Oil India Limited (OIL) Earnings Call Transcript & Summary

Ladies and gentlemen, good day, and welcome to the Q3 FY '24 Earnings Conference Call of Oil India Limited, hosted by Antique Stock Broking. [Operator Instructions] Please note that this conference is being recorded. I now hand the conference over to Mr. Varatharajan Sivasankaran from Antique Stock Broking. Thank you, and over to you, sir.

Thank you, Michelle. Good morning, everyone. I would like to extend a very warm welcome to all the participants and the management of Oil India Limited. We have with us representing Oil India Shri Harish Madhav, Director Finance; Shri Pankaj Kumar Goswami, Director Operations; Dr. Manas Kumar Sharma, Director E&D; and Shri Sachidananda Maharana, CGM. I would like to hand over the floor to Mr. Harish Madhav for his initial comments and followed by a Q&A.

Thank you, Varatharajan. Good morning to all the participants. And we are very happy to reconnect once again after the Q3 results. The copies of the results and the detailed analysis, we have already shared with everyone also hosted on the stock exchanges yesterday itself. Hope all of you would have gone through that. We are available now for any further queries, details that the analysts may be requiring or they -- whatever. And for -- basically on the physicals part, we have both Director Exploration and Director Production of the company also available on the call. Before we can move into the question answers from the analysts, I would request my CGM Finance, Mr. Maharana, to give a brief of the results summary, and then we can switch over to the question answers.

Thank you. Good morning, dear friends. At the outset, I would like to thank [indiscernible] Antique Stock Broking Limited for organizing today's analyst call. I'm Sachidananda Maharana, CGM F&A Corporate Finance of the company. The company's financial results of Q3 FY '24 were published on February 13, 2024. I would briefly give some indication about the performance of the company in both physical and financial terms. Now coming to the standalone results and beginning with the production front, the company has continued to improve its crude oil production, which is higher by 6.07% in the quarter ended December 31, 2023 at 0.856 MMT vis-a-vis 0.807 MMT in the quarter ended December 31, 2022. Crude oil production for the 9 months ended December 31, 2023, has also increased by 5.68% to 2.511 MMT vis-a-vis 2.376 MMT for the 9 months ended December 31, 2022. Natural gas production during Q3 FY '24 increased by 1.99% over Q3 FY '23. Natural gas production for the 9 months ended December 31, 2023 is marginally lower by 0.96% at 2,377 MMSCM vis-a-vis 2,400 MMSCM for the 9 months ended December 31, 2022. On the financial side, average crude oil price realization for Q3 '23/'24 is USD 84.14 per barrel vis-a-vis USD 88.33 per barrel for Q3 of '22/'23, decreased by 4.74%. Average annual gas price for the 9 months ended December 31, '23 is USD 6.5 for MMBTU vis-a-vis USD 6.92 per MMBTU for the 9 months ended December 31, 2022. The turnover for 9 months ended December 31, 2023 has decreased by 7.04% to INR 16,373 crores compared to INR 17,613 crores in the 9 months ended December 31, 2022, which is mainly due to lower crude oil price realization of USD 82.89 per barrel in 9 months ended December 31, 2023 vis-a-vis USD 100.27 per barrel in the 9 months ended 31/12/2022. The EBITDA margin for the 9 months ended December 31, 2023 has increased to 47.28% vis-a-vis 44.96% in the 9 months ended December 31, 2022. The company has taken provision towards disputed service tax and GST on royalty, including interest amounting to INR 237 crores during the third quarter ended December 31, 2023, and total provision of INR 2,892.78 crores, including interest towards these disputed taxes till 9 months ended December 31, 2023. Profit after tax for the 9 months ended December 31, 2023 decreased to INR 3,523 crores vis-a-vis INR 5,022 crores for the corresponding period last year. The earnings per share for the 9-month period ended December 31, 2023 is INR 32.49 per share. Now I come to financial performance of Numaligarh Refinery Limited, our material subsidiary. The profit after tax of NRL during Q3 FY '24 is INR 858.72 crores vis-a-vis INR 799.14 crores during Q3 FY '23. And profit after tax for the 9 months ended December 31, '23 is INR 1,516.66 crores compared to INR 2,933.56 crores for the corresponding period last year. NRL's gross refining margin during Q3 FY '24 is USD 12.72 per barrel vis-a-vis USD 13.48 per barrel during Q3 FY '23 and gross refining margin for the 9 months ended December 31, '23 is USD 13.12 per barrel vis-a-vis USD 19.71 per barrel for the 9 months ended December 31, '22. NRL's EBITDA for Q3 FY '24 is INR 1,218.19 crores vis-a-vis INR 1,121.8 crores for the Q3 FY '23. While EBITDA for the 9 months ended December 31, '23 is INR 2,297 crores vis-a-vis INR 4,179 crore for the 9 months ended December 31, '22. Coming to the consolidated results of the group. Oil Group's turnover for the 9 months ended December 31, '23 was lower at INR 26,137.84 crores vis-a-vis INR 32,261.71 crores for the 9 months ended December 31, '22. And the group PAT for the 9 months ended December 31, '23 is also lower at INR 4,647.51 crores vis-a-vis INR 7,874.65 crores for the 9 months ended December 31, '22, which is mainly due to lower crude rate realization, turnaround maintenance of NRL and provision made towards service tax and GST on royalty, amounting to INR 2,892.78 crores. With this, my opening remarks on the performance is over, and we are now open to Q&A.

