVRL so OVRL has assets of 10% and our associate BREML has assets of 6%. These will get transferred to the AssetCo model company, both LNG. And the debt will also remain in that company only.

[Operator]

Next question comes from Sabri Hazarika from Emkay Global.

[Sabri Hazarika, analyst]

Sir, two questions. First one is, so what is the current oil production in KG 98/2?

[Unknown Executive]

Currently, we are producing something about 12,000 barrels per day.

[Sabri Hazarika, analyst]

12,000 barrels?

[Unknown Executive]

Gas is around 1.75 million cubic meters per day.

[Sabri Hazarika, analyst]

Gas is around?

[Unknown Executive]

1.75.

[Sabri Hazarika, analyst]

1.7 MMSCMD is gas and 12,000 barrels per day is oil?

[Unknown Executive]

Right.

[Unknown Analyst]

And you were selling it also or is it -- I mean, you were like storing it right now, just oil 12,000 barrels per day?

[Unknown Executive]

Oil, we have got a tie up -- we are in the process of making a tie up with MRPL for the first load of [indiscernible].

[Sabri Hazarika, analyst]

Okay. So does it mean that -- I mean, you have something like [ 4,50,000 ] barrels per day of oil. So this 12,000 will add into there, right? I mean it will be reflected in Q4 numbers what -- whenever they come, right?

[Unknown Executive]

Q4 numbers will be reflecting this 12,000 barrels.

[Sabri Hazarika, analyst]

Okay, sir. And secondly, what was your 9 months cumulative 98/2 gas production?

[Unknown Executive]

98/2 cumulative...

[Sabri Hazarika, analyst]

Gas production for 9 months?

[Unknown Executive]

Okay. Sabri, we'll come back to you...

[Sabri Hazarika, analyst]

Yes, yes. Okay. 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 net realization. But given the fact that we are almost like 1 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 '26 onwards, $0.25 is something which was given in the guidelines. But for oil, are you like requesting the government to look in this? So have you got any indication? Or do you expect that the windfall hurdle rate will be increased from $75 from FY '25 onwards?

[Unknown Executive]

Just one second. See, as far as SAED is concerned, it's 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, 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's not that costs are going to escalate very high. The OpEx numbers have been more or less steady as far as ONGC is concerned. So we don't expect that the cost would be substantially higher that way. So really, the price that we are currently getting is also a comfortable price for us.

[Sabri Hazarika, analyst]

Okay. So any guidance on the cost side, can you give? Because if I look at 9 months '23, so your total other expenditure was around INR 13,600 crores. So 9 months '24 has been like INR 16,000 crores. So it has actually increased. So FY '25, 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 the rig rates and all are like higher?

[Manish Patil, executive]

Yes. One major reason that you find that 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 INR 9,000 crores, we took to previous years and INR 3,000 crores of last year. So that -- now the expenditure is around, say, INR 2,300 crores to INR 2,400 crores annually, that regularly now we have decided to take a hit, though we have been pursuing the government, and we are very hopeful that the 9-bench 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 for development purpose only. Like if we say for example, in the offshore, we spent -- we have decided to spend money on water injection, which will result into -- we are expecting that from the existing matured field, we'll have more production. So those kind of expenditure only.

It is not like expenditure, which are in the nature of infructuous 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 cooldown.

[Sabri Hazarika, analyst]

Okay, sir. And just one small question. So SAED is being imposed on 98/2 crude also?

[Unknown Executive]

Right now, we are getting it reviewed this -- applicability of SAED and other taxes that is under review. Right now, the preliminary review is that that it may not be applicable, but it is not final. It is under review.

[Sabri Hazarika, analyst]

Okay. So right now, the rough cut view is that, say, it may not be imposed at all on 98/2 crude, that is 12,000 barrels per day? Okay.

[Operator]

[Operator Instructions] Next question comes from Gagan Dixit from Elara Capital.

[Gagan Dixit, analyst]

Sir, there is the news that ONGC planning to drill a well in the Andaman basin [indiscernible] it is a potential of like 180 million tonnes or 1 billion barrels or something. So am I assuming this is something that's similar resource that you are targeting from the exploratory wells from such basin?

