Ladies and gentlemen, good day and welcome to the Hindustan Oil Exploration Company Limited Q1 FY27 earnings conference call. As a reminder, all participant lines will be in the listen only mode and there will be an opportunity for you to ask questions at the end of today's presentation. Should you need assistance during this conference call, please signal an operator by pressing “star” then “zero” on your touchtone phone. Please note that, this conference is being recorded. I would now like to hand the conference over to Ms. Saloni Soni from EY. Thank you, and over to you, ma'am.

Good day everyone and welcome to the Q1 FY27 earnings conference call of Hindustan Oil Exploration Company Limited. The company published its results yesterday and have uploaded the investor presentation on the exchanges earlier today. I trust all of you would have had the opportunity to review them. Before we start, a disclaimer. Some of the statements made in today's earnings call may be forward-looking in nature. Such forward -looking statements are subject to risks and uncertainties which could cause the actual results to differ from those anticipated. These statements are based on management's beliefs and assumptions on information currently available to the management. Audiences are cautioned not to play undue reliance on these forward-looking statements, while making their investment decisions. On that note, let me introduce you to the management in today's conference call. We have with us Mr. Baroruchi Mishra, Managing Director and CEO; and Mr. Allen Joseph Andrade, CFO. Without further ado, I'd like to hand over the call to Mr. Mishra. Thank you and over to you sir.

Thank you Saloni. Good afternoon to all of you who are on the call. Before we start, may I request you to spend 20 seconds looking around for your escape and evacuation routes just in case of an emergency, familiarize yourselves. Because that's a good thin g to do when we start any conference calls or anything. So this is a standard thing that we should all be doing. So with that, let me start with a brief on how the quarter has been, what have we been doing and what is the look ahead for us. The quarter unfolded against a backdrop of continued focus on energy security, as you know. Domestic hydrocarbon production and infrastructure development across the entire oil and gas sector has been a heavy lift for the country. While the broader industry continues to navigate operational and market challenges, the long term fundamentals remained very encouraging for us, supported by the huge

demand that the country continues to see now and in all times to come, to be able to propel our growth by 7%-8%. Energy becomes the bedrock of this growth for the country. Against this backdrop, our focus for this quarter remained absolutely clear. We continue to prioritize operational execution, production optimization, and continue to work on our development projects while all the time trying to have a strict discipline in our capital allocation. While certain assets faced short term operational challenges, we made meaningful progress across the portfolio in positioning our key projects for future growth. So one by one I'll take you through the progress across our portfolio. Beginning with our offshore assets. So at B-80, our flagship offshore asset, production during the quarter was impacted by a higher water cut from one of the producing wells resulting in lower output. Now if you remember, we had said last time that we have to do work -over on these wells to shut off the water zone, etcetera. Incidentally, the water cut continued to increase and that has impacted production, but we continue to produce from these wells. In order to sustain production at near similar or slightly higher rates, we have changed the configuration of the compressor trains on the platform on the MOPU , so that the compressors are now able to operate with a lower suction pressure. What that does is that allows the well to flow more even when the flowing pressures of the well decreases. So that configuration change has been done, and we are in a test mode now. The workover of 2 existing wells, which are D1 and D2, we continue to stay on track. We are in discussion with the rig for the final award this month, and then they would be mobilized by October, at which time we will work over on the two wells, which are currently producing, shut off the water zones, open up new oil and gas zones and ensure that we have an increased production from these two wells. We have made meaningful progress on resolving our HPCL issue, albeit that there were delays in the offtake by road. But that said, the offtake continues, and we are reselling the crude to third parties. Moving to B15, which is the new block which has been awarded to us. The FDP is under preparation. We are looking at all concepts. We are evaluating three or four concepts at this stage. One of them includes connecting to the existing ONGC's platform to red uce our capital costs. So, all of that is being worked now, and we'll do the drilling in FY28. The reserve levels are 16 MMBOE, which will be reappraised after we have done some more processing and after the first well, we are hopeful that we'll see an upside. At PY-1, which is in our East Coast, the platform, the three wells, we have suffered serious production loss -- and now we are in discussion, we have already awarded a contract for