[Operator Instructions] The first question is from the line of Siddharth Chauhan from Batlivala & Karani Securities.

Congratulations on good set of numbers. Sir, I have 2 questions. One, we have been sustaining the 5% to 6% Y-on-Y oil production in the last few quarters. Is it through increased EOR, IOR activity? Or has production commenced from field like Baghjan field?

I'm P.K. Goswami, Director Operations. So this is not due to EOR or IOR activities. This is from our existing fields in Northeast mostly. And the -- this is basically due to new drilling activities in the old areas. . So we have drilled lots of new wells in the -- development wells in those areas. And at the same time, we have done some new -- introduced some new technologies for production from the old wells. So combining these 2 efforts, we have -- we are now getting -- not only we are maintaining a steady production from the old field. And at the same time, we are getting new production from the newer. So the ultimate result is that there is an increase in production of both oil and gas.

Sir, just a follow-up. Sir, when do we expect Baghjan field to come online? And what will be the incremental production if it comes?

Baghjan field is already online. So there is no hindrance in any area in Baghjan, so we have been producing from the Baghjan field, and there is substantial increase in gas production from that field. . Basically, it's targeted for gas production only. And as of now, as we speak today, we have been constructing 1 new field gas gathering station, which will be a gas-producing station at Baghjan. So we are targeting gas production of 5 BCM by next 2 years. So this gas will mostly come from Baghjan.

Okay. Understood, sir. And sir, second question on the Northeast gas grid. Sir, I understand it will be commissioned in 3 phases. So which phase is critical for Oil India to ramp up gas production?

All these 3 phases are important for us because as of now, as you have seen the gas production in the first quarter was very low because there were no offtakers for gas. Basically, it was due to the non-connectivity to the mainland India. . So once we get the connectivity to the mainland India, so this -- we will have opportunities to sell gas outside of this market. As of now, we have limited customers and some customers are seasonal, like the tea garden, where there is a seasonal demand. So that makes our gas production difficult at some times. So that is why the first quarter production was very low. But once the Northeast gas grid is connected, so we'll be having lots of opportunities to sell gas outside. So all the phases of gas grid is important. And at the same time, when we talk about the Indradhanush Gas Grid Limited, IGGL, that is working in Northeast. So IGGL is now almost ready, and we have now proposed 1 more line in IGGL, which will connect our field, directly it will come to the IGGL Mainland connection. So that is 1 line in plan now, so with that line available, we'll be able to produce more.

The next question is from the line of Probal Sen from ICICI Securities.

Two questions. One, with respect to the production growth, which you mentioned that as of now it's basically higher level of development drilling plus some recovery techniques from existing wells itself. Can we get some sort of phasing, if I look at the run rate for this year, we are likely to end somewhere around 3.2 million tonnes to 3.3 million tonnes of oil. Now going from this to essentially about 4 million tonnes, how should we actually build that? Will that be a sort of a gradual progression every year over the next 3 years? Will -- is there any specific field that when it comes to online will deliver that increase? Similarly, for gas, you did mention that it's the 1 new field that is under development at Baghjan. But is that going to almost entirely account for the 1.5 BCM increase that we are targeting?