[Unknown Executive]

It's an exploratory well under the [indiscernible], what we have got the block there and we are taking our first exploratory well in this calendar year. And the resource that is able to -- resource estimation from this well, we will be able to communicate later on.

[Gagan Dixit, analyst]

Okay. Because I thought that might be you have some idea out based on your 2D, 3D surveys. So that's something minimum target that you are targeting from time.

[Unknown Executive]

So it's exploratory well -- so let's hope and wait and watch that we get the good result from this well.

[Gagan Dixit, analyst]

My second question is that there's also the news that ONGC is in talks with restarting its production in the Libya that we exited 13 years back. So any status of it, if you can just point it out, sir.

[Unknown Executive]

ONGC Videsh does not have any production asset in Libya so we don't think that we have any option produced from the Libya.

[Operator]

Next question comes from Vikash Jain from CLSA.

[Vikash Jain, analyst]

Firstly, sir, your OpEx is very, very high for this particular month, even -- this particular 9 \-month even after we adjust for your GST on royalty. It is -- for this particular quarter, it's at about this -- 9 months, it's 25% up Y-o-Y, which comes on top of 11% increase that we saw in FY '23 full year. And this is even before fourth quarter, which typically has been a pretty quarter where you 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 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, fourth quarter, will it again see a jump, which typically it has seen in the last 4, 5 years?

[Unknown Executive]

Yes. Just a second, Vikash ji. Yes, you were talking about the increase in OpEx over the 9 months period, right?

[Vikash Jain, analyst]

That's correct.

[Unknown Executive]

Basically, if we have seen that 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 9-month is concerned, the increase is mainly because during the COVID period, we had -- the operations were down, and then we had some damages happened, which happened in the -- 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, we have -- now we are focusing more on water injection, which is more like a development expenditure, though, we are booking that in the OpEx. So that's around INR 224 crores on water injection we are spending on the Western Offshore. So these are one-off expenditures, which are contributing. It's not that they are regular expenditure. In addition to that, on VAT amnesty scheme also, we have decided to go ahead with one case and -- where we are paying about INR 160 crores.

Apart from that, 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 base of the recommendation, we have decided to pay some amount. So most of the increase that has happened is in the nature of one-off expenditure. They are not a regular increase on the base of the production numbers. They are not directly variable with the production numbers.

[Vikash Jain, analyst]

Sorry. So when you say like water injection, that would not be one-off, right? I mean now you will account for it every quarter whenever that happens, right so...

[Unknown Executive]

Yes, once we pick up a field, then we decided to go -- see water injection is not something which we incur on the base of the production every year. Certain fields where we have -- where we feel that it needs 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.

[Vikash Jain, analyst]

Okay. No sir, the last part that you mentioned around some provisions that you've thought of accounting that has all increased 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?

[Unknown Executive]

No, not in the nature of ongoing things which we decided earlier. Like we were having certain dispute with respect to completion of some of our exploratory schemes, which we could not -- like either for reasons beyond our control, things got delayed so that 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 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 onetime solution to -- mutually agreeable solution, which we decided to go for. So they are not in the nature of recurring expenditure. This -- the number which I told is that with respect to this LD for 9 blocks was INR 136 crores, and the VAT amnesty scheme was around INR 180 crores, which we have booked in the current.

[Vikash Jain, analyst]

And sir -- I mean, see, what I'm worried about is if you see a simple lifting cost has gone up from -- for 9 months versus $10 is about $12 or so, okay. And if we also look at our exploration write-offs, et cetera. And this is even before the fourth quarter. Fourth quarter typically, over the last 5 years has been -- 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 fourth quarter? Because even on an ongoing basis, OpEx has been higher through this 9-month or that's something -- that -- this is the new OpEx number we should be working with?

[Unknown Executive]

Yes. 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're doing 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 explanatory write-off is concerned, in this particular quarter, we have taken a hit of about one well in Mahanadi, where -- which is an expandable well, that's almost INR 500 crores for one well.

So these are not the expenditure that we expect that will happen regularly. This kind of industry such things do happen. One-off expenditures 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 were asking me that we are not expecting to be high.

[Vikash Jain, analyst]

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 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?