rig-less intervention on the wells, which will increase production from these wells in the short term before we come back and drill two new wells. Now the drilling of those two new wells, while we had planned for quarter four of next year, they have become contingent upon the ability of the gas buyers, IOCL / GAIL to lift our gas because otherwise, we will have sat on these new wells, having drilled them, ready to produce and if we keep them shut for x number of months, they will again be watered out. So this time, we are trying to get it right. As far as possible, we'll have a take -or-pay agreement either with GAIL or with IOCL and only then we will spud the wells. So that's the intent that we have, we are going ahead with. But in the interim, we're do ing the rig- less completion to increase production from PY1. Now, let's get back , to get to the onshore portfolio. So we have Dirok in Assam, highly prosperous field. We are the operator with 27 -odd percentage in the field. There isn't a reservoir in India, and in large parts of the world, where your production header pressure from six wells is 3,000 PSI. That speaks to the prospectivity of this reservoir. But that said, we are producing only 50%-70% of the capability from the existing well stock because of the lack of evacuation route. Now stuff have happened in the evacuation route improvement, as in the PNGRB has made the DNPL line as a common carrier, earlier it was a captive of NRL/Oil India, but now it's a, I mean of course operated by AGCL, but now it is a common carrier. There were some sections in this pipeline which had degraded and therefore the overall capacity of the pipeline has been reduced. So they have laid pipelines along the main pipeline for sections which have seen asset integrity challenges, they have to tie back into the main pipeline. They are looking at hot tapping to tie back and get back the total capacity to back to 2.5 million standard cubic meters from the current degraded capacity of 1, 1-1.5 MMSCMD. So that work is being done by Assam Gas Company Limited and we are in discussions with them just to be there to support with any technical requirements that they may have on this hot tapping. Coming to Kharsang, we had successfully completed nine wells program and we doubled our production from last year, but we haven't rested there. We have continued to do workover on a few of the wells. We have now, we had 23 additional wells there, we were sat for without production, and we have been working over on them. Five or six workovers have been completed and we are incrementally increasing production. We are also getting ready for the second phase of nine wells, the rig has been identified, the award is imminent, we are looking at tubular, we are ordering the tubulars, which should be there in one or two months time, and then we should be good to go for our second phase o f drilling in Kharsang.

The problem remains that if we find gas, then we don't have a buyer and in fact, we have found virgin gas in two of the wells in Kharsang. That's a good problem to have, but the only thing is it delays the monetization of reserves because we don't have a pipeline. So we have started a pipeline route survey, as we speak , the tender is out, it will close tomorrow, and then we will have parties to start the route survey. There is a challenge there as it goes through a forest area, so regulatory clearances might be an issue, but given where we are and the confidence that we give to the environmental teams and to the forest officials about not disturbing the fauna and flora of the forest, we should be able to navigate this regulation and should be able to start laying the pipeline in six to eight months time. So that will then connect us to a continuous gas flow path that Oil India has already created, and that will help us monetize the Kharsang gas molecules. Oil we are already selling to the Digboi Refinery and to various buyers, mostly IOCL. So coming to Gujarat, in Cambay Basin, we have Asjol, Balol, and Palej. Three of these in Balol, we have started a new technology, which is a belt technology where the belt goes down and soaks up the oil and comes up and we squeeze out the oil. That new technology has been implemented. It is in the trial phase. Then we have also debottlenecked our Palej facility to be able to increase production by using thermionic heaters and those kind of things. So overall, 20% to 30% increase in production we will see going forward, although we have already seen a 5% to 6% increase in the last quarter. But more to come. Palej has a lot of potential, we have to drill additional new wells. We have also ordered sucker rod pumps. So we are on track to increase production from our Cambay assets. A new block which has to be given to us for exploration is in the final stages of approval. Once that happens, it's close to our Palej field, we'll be drilling new exploratory wells as well. So that is the long and short of our portfolio. We are on track to both grow value, create value as well as preserve value for our organization and for you shareholders. So with that, let me stop and I'll hand over to Allen for a quick two minutes -five minutes update on the financials and then I'll be very happy to take questions.

Thanks, Baroruchi. I will now take you through the financial and operational performance of the company for the quarter. During the current quarter, the company recorded standalone revenues from operations of INR117.5 crores compared with negative of INR194 crores in the previous quarter. After accounting for profit petroleum and revenue share of INR9.83 crores, the net revenue stands at INR107.6. The previous quarter was impacted by the reversal of the HPCL sale of INR259 crores, as we are well aware. The consolidated revenue from operations for the quarter was INR124 crores, and after profit petroleum and revenue sharing, the net consolidated reve nue stands at INR114.17 crores.

The improvement in the current quarter, as Baroruchi had mentioned, was driven by higher production from the Kharsang field, mainly crude, and favorable Brent prices. This was augmented by the commencement of the liquidation of the B -80 crude, although at a slower than expected pace. Even from an operational perspective, the production from Kharsang has been most encouraging, where production increased from approximately 12,300 barrels of oil to 17,400 BOE. The average realization of crude and condensate improved significantly to about $95.5 a barrel, compared with approximately $70.8 per barrel in the previous quarter on a standalone basis. In addition, the average gas price realization improved to $12 MMBTU, compared with 9.8 MMBTU in the previous quarter. So quarter -on-quarter price changes and volume changes from Kharsang have delivered a really good top line. Coming to profitability, the standalone profit before tax and exceptional items was INR12.54 crores for the quarter compared with INR30.4 crores in the previous quarter. This is mainly due to the offset to cost from higher inventory of crude in the previou s quarter. As you know, the previous quarter we reversed out the sale from HPCL and hence, that resulted in a higher -- in a lower cost offset to the overall operating cost. On a consolidated basis, the profit before tax and exceptional items was INR6.5 crores compared with INR9.01 crores in the previous quarter. The other income for the quarter was INR19.37 crores on a stand -alone basis and INR20 crores on a consolidated basi s. The stand -alone other income includes the release of a long due escrow balance pertaining to cost recovery of approximately INR8 crores, income from an insurance claim, which was admitted by the insurance company of INR2 crores , and topping up of the Adbhoot acquisition as at March of approximately INR2.3 crores. The movement of profitability needs to be viewed in the context of the quarter's cost structure, mainly the impact of changes in inventory of crude, which is stored in tankers and not sold till the appropriate time. Stand-alone total expenses for the quarter at INR114 crores included depletion of INR51 crores, royalty and other statutory dues of INR13 crores and stock adjustments of INR41 crores. On a consolidated basis, the total expenses were INR128 crores with cost s, including depletion at INR58 crores, royalty , cess and other statutory dues at INR15 crores and stock adjustments of INR41 crores. The consolidated statements include the 10% GeoEnpro sales from Kharsang. As we look ahead, our focus will be cost reduction and cash management to ensure, as Baroruchi said, the allocation of funds to maximize full potential of the existing reserves. Thank you, and I will hand it back to you, Saloni, I think with that.