Yes. This is Dr. M. K. Sharma, Director to Exploration & Development. Regarding the Baghjan field development, actually, we are having stack reservoirs, and we are simultaneously developing that field. And this has got a very high gas potential as well as subsequent oil together. . So Baghjan is actually on -- regularly on production, and we are producing a significantly high amount of gas and oil from that area. And looking at the coming up situation actually to reach the 4 million metric tonne, we are having a very well laid down plan and we're increasing -- or actually accelerated drilling and accelerated activity in the drilling fields of getting the -- improving the recovery is the plan, and it is in -- eventually in line with our plan. So we in -- next year -- this year, we are targeting to increase the drilling of wells by doubling the amount of wells and we are going close to that. And next year, it will be furthermore. It will be of the order of 45 to -- it will be the order of around 80 -- 75 to 80 wells next year. So with this increase in front, we are very confident that our production will increase and go close to 4 million tonne target.

Okay. And we maintain that, sir, the target will be met some time by FY '26, if I am not mistaken or '27, what's the sort of tentative time line to reach this target?

H. K. can you please take that question?

Probal, I think this will be -- '26 will be a very, very fair estimate because this year, production will be around 3.35 million tonnes, 3.4 million tonnes in that range. And our target for next year is to escalate it to around 3.8 million tonnes. So very next year '25, '26, separately if everything goes well as per the plan, we will be reaching around 4 million tonnes by '25, '26 or maybe more than 4 million tonnes.

Can I get a similar time line or granular target for gas as well?

Yes, yes gas 5 BCM also will be the same -- similar time lines.

If it is 5...

Maybe a little earlier also, after this I will give you a...

Yes, it will be earlier, yes.

Okay, even earlier than that. All right, all right. Sir, 1 last question, if I may, a housekeeping question. With respect to the other expenses. If I take out the INR 237 crores from the number reported in this quarter, that still leaves around -- basically around INR 930-odd crores of expenses. So barring this service and royalty provision is that the run rate we should be building on a quarterly basis for other expenses?

Other expenses, more or less, they continue at the current level. This -- even the taxation provision, GST and royalty, that also will continue almost at the similar level because the prices are -- crude prices are almost behaving -- moving in the normal range around $75 to $80, $85 per barrel. Gas prices is $6.5 is stable. So the royalty element will be similar and accordingly, GST on royalty also will be more or less similar. So it will be very fair to estimate that the current run rate of the other expenses or all the costs will remain as it is, except there is an element of exchange rate variation, which depends on the rupee/dollar exchange rate. So this has been very low this time because the variation was less, last year it was high. So except that, which is basically unpredictable, rest of the elements will continue more or less in the similar trend.

Sir, how much was the exploration write-off in this quarter? That's my last question.

It is INR 258 crores.

INR 258 crores. I'll come back if I have more questions.

The next question is from the line of Sabri Hazarika from Emkay Global.

And so I have a few questions. Firstly, sir, the entire increase in provisional -- the dry well write-off is basically this INR 258 crores. And this is on which asset?

No, this is the number of wells. Different, different wells will be there. Total provision and write-off on account of dry wells is around...

There is some provision on South Baghjan and Bogapani, Moran...

Basically, on our Northeast as well as this 1 well on this...

Mahanadi.

Mahanadi basin.

Okay. Okay. One well in Mahanadi basin also, right? Okay. And so this is like -- I mean, this will keep fluctuating, right? I mean, there's no particular trend because...

It still keep fluctuating depending on the drilling -- exploratory drilling that we do and the results of the wells that happen. So this certainly will keep on fluctuating.

Okay. And what was this DD&A increase of 18%. So anything specific on that? The depletion has gone up significantly. Any reserve-related changes or something like that, sir?

It is because of the -- because of the change in the product and reserve ratio.

Okay. So has it gone down?

Yes.

Okay. So this is like the current run rate we have to take out there. I mean pretty fluctuating, I think the depletion part also. So just wondering if...

See, depletion happens -- the way it will be because the reserve estimation is done only at the year-end while the production growth is coming quarter-to-quarter. . The new reserves estimation will be only at the year-end. So for the current year, yes, it will continue. For Q4, it may change again because before the Q4 results we will have the new reserve estimates.

Okay. It's taken on a financial year basis, right, not on a calendar year basis?

Yes, reserves estimates is annually done, not quarterly.

Okay. And sir, a couple of more questions. In terms of like this IGGL, you have said that it will get -- it is almost ready. So when is the commercial commissioning expected? And when is this new line that you have proposed going to commission?