[Unknown Executive]

Yes, yes, correct. 16%.

[Operator]

Next question comes from [indiscernible].

[Unknown Analyst]

Sir, in terms of the new projects that we have lined up, besides KG Basin, can you just give some color on next 3 years or so what are we expecting in terms of incremental production from these projects? And what is the CapEx spend related to them?

[Unknown Executive]

Incremental production from KG 98/2 or the total projects what we are planning in the...

[Unknown Analyst]

Outside of, I mean, KG 98, the incremental projects that are coming online next 2 to 3 years, so what is the production expected from them? And what is the CapEx that we need to spend for.

[Unknown Executive]

The total CapEx, as I earlier said, that it is in -- the ongoing projects [indiscernible] INR 60,000 crores, which will be materializing in the next 2 to 3 years. And they will be having a life cycle gain of around 80 million tonnes of oil equivalent. And moving forward, in the next 3 years, we will be expecting something around 5 million tonnes of oil and oil equivalent from these new projects, of which the major chunk will be coming from 98/2 to the tune of from 4 MMTOE and 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 is again contributing around 0.5 MMTOE. And we have got a few other projects of development of contract areas under the DSF-2, blocks are there. Then we have got [indiscernible] Phase 5, which is upcoming. So Daman upside, I already told you. And there are various -- fewer projects which are upcoming in the onshore project, which will be again adding up to something around 0.3 to 0.4 MMTOE. So these are the projects which we are looking forward to for completion in the next 3 years.

[Unknown Analyst]

Got it, sir. Sir, one question on the CapEx, this INR 30,000 crores to INR 35,000 crores of run rate that we are mentioning, can you just give some color on -- you did mention that now in terms of new projects, this INR 60,000 crores spend probably over a 3-year time frame. So what is the level of maintenance exploration in new project spend, if you can give a rough breakup in the INR 30,000 crores, INR 35,000 crores for the next 2, 3 years?

[Unknown Executive]

[indiscernible] whatever our CapEx outlays there, our development projects contributed something around 60% of our total CapEx outlay in the development drilling as well as the capital project, what we are taking on.

[Unknown Executive]

Yes. So to be -- specifically, if you see, survey would be around 11%, okay? And exploratory drilling would be somewhere in the range of 22%, and development drilling would be in the range of 25% to 27%. And the balance would be on infrastructure and other capital, which would be around 37%.

[Unknown Analyst]

And sir, also, any update on the OPaL equity infusion?

[Unknown Executive]

See, we have already drawn up a plan of infusing around INR 19,000 crores 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.

[Unknown Analyst]

And the CapEx number that we are saying INR 30,000 crores, INR 35,000 crores is at stand-alone level, it does not include any equity infusion?

[Unknown Executive]

That includes a minimum equity, not the OPaL what sir was talking about.

[Operator]

Next question comes from Manish Ostwal from Nirmal Bang.

There is no response sir. There are no further questions. Now I hand over the floor to Mr. K.C. Ramesh, CFO, for closing comments.

[K. C. Ramesh, executive]

Yes. 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 remarks by our Director of Finance, we are expecting that going forward in this particular quarter itself, with the KG 98/2 commencing production, the production numbers that we have for last quarter of the last year where we would be able to maintain in the last quarter of current year though for the first 3 quarters, it has -- it's slightly on the lower side.

But we are hoping that for a better outlook and -- we are very confident about the future that whatever initiative that we are taking in terms of foraying into other areas apart from the conventional oil industry, they would be paying us good dividends. The investments have been well planned -- well thought out basis. So with this, the price outlook for gas is also pretty -- I mean, it's good that we have already got -- based on the [indiscernible] committee, we are expecting that the incremental production which is coming through gas would be fetching us almost $9 to $10 per MMBTU.

So gas would be adding substantially to our top line and bottom line as well. And with our persistent -- we will be trying to keep taking up with the government with respect to the SAED applicability and hopefully, if we can get something positive on that as well. On the oil front also, we'll be doing comfortably well. So 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 in future from 98/2 adding and the Daman upside, which Mr. Pavan Aggarwal was saying earlier, that's 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 -- 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.

[Operator]

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