Thank you very much, sir. We will now begin the question -and-answer session. We have our first question from the line of Dhruv from Leo Capital. Please go ahead.

Thanks for the opportunity. So I have a couple of questions. So my first question is that what is the current status and expected time line for the Northeast grid connectivity that Dirok depends on? Is the pipeline interconnection actually complete now? Or is it still pending? And once it's ready, by when do we expect Dirok production kind of like ramp to the decent levels?

So our take is that by December, this should be completed. The Assam Gas Company Limited, which operates the pipeline is in discussion for hot taps to be carried out. Then in the NRL, there is 100-odd meters of pipeline which has to be done . That also needs a hot tap. We are told that by December, all of this will be completed because right now, after the hot tap option has become available, NRL shutdown is no more needed. So it is roughly 16 to 20 months lead time for hot taps. So that work is going on with the Assam Gas company. So December is what we are looking at.

Okay. Thank you. My second question is regarding what's your view on B -80 currently? How is the production and monetization progressing given the HPCL dispute? and when do we expect the issue to be resolved?

So if you mean the B-80 crude which is stored in HPCL tanks commingled with their crude, we are in -- the sale continues through tankers to third parties. We have reversed the sale, as Allen said, in March, April of this year, and we agreed to sell it to third parties. The speed at which is there's being picked up by the third parties is slower than expected, but we hope that by end of October, early November, the entire crude inventory will be gone from the HPCL refinery in Chembur in Mumbai.

Okay sir. That was really helpful. Thank you and all the best for the next quarter.

Thank you.

Thank you. Next question is from the line of Shubham Jain from NV Alpha Fund. Please go ahead.

Hi, sir. Thank you for taking my question. My first question was how much was the impact on the P&L because of sort of mark-to-market losses on the inventory that we are holding?

So the jury has to still come back home. We are in the process of selling it, and it is dependent upon the Brent price. So we have sold roughly 15% of the crude as we speak and the realization has been -- we have incurred some losses, which is an range of INR4 crores to INR5 crores, maybe INR6 crores. But we still have to go with the remainder of the crude, which is now picking up as the monsoon bears out. So we will suffer a loss.

Now how much? I would put my number to around 7% to 10%, but please don't take it as a guidance.

Got it. If I adjust for this number in this quarter's number, what would the EBITDA have been?

EBITDA?

Yes. So we've done a INR6 crores EBITDA and there is a certain adjustment that happened because of the inventory level. What would the EBITDA have been ex of these adjustments?

Okay. Let me come back to you on that because I don't want to give you this -- it's a bit of a technical issue because there is inventory adjustment, there is profit petroleum adjustment. There's a cost -- there's a sale adjustment, okay?

Understood. My second question was how is the sort of rig alignment’s workover and the new wells that we want to dig in B-80 progressing?

Can you speak slightly slowly? We couldn't hear you. I mean, you were not clear.

So sorry. I hope I'm clear now.

Yes.

I was asking how is the sort of alignment of rigs happening for the workover plus the new wells that we want to dig in B -80, have we, do we already have it in place and sort of are we on track to complete it by 3Q and 4Q '27 respectively?

Yes. So we'll start -- so if you're wanting to understand about the campaign, this is a single campaign that we will be looking to deliver. The first one would be two workovers, which are in the range of 10 to 20 days each. And then we'll have three wells, which would be in 30 to 40 days each. And that will take us towards the end of March, early April, and then we will install a jacket on it and a production deck and on that basis we will we'll start production. Now, these are offshore wells, stuff happens sometimes the tubing gets stuck, and so there could be delays. So we are -- but the plan remains that by June of next year, we'll bring three wells on production. By November and December of this year, which is 2026, we will have two wells that we have worked over on production.

Got it, understood. Thank you so much. I'll get back in queue.

Thank you. Next question is from the line of Riddhesh Gandhi from Discover Capital. Please go ahead.

Hi sir. Sir, just had a few questions. We've obviously had a long delay in terms of Assam with regards to -- for the last, I mean two years, it's been a few months away. Right, with regards to it starting. Just want to understand what's giving us the confi dence now and just wanted to understand what are the actual risks involved with regards to the Assam connection -- connectivity to the national grid.