We have to check back.

IGGL commission, we'll have to check back. Sabri, we don't have readily available. But I think first phase is getting commissioned within this financial year or early next financial year.

In this financial year they are saying, so [indiscernible] we have to check back.

Okay. Fine, sir. And also this NRL, there has been an increase in profitability Q-o-Q despite lowering of GRMs. So anything specific there or is there any kind of like write-backs, anything of that sort?

No. NRL, basically, the performance of the refinery in Q3 has been very good, and they have operated at about 114% of the installed capacity. So that is contributing.

Okay, sir. And sir, have they given any interim dividends?

NRL has declared yesterday, yes. In their Board meeting day before they have declared interim dividend.

Okay. And how much would that be, if you could disclose? I mean, if it's permittable to disclose?

Allow us not to disclose because this is a closely held company and it's not relevant possibly for the investors.

Right, sir. And sir, last question...

Can I say that in our next quarter results, you will come to know how much dividends we have got from NRL. So that will be reflected.

Okay, sir. And sir, last question. This Mozambique debt I think -- I mean it's on your stand-alone books as external commercial borrowing. So is there a thought process to like transfer it to some new holding company or something? I think ONGC has come up with some new holding companies for like taking that debt in those books. But are you like restricted by some ECB covenants and something that you have to keep it in the stand-alone debt itself?

No. Mozambique, it's not only ONGC, it's basically the complete asset is undergoing a -- has undergone a restructuring with the one asset company, one holding company structure, that borrowed SPV, SPV selling and sellers. So the complete structure has undergone a change for the Mozambique asset. So we are also going to -- going according to that. And that structure is applicable to us also. ONGC might have declared all those things because BREML is the subsidiary company of ONGC. So whatever is applicable to ONGC for Mozambique asset is applicable to us also.

Right. So incremental CapEx and funding will happen in that asset management company, but your initial ECB will remain as it is. Is that right?

So everything is moving to the new structure.

Even -- so stand-alone debt will go down, right, because of this restructuring?

No. Actually, the ECB that has been taken by Oil India it will not be impacted because this is what we are investing in BREML. So till date, we have invested almost close to $1,500 million that will remain in Oil India's book as borrowing. What DF sir was telling is that the structuring below BREML level, that has changed that has so changed -- that is undergoing a change.

Okay. Okay. Got it. I mean any kind of future CapEx will be taken by that AMC rather than...

Yes. The borrowing at the project level will be done by the borrower SPE, and that will be -- on lending will be done to the assetco for the execution of the project.

The next question is from the line of Mayank Maitri (sic ) [ Mayank Maheshwari ] from Morgan Stanley.

A couple of questions from my end. One was in terms of dividends, sir, there has been no interim dividend this quarter. Any specific reason on what are you thinking on the overall dividend and capital allocation policy from Oil India?

See dividend, we follow the government guidelines. You must be aware there are DPE guidelines on dividend distribution, DIPAM guidelines, sorry. Basically, it is 5% of the net worth or 30% of the profit after tax, whichever is higher. So we follow that and 1 interim dividend, we have already declared. And as of today, decision has not been taken. Yesterday's Board meeting, no decision was taken. But if any call is taken, we have to discuss with the government also before the end of the financial year. And we will see if something is required, we may or may not declare the dividend. Otherwise, everything will go as a final dividend. But for the full year, that guidelines will be followed.

Okay. And sir, can you just talk us through in terms of the update around NRL upgrade as well as how much of the CapEx has been spent there? And what are your plans on Oil India level CapEx and exploration for fiscal '25?

Let me first cover the Oil India part. Oil India, fiscal '25 CapEx plan is close to INR 6,000 crores. And out of this, of course, the exploration. This includes about INR 1,000 crores equity investment in NRL as well. You may be knowing that NRL has -- we have to contribute about INR 2,100 crores in NRL, right issue was made by NRL last year and 50% of the total call we have already contributed. And another INR 1,100 crores will go -- received next year. So total about INR 6,000 crores is the CapEx plan of Oil India for next year. For NRL, the [ fixed ] CapEx is INR 28,000 crores total. Total actual commitment and investment till date is about INR 15,000 crores out of the INR 28,000 crores total refinery cost.

Okay. And sir, what has been the progress in terms of the completion of the refinery upgrade?

The refinery is about 50%, 55%, 60% is the completion.