So very good question. So the current circumstances have forced issues with the stakeholders, because the country needs gas, there is a supply chain disruptions, energy security has become a big thing. So there has been a lot of push from all stakeholders to align and get this done. To that extent, the PNGRB has hastened to ensure that the line which would carry the gas is no more a dedicated pipeline, it is a common carrier where anybody can pump the gas if there is demand. So that aspect is taken care of. The other aspect was the degraded sections of the DNPL line had to be replaced to increase the capacity. So those lines have been laid. Those sections of lines have been laid. Now it is just a matter of tying back to the original line so that the capacitie s can be increased and the pressures can be increased. That was earlier dependent upon NRL shut down because to be able to cut the line, you would have to empty the entire pipeline, depressurize it, flush it with nitrogen. That would mean 7 to 15 days of shut down for the Numaligarh refinery. In discussions with Assam Gas Company Limited, many stakeholders including us, we have been able to convince or we have been able to discuss that hot tapping could be a solution for ensuring that NRL does not have to take a shutdown. In fact, for hot tappi ng in a pipeline, you actually have to produce gas, continue to flow gas so that the heat can be dissipated. So Assam Gas Company Limited has taken on this concept, they are in the process of award of the hot tapping contract, we have been in discussions with them to provide technical support. Although we are not directly connected, but just as a responsible stakeholder, we have been in discussions with Assam Gas Company to provide support on , technical support that they might need on the hot tap. So that gives us a level of confidence. But it could have started a bit early, the tender etc., but floods have made a lot of disruption in Assam as we speak. Things are getting back to normal and in talking to the service providers of the hot tap, they are saying 16 to 20 weeks. Although they are trying to bring it forward now, so we are hoping that in

December, the hot taps would be completed and we should be able to get higher capacity in these lines and then be able to flow to the national gas grid. So that is the premise.

But NRL has been refusing to take a -- has been refusing to take a shut down for the last few years, is it? Because I mean that's the easiest solution which was there, right?

No, so it would not be fair for me to say that they have been refusing to take a shutdown. It is also dependent upon whether they are allowed to take a shutdown, given the shortage of products, etc. So there are multiple things that play there, and I will not be the right person to comment. But long story short, the shutdown was delayed and we agreed with Assam Gas Company, they were looking for options, and we discussed that hot tap could be an option and on that basis, they are pushing -- they are progressing.

Got it. Sir, and the other question similarly with regards to a B -80 as well, we've done a number of re -workings over the last few years, right, whether it was having chemicals brought in and all of the equipment, etc. over the last few years. Now again, there appears to be another solution here. What's again giving us the confidence that it's going to work this time around when, I mean historically it hasn't, and just wanted to understand actually, what would give us the confidence that there isn't anything structurally wrong with a B-80 and that it's actually fixable.

That's a good question. In the oil and gas sector, we have to continue to pursue production so long as we have a level of confidence that the recoverable reserves are still in the ground. In India, we don't have an ecosystem where you can just make a phone call and get a vessel to do work on a subsea completion well. These two are subsea completion wells. So stuff have been tried in the past, where we've used chemicals to shut off water zones, etc. Some of it has worked, some of it haven't, but now we are getting a rig to be able to completely shut off the water zone through rig intervention. So the level of confidence in making an improvement towards higher production is high. We will have to do re -perforation etc., because the flexibility to operate increases if you have a rig on the well. These are subsea wells, so you can't -- if there were dry Christmas trees on a wellhead platform, you could have brought a coil tubing like we are doing in PY- 1, or a wire line and would have done stuff inside the well. But these are subsea wells and to be able to make an intervention in these wells, physical intervention through a tubing etc., to change zones, to re -perforate new gas and oil producing strata, you need a rig and that rig we are getting now. We believe our 2P reserves are still there, 26 million, of which 1.5-2 million has been produced so far. So there are reserves to be produced. So we are giving it our best shot, we are planning properly, and we hope that we will be able to minimize the risk. Risks are

always there in the oil and gas sector. We are hopeful that we'll minimize the risk and recover our investments with very good margins after we do this work.

Got it. Sir, the other question was in your latest presentation you -- we seem to have increased our capex budget from the Q4 presentation. Is this because of escalating, actually costs or is it because of incremental opportunities that we are pursuing?

So at this stage unless we have awarded the rig contract, we'll always have to have a contingency. The rigs have come in very short supply now. As the oil prices increase, everybody wants to drill. So we have to have some increase in the contingency , and it is not that whatever we have set as a capex will be spent. That is the kind of facility that we will be creating and we'll draw down on the facility on a need basis. After doing these two workovers, our own cash flows will also improve, and a part of that would be funded from our internal cash flows. But just to be cautious, we are going into the market. We are talking to the investors and to the banks to be able to ra ise a pot of money which will allow us to do the workover and the three wells and bring them on production unhindered from a cash position.

Got it, got it. Okay, sir. I'll rejoin the queue. Thank you.

Thank you.

Thank you. We have a next question from the line of Manpreet Arora from Arora Wealth Advisors. Please go ahead.

Yes, thank you for the opportunity. Sir, one clarification first, Mr. Andrade, you mentioned that we realized $12 on the gas side. Now this is blended realizations across B -80 and Dirok?

Yes, this is blended -- cross flow.

Sir just a request, you know, in the previous presentations we used to give, you know, asset wise realizations on the gas and oil.

Yes.

Yes, and you know it will be good if we can continue that practice because I believe that B-80 is IGX related and then on the Dirok side we have the PPAC pricing. You know the blended realizations, kind of, make it a little difficult to model, specially you know when Dirok will in next few quarters will start scaling up. It will help us to model it a bit better on how Dirok will start contributing. So I mean if you can continue that practice that we used to follow previously, that would be very helpful.

Point -- point well taken, point well taken. We will in our next presentation make sure that we include the offshore and onshore realizations as well so we can get an idea of what individual fields are realizing. But please remember that the B -80 gas which is produced is traded on the exchange and we realize approximately about $15 per MMBTU to $16 per MMBTU on that exchange. The other prices at Dirok are -- Dirok and at PY-1 are pegged at sometimes $10 MMBTU, sometimes $12 MMBTU. So it’s a blend. That's why it's a little difficult to tell you what exactly this is. But we can certainly, we've got that information. We can provide that without a problem.

Great, great. That is really helpful. Thank you. The other...

Yes, because -- sorry, just to add I mean it's we have a JV obligation to report these figures. So every joint venture has quantitative information as well as the sales information. So it's not difficult to pull that figure out. So we will make sure that all the investors are provided with that information as well.

Great, great. Thank you. The other question was on the B -80, since it is a monsoon time right now, s the production still ongoing or have we stopped -- it is a monsoon.

Now which is ongoing -- we have never had a day where we shut the production, although we had to do some things related to asset integrity in the splash zone on one of the wells, we had very severe corrosion, etcetera, which we had to figure out. One of the wells has a very high water cut, and by itself it would have produced very little. So we have re -configured the compression so from parallel we have gotten them into series so that they can suck higher at a lower suction pressure. So the production continues albeit that it is partial at this stage. They have lived towards the end of the month, it should be completely 100%.

Just to add, I think, you asked the question about the average price realization. If you, I mean, I hate to make you do this, but if you want the B -80 realization on an average is $16.5 per MMBTU. The Dirok is 12.5. Okay? Compared with that...

Sorry, can you say that again, 16.5 for B-80?

Yes, and the Dirok was 12.5.

Okay, great. Great. Thank you. And sir... am I audible?

Yes. So sir on the DNPL side, you know, just to understand what you described about NRL and shut down. So the sequence of events from now on, because, you know, this was also mentioned in the Oil India con -call. So I think DNPL is now a common carrier. But there is a 200 meter, you know pipeline gap which needs to be done where IGGL -- to connect IGGL and DNP L? and then once that is done, then we will go for the DNPL capacity augmentation, whatever the, you know, degradation has happened, we will do the hot tapping and then you know, at the end of December, you know, we expect gas to flow from DNPL to IGGL. Is that a correct understanding?

Yes, so it is in parallel. Your point is well -taken. I mean, you have made the right points. Only thing is AGCL are working on. There is no dependency on the hot tap and the NRL, there's a 100 meters or 150 meters, 200 meters of pipeline which has to connect DNPL to the gas grid inside NRL's -- NRL's facilities. That's a very, that's not such a big thing. The main thing is this hot taps. So they are continuing to work on the hot taps now, and at any suitable time, this 150 to 200 meters of pipeline will be laid inside NRL to connect DNPL line, which enters the gate of NRL to the exit where it connects with the gas grid. So that shortcut bypassing NRL, is in the gift of NRL to do it at any time. It should not be such a big problem. The big thing is some of these hot taps are in the middle of the fields, paddy fields and they have water, etcetera, in them, which has all been now -- which have all been planned now and the awards are imminent and the vendors have gone and seen have submitted the procedures. So that is the critical path, if you will, for start. And of course, this 200 meters of pipeline, as Oil India told you, is absolutely necessary, but that is within the premises of NRL. As you can see, 200 meters grind is not a very big thing.

Yes. Thank you and one last thing on the B -80, in the last investor call, we had about -- asked about the storage that we have already 1 ,18,000 on the FSO. Now you had mentioned that we can technically sell it, but there are demurrage charges that will come into picture and therefore, we have to take that into account if we want to sell what we have currently in our FSO. Now I mean -- and you also mentioned that we are looking at how we can do that. So is that still--

So in October, we'll sell. In October, we'll have sufficient volumes for a small tanker to be able to take it and we'll be able to sell, but that would be around 120,000 to 130,000 barrel of crude we'll be able to sell in October. Because if you have lower volumes and you send the large tankers, those tankers ask for demurrage charges and there is some debt volume which remains. So it is not an optimal number, 120,000 to 150,000. We are looking at smaller tankers. In October, as soon as the monsoon gets over, we will sell.