The next question is from the line of Kirtan Mehta from BOB Capital Markets.

You mentioned about the sort of the Indradhanush Gas Grid is coming to the completion with Phase 1 likely to complete by either end of year or early next financial year. So for marketing our gas outside Northeast, are we going to do it ourselves? And have we started talking to customers for additional sale of gas outside Northeast?

No. Actually, the -- with the present gas production, we are not yet covering the Northeast -- entire Northeast also. So as of now, our target will be covering the Northeast because there are lots of other factories in the Upper Assam side which are not being covered by our gas. Our gas is up to Numaligarh. So we are selling gas up to Numaligarh point only. Beyond Numaligarh lots of gas customers are there, we are initially targeting all those gas customers. Then we'll proceed to the next part.

So with Phase 1, which are the additional areas where we can sell this gas into?

Up to Guwahati.

Up to Guwahati. And have we started discussing with the customers up to Guwahati in that sense to sell the additional volume?

Additional volume is not yet finalized. This is under discussion now.

Discussion with the customers has also started or not, that was basically the question...

Yes, yes, discussion with the customers has started. Actually our main customer, 1 customer will be Purba Bharati Gas Grid Limited, who is giving down CNG and PNG connections in Guwahati city. So they have already started there as well. And lots of other factories are there, cement factories and other units are there. So we are looking for some tea gardens also in those areas. So these are the new probable customers for us.

And what could be the incremental demand from this particular area, which we can target during Phase 1?

As I said, the number is not yet finalized. So our production target is by next year, 3.5 million tonnes. So definitely, we're having sufficient customers for that.

Sure, sir. Second question was about the exploration CapEx that we are targeting for Q4 as well as FY '25, and which are the key wells that we will be targeting within this exploration CapEx?

Actually, our exploration is -- at present -- as you are aware, our exploration is having both actually all the exploration OALP regimes as well as the existing PMLs. So combining that, we are having a strategy that has been getting implemented. We call it near-field exploration, where the area in and around our PML area is taken into consideration and -- inside the area with different explosion opportunities. Then at the same time, our OALP explosions are also kicking off for drilling phase. So simultaneously going on, we are drilling in Mahanadi. We are also drilling in Northeast. We are also drilling in Rajasthan. And at the same time, our near field exploration that we have categorized is continuing. So we look forward for an extensive explosion in coming days.

Understood, sir. In terms of the chunky exploration write-offs that we see. Does it arise from both the areas from our near-field drilling in the Mahanadi and Rajasthan drilling or it's more attributable to the drilling that we're undertaking the new exploration areas like Mahanadi and Rajasthan?

See this -- any write-off will be attributable to any exploration drilling, whether we do in the current nomination block, what you call a near field exploration or the new OALP, NELP block. This is coming from everywhere. And I think the distribution of wells also exploratory versus more or less -- currently, it is more in the near fields and going forward, it will be more in the new exploration NELP or the OALP blocks, rather OALP blocks.

Right, sir. And just 1 final question from the CapEx perspective, we indicated the INR 6,000 crores for FY '25 with exploration at around INR 1,000 crores. And I understood NRL at INR 1,100 crores for the next year. What are the other components of the CapEx plan...?

The INR 1,100 crores is for NRL. And then exploration, development, survey all put together, it will be close to INR 3,000 crores, 50% of expenditure actually goes into the exploration and development. What INR 1,000 crore exploration you are talking about is only the drilling part. And it can -- in fact, if we start the offshore drilling, this expenditure may further increase in the RE states. And when we revised the CapEx target midterm review we have -- happened. As of now, whatever we have planned, depending on the wells plan. So total exploration expenditure will be anywhere between 45% to 50% of the total CapEx target. INR 1,110 crores NRL investment and balance in various capital equipments and maybe some in Mozambique project if we have to invest.

This INR 6,000 crores does not include as of now, the -- any expenditure on Mozambique. So if that comes, would that be extra during FY '25?

So partly, we -- about INR 250 crores, INR 300 crores, we would have certainly included, which is depending on the expected cost that may be coming from Mozambique. Some expenditure already the investment has been factored in.

[Operator Instructions] The next question is from the line of Gagan Dixit from Elara Capital.