Sorry, to you interrupt you Manpreet. May we request you to join queue? Thank you. We have next question from the line of Nishant Maheshwari, an individual investor. Please go ahead.

Hello, am I audible sir?

Yes.

Yes, you are.

Sir, we read something -- there is a protest in Tamil Nadu regarding of drilling two wells that too is related with the area of allocation. So, can you brief us about this?

Yes. So look, these fields are all approved by the MOPNG. For as a matter of good practice, we keep the state governments informed. But the final arbiter on the approval to drill, etcetera, is the central government, which we have for the entire field. So there were indeed some protests around drilling these two wells. We have taken up the matter with the state government, explained to them the way this environmental clearance has worked, and we have showed them all the approvals that we have. We hope that it will not be such a big issue. So, let me rest it there. But you're right, there was an article there. But essentially, as you will read anywhere, the approvals are from the central government. We keep the state government completely informed though.

In the last con call, sir, you said that the realization of the HCPL crude was ongoing and the turnover might have been booked. But as on the date that the same situation is canceled and we are now less confident on what we have stated in the last investor presentation that we will be achieving 11,000 barrels per day from now to June 2027, and that's really now under a big -- I mean how we can trust? Because from last three years we are constantly saying that production will increase, production will increase, but as on date the production has drastically reduced from 2024 levels. That’s -- now how we can trust that 11,000 barrel per day production will be there in this company?

No, that point is well taken, and I understand your line of thinking on it has not been delivered so far. One of the key reasons why there was a further delay was the st uck-up of our invoice in HPCL, which was a Black Swan event in many ways, where INR260 crores plus, if you add the interest, roughly INR300 crores got stuck. Otherwise, the workovers would have been done in November of last year, and we should have been on track to drill -- we should have drilled these three wells to be able to get on production. That is the nature of the beast here.

Globally, $400 billion are spent every year to keep the production plateau, not from declining, not for growing production. That unfortunately, we could not do for various reasons. Now we are in the market to be able to raise funds to deliver that. Again, there could be a challenge if we don't get the funds, but at least some part of it, we are funding from our own accruals. So we are hopeful that we will be able to deliver. In the offshore, in the reservoir, there are always uncertainties. So, when I say 11,000, it could be 8,900 or it could be 13,000. But that's the range that we're looking at on the basis of the technical work that have been done on the reservoir and the pr ospectivity of this reservoir to produce these volumes.

Are we looking into Samudra Manthan scheme and get some expenses to be -- I mean, borne by the government of India?

So, those are for deepwater. Samudra Manthan is essentially for deepwater as far as I understand, and we are in shallow water. So, right now, the eligibility for us to get some support, we are still in the process of evaluation. But you're right, this is a huge flip for the oil and gas sector in the country. Whether it supports shallow water drilling, that is something that we still have to understand.

Have we started selling crude of HPCL or--?

Sorry, to interrupt you Nishant. May we request you to rejoin the queue?

Sure, sure. Can they address this please?

Yes, we have.

Okay. Thank you.

Thank you. Next question is from the line of Nirbhay Mahawar from N Square Capital, please go ahead.

Yes. Thanks for the opportunity, sir. Just wanted to know, when do we see our cash flow sufficient for our capex commitment? Because you have mentioned that because of the delay from HPCL, we have delayed our capex. So with whatever operating improvement we're expecting, when do we see our capex from internal approval rate?

So for delivering B-80 program, we will have to rely on debt. 2e are in the process of raising debt. By the quarter four of by November, December of next year, 2027, our cash flows will be sufficient to fund our growth for B -15, and if we get awarded another block, then from point forward we'll have to take a call. Bu t for now, we have to raise debt in the market to be able to fund our B-80 program of three wells and two workovers and then the pipeline, etcetera.

So what is the net debt right now? Or net cash, whatever number is?

Our gearing is very low at this stage. It is 0.04. We have some debt on the books. All en, would you like to quickly talk about that?

Yes, we have a INR20 crores loan from the bank. That is it.

Another follow-up on DNPL, sir, is there any quantity cap in terms of common carrier, being a common carrier or it can take all whatever we produce?

No, the quantity cap, -- the quantity cap is not related to it being a common carrier, it is related to the asset integrity of the maximum pressure containment capability of that line, which is 90 bars. So at 90 bars it can produce 2.5 MMSCM per day. That is the capacity of the pipeline. If you do hydraulics and you have sufficient residual strength, you could go a slightly more. Right now, because the line is degraded, they are operating it in the range of 40 bars to 50 bars. Allow me to tell you how much is it exactly. Therefore the line capacity has come down to one to 1.2 or 1.3 million standard cubic meters. But as soon as the degraded sections are isolated and new newly laid sections are connected back, then the entire asset integrity of the pipeline would be restored and they should be able to then operate the facility at 90 bar, the pipeline at 90 bar which will take the capacity to INR2.5 million standard cubic meters per day.

So would it be fair that FY27, we'll be able to get it...

Sorry to interrupt you, Nirbhay, may I please request you to rejoin the queue? Nirbhay Mahawar Fair enough. Yes. Thanks.

Thank you. Next question is from the line of Anubhav Goel from Cosma Ventures. Please go ahead. Anubhav, are you there?

Hello?

Anubhav, are you there?

Yes. Hi team. So just one question for 4Q, realistically given the funding crunch, how firm is our plan for drilling wells in Kharsang and PY -1? My question largely is which field will take priority? Is it B -80, because you know there, there could be some chance we don't drill any new well, especially if the workovers don't give us the output we are aiming for in the third quarter.

So priority-wise, Kharsang is paying for itself, so that's not such a big thing. PY-1, the Rig- less Intervention that we are doing we are paying from our own books, so that's also not

a big issue. B -80 is dependent upon the debt that we raise from the market. You are absolutely right, we would drill the first well, test it, understand the deliverability, then go to the second well, and then to the third. Right now, through the reservoir simulation works, we find that all of these three are very feasible to drill with production in the range of 1,000 to 1,500 barrels per well. But that said, we will continue to do the logging and logging is the surest way of understanding , what is the oil and gas saturation in individual startup of the reservoir, and then how should we tweak our next well trajectory to be able to target the sweet spots. But that is the work that we continue to do. No drilling campaign is ever started with a self-doubt in the mind that we will not be able to complete. We will only start the drilling campaign once we have a level of confidence that the results would be there, or be it that if we are targeting 1,000, it could be 700 or it could be 1,400. So that's something that will always be there as because we are talking about stuff which is 4 kilometers below the main mud line. So that uncertainty will remain. But going by the reservoir models that we have, we believe we have in -fill locations for three wells that we'll need to drill. These are development wells.

So sir, for Kharsang, I understand, but for PY -1, since the amount would be high, so it would be fair to say, like if we don't get the results we want by the third quarter, then we might just push up the deadline on that, to be conservative.

No, so PY-1 the dependency is the gas sales agreement. If we have buyers for the gas only then we will drill the two new wells, because we have burnt our fingers, if you remember 15 years ago, these wells came on with 50 million standard cubic feet per day production. Not heard off from three wells in most of Bombay offshore also. But we got that. Then we were done in by lack of buyers and we had to keep these wells shut, and the water overwhelmed the gas zones because there's a basement reservoir, and then we had to re- process and we had to get PetroVietnam to analyze it. They have said that we still can make 15 million to 20 million standard cubic feet per day from two new wells, but we'll drill those only after we have a firm gas sales agreement. But in the meantime, we are doing a Rig-less intervention to increase production from the existing wells. That would be in the short-term, which will be funded from our books.

And sir, post-December for the Dirok…

Just my last question. Sir for the Dirok offtake post -December is it like once a pipeline is completed, then we will spend some time forming contracts with buyers or like, can we expect a quick ramp up?

So then NRL has also been made a re-seller. The DNPL pipeline has been made a common carrier. So technically speaking, therefore, NRL can take our gas and sell it on the exchange, like we are doing in the Bombay offshore in the B-80 field where we are selling gas on the exchange. So it could be done in three days time. We don't have to have a firm buyer if we are going to the exchange. The route, a critical or a credible technical path to the gas, to the national gas grid is all that is needed for us to monetize the reserves. Then we could have intermediate buyers who can charge a marketing margin. But even so, we will be able to sell on the exchange without much hassles.

Got it sir. I'll get back in the queue.

Thank you.

Thank you. We have a next question from the line of Mannan Patel, an individual investor. Please go ahead.

Thank you for the opportunity, Sir. Sir, the first question is on Dirok. So DNPL has been made a common carrier and -- but it's only 25% of that capacity. So I want to understand who are the other players who will be competing with for that capacity? and once that is online, how much production can we ramp up due to this capacity constraint?

So I will not be able to give you a complete answer on what is the locked -in volumes of other operators. Our locked -in volumes are 0.6 to 0.7, sometimes 0.5 million standard cubic meters on a gross basis, which we should be able to ramp up. The capacity wi ll be doubled -- more than doubled from the current 1.1 million, 1.1 million or whatever is that number to 2.5 million. So technically, 50 million to 60 million standard cubic feet can flow additional in that pipeline. So we'll have to see. But as far as w e understand from the discussions that we have had, we should be able to sell all our well stock gas once the pipeline capacity is brought online.

And that should happen by Q4?

December end is what is our target, what we'll see is there are some things controllable. There are some things not controllable. But even the uncontrollable ones, we are continuously talking. So, AGCL, we are continuously in dialogue with them for hot taps, etc. So, we're trying to do our best. Hopefully, by December, we should be on.

Got it and sir, second question is on B -80. So, workover we're planning to do in October once the monsoon stops. So, how long does a workover of the well take, and what kind of production ramp -up can we expect from each well after the -- after that workover happens?

Roughly 10 to 20 days if we -- if we got a pipe stuck in or some fish in the well, etc., there are some problems. 10 to 20 days is a standard time for a workover. We are looking at 500 to 800 barrels per well, and 3 to 5 million scuffs per day from these wells. But that's the range that we are talking about.