Sir, when I see last year this presentation that mentioned your domestic 1P reserves are around 780 million barrels and your annual report says your developed reserves in the domestic market is around 200 million barrels oil equivalent that's the number. So my sense is around 25% of your reserves are the developed reserves. So whatever the production growth you are targeting for the next 2 years, can I safely assume that this is mostly the upgradation of the undeveloped to your developed reserves of that same market [ 780 million ] barrel 1P reserves, that would be the case, sir?

Yes, you are right. So basically, that is one agenda. But at the same time, we are also carrying out explorations for newer plays, which are getting added. So there will be a section but significantly it will be from the upgradation of the reserves from the 1 category to the higher category.

Okay, sir. So it means that technically, you can increase further production also if you want to further develop those reserves because 20% is a very low number for the developed...

Yes, you are very right in the production, we are already having a target of reaching 4 million tonne by '26. But then gas, as you are aware, it's market-driven and connectivity to the mainland is the main constraint. So we are having significant potential to increase gas and we are ready with that. The moment the connectivity comes we will increase the production of gas.

Sir, is there any study with you about the contingent resources tax in the Assam basin or something that get the sense about the exploration potential, if any initial studies which you have done?

Yes. Yes. Actually, this is a continuous process as you are aware. When you take up a block, it has been carried out and basis that there are around -- as we speak, there are 17 blocks that is under various stages of exploration, and we are carrying out these contingency ratios assessment, and then we will be carrying out the exploration through different phases from seismic till drilling. So that's a continuous process, that is actually rest of the PML beyond the area -- beyond PML is actually taken care of by that process.

Okay, sir. And my final question is, I think you have identified 4 or 5 fields apt for production ramp-up in the Assam region. So if you give some sense about the timeline and the -- some possible production addition roughly range is something that would be helpful, sir, in...?

I think you are referring to the Mission 4+ production target. So for that, we have identified 5 fields. And as of now, drilling activity, as we have discussed in the previous discussions, the drilling activity has been ramped up in all those areas. And the target is next year around 3.8 million tonnes to achieve and the subsequent year, we are expecting more than 4 million tonnes plus. So that is the plan from these 5 fields.

Okay. Okay. Okay. That 5 fields is a part of your production in the ramp-up plan.

Yes, yes, yes.

Yes, yes, it's the same plan.

The next question is from the line of S. Ramesh from Nirmal Bang Equities.

See the first thought is your segment results from the gas business has dropped more than 30% whereas the gas price hasn't declined that much. So what is the reason for this sharp decline in the gas segment earnings?

For the 9-month period, as you already know, the first quarter was affected because of the offtake was less. Numaligarh Refinery Limited, they had a planned shutdown and subsequently, there was just certain fire incident. So that's why it was closed for almost 75 days for this -- in the first quarter. And in the first quarter, BVFCL also, they had a planned shutdown, Brahmaputra Cracker and Polymer Limited had also a planned shutdown in the first quarter. So in this 9 months period, if you see, the drag is because of the shortfall in the first quarter.

Okay. So if you look at your growth drivers for next year, based on the 10% growth in oil production, maybe similar growth in gas assuming the costs remain the same, and if there is no increase in the dry well write-off, would we be able to revert the decline in earnings we are seeing this year. So would you be able to get back to growth in earnings, so say, in FY '25?

Yes. This is a one-off incident, as you see. And subsequently, in the second and third quarter, it has been improved. So with the improved performance, we are certain that the performance will be -- in the coming quarters, the performance will be much better.

So on the GRM reported for Numaligarh, these numbers, are they including the excise duty benefit because the numbers are very low, which includes the excise duty benefit. So what is the excise duty benefits you've got on the GRM numbers you reported for Numaligarh?

This GRM reported are the core GRM without the excise duty benefit.

Then what would be the excise duty benefit, which is included in the segment results?

About $15, $16 per barrel.

$15, $16 barrel for 9 months. Okay. So in terms of your, say, long-term plan for Numaligarh once the expansion is done, what is the time line for completion and startup of the expanded capacity of 9 million tonne? And what is the...?

Scheduled for July '25, but we can consider another 3, 4 month extension. So fair estimate will be around September '25.

So where do you think you'll be able to sell that because it's almost about 2x addition to your current volumes, so what is the evacuation plan? And how confident are you in terms of being able to sell the entire 9 million tonnes throughput equivalent of output?