Got it, sir. Thank you, and wish you all the best.

Thank you. We have a follow up question from the line of Riddhesh Gandhi from Discover Capital, please go ahead.

Sir, just want to understand that what our understanding was from the last call that you had explaining the HPCL situation was that because you were getting a similar price and there was not going to be too much of a loss you have gone ahead with the resale. Now if you're indicating that there is a 10%, 15% loss because the price of the Brent has reduced and our agreement is strong enough with HPCL that is taken on an as -is basis, then why aren't we then passing on this liability on to HPCL?

Okay. So how do I say this? We have an agreement already signed where we have reversed the sale and HPCL has been very cooperative. They have kept the crude, and we are continuously working with them. We have created additional gantries for offtaking the crude. So there is a very collaborative atmosphere. I don't -- and we would like to preserve it and keep it that way rather than having double barrel guns at each other and fighting. Of course, there would be a conciliation process, but we want it to be very cordial and amicable because they are long -term partners. We are a producer and they are a consumer. So why not?

But at the end of the day, it is a commodity, right? So I mean if HPCL isn't going to take it, someone else will take it. It is oil at the end of the day. So if they are making on an agreement that we have, why wouldn't we just sort of -- I mean, as long a s there was actually no loss, then it was okay, right, because the Brent has run up materially. Now we are saying that if Brent goes down, we're taking exposure, etcetera, shouldn't that be effectively -- and any -- even I mean, they have accepted the oil, right? They have probably tested the oil, right? and so effectively, them being cooperative and sort of holding the oil should not really be -- I mean would be a basic expectation, right, given it is their fault?

Yes. I take your point. I wish it were to be that easy, and you were our lawyer, thought, it didn't work that way. We have had a situation where we have agreed on a way forward. As

far as a responsible corporate like HOEC is concerned, we will not renege on whatever we have agreed with. But going forward, the matter would be in the conciliation , High Court Chief Justice has been appointed, and we are hoping that it would be an amicable conciliation process and then we'll move on. We'll sell the crude and we'll move on. But your points are taken. These things have crossed our minds also and others' minds also. But where we are now is an agreed position to offtake our crude and we are not doing anything different.

Okay. All right. Thanks. That’s all for me. Thank you.

Thank you.

Thank you. We have a follow-up question from the line of Nirbhay Mahawar from N Square Capital. Please go ahead. Nirbhay, are you there?

Yes. Hello. Yes, I’m there. On Kharsang gas evaluation, how fast it can happen, sir? How much time would it take?

Good question. So, we have to lay a 24 kilometers pipeline into the Oil India pipeline, which has been -- which has already been laid. That pipeline, 24 kilometers, we have started -- I mean the tender for the route survey will close tomorrow, and then we' ll appoint a route survey agency. They will do the route. They will come up with all the requirements of the right of way there and then we'll apply to the agencies for the right of way. All going well, we believe in six to eight months, we should be able to get the right of way. If we get the right of use for the way -- for the pipeline route, then it is another six to eight months, it's just a 24 kilometer pipeline to lay. If it were to be an ideal situation, we would believe that by the end of next year, December next year, the pipeline could be completed. Oil India has already led a pipeline from Kumchai fields to Bordumsa and we have to tie into that pipeline at Bordumsa, which will then connect us all the way up to NRL and then to the national gas grid. So that given the difficult terrain and the forest areas to digital pass along the highway and below river, etcetera, we believe 14 to 18 months is the time it will take to lay that.

Sir, post our Dirok ramp-up, would it be fair to assume that all cash flow constraints will be over, which you are expecting by the end of financial year at least?

So we have -- I mean, cash flow constraints depending upon what is your work program and budget. If you're wanting to do more, you definitely need more cash, and we are not resting a B-80, will immediately go to B15. So I'm not saying it's a constraint in the sense that it will prevent us from delivering what we want to do. It will help -- but Dirok will

definitely buy up the balance sheet of the company if we are able to produce all the molecules that are currently locked -in in the wells. But your point is right. We will definitely have a better cash flow situation if Dirok is completely on stream.

Fair. Thank you.

Ladies and gentlemen, that was the last question of the day, and I now hand the conference over to the management for closing comments.

So thank you. I'm very delighted by the interest that our esteemed shareholders have about the prospects of the company and how it is doing and what is the future. That keeps me honest, that keeps us very sharp, and we have a burden that we carry, which is to be responsible to you and to be able to do everything that we can to be able to create wealth for yourselves, and the process, help the energy integrity or the energy security of the country and grow at HOEC to new heights. So thank you very much for your very active participation, and we stay -- hot standby to support you with any queries that you might have. So thank you for that, and we are very happy to interact again next quarter where we might have some better stories t o say or some new stories to say, better meaning -- new stories to say. Let me stop there. Thank you.

Thank you very much, sir. On behalf of Hindustan Oil Exploration Company Limited, that concludes the conference. Thank you for joining us and you may now disconnect your lines.