All these things have been already tied up. Agreements have already been done with like we said Bharat Petroleum Corporation and also some agreements with the private marketers plus other OMCs. As far as the evacuation plan is concerned, the larger evacuation will happen through the Numaligarh-Siliguri pipeline which is currently having a capacity of 1.7 million tonnes. It is already under expansion for 5.5 million tonnes annually. So all petrol, diesel and kerosene, these 3 main products out of the 9 million tonnes, whatever is the production of these 3 products, 5.5 million tonnes the pipeline is getting expanded plus Numaligarh has already laid a pipeline of 1 million tonnes per annum diesel pipeline to Bangladesh, and all those plans are already in place and under implementation.

Okay. So in terms of your sale of gas, are you going to sell to GAIL or are you directly selling it? And what is the pricing arrangement? Would it be at the APM price? Or what are the kind of pricing you will get? If you can share the thoughts on those few aspects?

As of now, the entire gas that we are producing is basically the APM gas, but there was a provision in the gas pricing guidelines about some premium pricing, 20% premium pricing from the new gases, certain areas. But those guidelines are yet to be issued what will be considered as eligible for premium pricing. So once we get those guidelines, then only we'll be able to find out how much my gas production can be eligible for additional price. Otherwise, as of today, entire gas production is APM gas production eligible for $6.5 per annum basis.

So will you be selling it through GAIL or you're directly dealing with the customers for gas...?

We are selling our entire gas through -- directly nothing to GAIL as of now.

The next question is from the line of Somaiah V. from Avendus Spark.

This is Vishnu from Avendus, sir. Sir, a couple of questions. Firstly, on the production targets we have just given. So these factors in a base decline also because typically all our fields also kind of decline. So it means our production has to be significantly higher to cover up the base decline also?

Yes, you are right. Actually, the average decline -- this is -- that -- whatever is increase in production is after compensating the declines and for the additional [indiscernible]. So average decline has been taken care of, and then we are getting the increased production, this is on the...

It's for the decline itself.

So if I talk about a decline of around 8% to 10% so you are now showing a growth of 6%. So this is 10% plus 6%. That means the total growth is 16%.

Around 16%.

Understood, sir. Second, on the gas marketing, which you just discussed about. At least in the near term, at least the next couple of years, what kind of volume that we think that we can place in the markets around the new pipeline or nearer to our markets?

So my -- the next 2 years, our target is 5 BCM of gas. So we are looking for that type of market in the -- when it will get connected to the mainland India. So I don't think there will be any constraint in marketing. So that is why we have now placed a plan of 5 BCM gas.

The additional 1.5 million tonnes basically taking a cue from what my Director Operations just mentioned. Currently, we produce around 3.2 BCM annually. The growth is 3.2 to 5 will be 1.8. So taking out the internal consumption, any growth in internal consumption, et cetera, at least 1.5 BCM additional will be available in the market once we reach production level of 5.

Understood. Sir, we generally get a -- the customers get a subsidy in terms of pricing, which was sold in Northeast. So this additional gas will also be eligible for this? And currently, what is the subsidy per unit of gas do the customers get?

Subsidy is only certain customers get subsidy, certain class of customers get subsidy. Subsidy is 40% of the gas price. Now that subsidy is limited to the allocations that have been made by the government long by 2005, 2006, after that, there is no increase in the subsidy allocations. So for every additional drop of molecule of gas will be at the full price, nothing on subsidized.

The next question is from the line of Vikash Jain from CLSA.

A couple of them. Firstly, some numbers. So this -- can you please share the seismic cost for the quarter?

Seismic cost?

INR 131 crores.

For the quarter. INR 130 crores.

INR 130 crores. And same number for the previous quarter, what was that, [indiscernible]?

[ INR 175 crores ].

The. Y-o-Y quarter, I mean.

No, no one second, let me just see the numbers also.

[ INR 130 crores ].

Currently, yes, current quarter is INR 130 crores, last year -- last quarter if you do those, it was INR 110 crores.

Sorry, I...

INR 110 crores.

INR 110 crores. Okay. The other thing was this provision on GST that has been made in this quarter. This appears to be much more than 18% on the royalty for the quarter. What am I missing over here? I mean, this number is like...?

Actually, this number includes not only GST, this includes also interest outstanding, on the outstanding balance. So that is why the amount does not match that 18% with the GST the usual royalty amount.

But if you have already put in the amount in escrow, would you also need to put in the interest? I mean, are you charging if that amount has been already deposited although under protest?

No, no, Mr. Vikash, entire amount has not been paid. Say, out of the total provision, total GST that is payable, only about INR 1,400 crore has been deposited with the government. So that after the date of deposit, of course, doesn't bear any further interest. The remaining about INR 1,011 crores which is -- so the provision has been made. It has not been deposited in view of the stay granted by the Guwahati High Court. So that certainly is maybe liable to interest, which provision we have created.

And what rate of interest are we charging? I mean is there any penal rate of interest as well over that? Like you said 24 so about INR 1,000 crores, you said, INR 1,100 crores, right?

INR 1,000 crores, INR 1,100 crores is the unpaid amount, yes.

And what rate of interest are we looking at over here? Because you...

The rate of interest is as per the rate given in the GST Act.

Okay. Okay. Understood. The other question was on this production number that we are talking about going from 3.4 million tonnes you said next year and then 3.5 million tonnes, and for gas, going to 5 BCM in FY '26. So FY '25, what do we -- what is the kind of number that we are looking for gas?

That will be around 4 million tonnes -- 4 BCM. It will not reach 4 BCM, it will be near about 3.8 BCM to 3.9 BCM.

So 3.8 BCM to 3.9 BCM...

Yes. This is basically customer driven. Once the customers are established with us, deals is established, the customer will go up. And accordingly, the gas production will go up. . As as of now as I speak, we have the potential to produce all those wells, but we are not producing because we do not have customers. If we produce, we'll have to flare it up. So we do not produce, we're closing some of the wells. So once we get the customers, we'll be able to produce it, if I get a customer of around 3.8 BCM, 3.9 BCM, we'll be able to produce that next year.

Customer basically means your connectivity that you're talking about, right?

Yes, yes.

Yes, basically customers, yes.

So that connectivity, what is the update on that? I mean, how is that pipeline connectivity moving as your best guess?

As of now, the mainland connectivity may take some time, but it is coming up, up to Guwahati it will be ready. So up to Guwahati, we'll be able to capture all those customers by this year.

And for crude 3.4 million tonnes to 4 million tonnes, I mean -- you said 3.5 million tonnes in FY '25 and then straight away going to 4, that's a pretty big jump. So any particular reason? Or is it simply with NRL hopefully coming by FY '26, which will only be partly. That is not what is causing it, right? Or is it dependent on NRL, the offtake going to them?

Sorry, I could not get it. Can you just repeat?

I'm saying you are talking of crude going to 3.5 million tonnes FY '25 and then 4 million tonnes in FY '26, right? Is that what your guidance is?

No, this is not related to Numaligarh Refinery. Crude, we have customers so we can produce crude oil.

Okay. So -- but this is the guidance, right, 3.5 million tonnes and then 4 million tonnes?

Yes, 3.8 million tonnes next year, then 4 million tonnes.

3.8 million tonnes in FY '25?

Yes.

Ladies and gentlemen, this will be the last question for today, which is from the line of [ Vipul Kumar Shah from Sumangal Investments ].

My question is excise benefit will be available for expansion of NRL from 3 million tonnes to 9 million tonnes?

What benefit?

Excise benefit.

Yes, it is available, it is available as and when excise duty is continuing this benefit is available.

Okay. And marketing of entire 9 million tonnes will be by BPCL?

Not necessarily, we are tying up with BPCL, IOC, HPC, even the private marketers also. But majority will be of course through BPCL.

As that was the last question for today, I would now like to hand the conference over to Mr. Varatharajan Sivasankaran for closing comments. Over to you, sir.

Thanks, Michelle. Harish-ji, if have you any closing comments. Please go ahead.

No closing comment as such, I will certainly thank all the analysts and the investors who participated in the call for your interest in the company. And I think it's your positive outlook that you are basically conveying to the investors, to the shareholders and that's what's basically reflected in the company's market cap and the share prices of late. Thank you very much for all of that. And thank you very much for joining us today. We are open for any queries, any -- call us at any point of time. If any clarification needed, please reach out to us. And thank you, Antique Broking and Mr. Varatharajan for attending this call. Thank you so much.

Thanks, Harish-ji. Thanks for giving us this opportunity to host the call. And I thank all the participants for taking time out to join this call. Have a nice day.

Thank you very much, sir. Thank you, members of the management. Ladies and gentlemen, on behalf of Antique Stock Broking, that concludes this conference. We thank you for joining us, and you may now disconnect your lines. Thank you.