Hindustan Oil Exploration Company Ltd

Ladies and gentlemen, good day, and welcome to Hindustan Oil Exploration Company Limited Q4 and FY26 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 after the presentation concludes. Should you need assistance during the conference call, please signal an operator by pressing “star” then “zero” on your touch-tone phone. Please note that this conference is being recorded.

I now hand the conference call over to Mr. Cyril Paul from EY. Thank you, and over to you, sir.

Thank you. Good day, everyone, and welcome to the Q4 and FY26 Earnings Call of Hindustan Oil Exploration Company Limited. The company published its results and has 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. Such statements are based on the management's beliefs and assumptions based on information currently available to management. Audiences are cautioned not to place undue reliance on these forward-looking statements while making their investment decisions.

On that note, let me introduce you to the management participating with us in today's conference call. We have with us Mr. Baroruchi Mishra, Managing Director & 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. Good morning, and a warm welcome to all our investors. I thank you all for joining us today for our earnings call for the quarter and year ended March 31, 2026. It's indeed a privilege to address you in my capacity as the Managing Director and the CEO of Hindustan Oil Exploration Company Limited. This is my first call with you, and I'm very excited about this session.

Today, HOEC stands at a pivotal inflection point in its journey. Over the past years, we have systematically built a diversified and balanced portfolio of producing, development and exploration assets across India's key hydrocarbon basins. As a result, we are uniquely positioned with a compelling and rare combination of 4 things: number one, established production and stable cash flows; number two, multiyear near-term development opportunities, meaning it has a very clear line of sight and significant upsides in the reserves.

Our 3P reserves, and you will see those in the slides that have been sent to you are over 100 MMBOE, and strong alignment in the India's increasing focus on energy security. So our strategic priorities remain clear and unwavering.

We want to maximize value from our existing producing assets and that is very important because a lot of that is low-hanging fruits and accelerate monetization of discovered resources.

In that way, we also want to improve or enhance our operational efficiency through technology and disciplined execution. Capital efficiency is key for us.

So we have been joined by 3 very capable individuals. The first one is our CFO, Mr. Allen Joseph Andrade. He is the Chief Financial Officer with 40 years of experience across British Gas and Shell India and a deep expertise in oil and gas joint ventures.

The second individual is Mr. Sanjay Kundu, who is the Head of our Offshore Operations with 30 years of experience spanning Shell and BG across U.K. and India, including deep offshore operations. The third individual is Parthasarathy Bandopadhyay. He is our Principal Reservoir Consultant with 30 years of experience across India, British Gas, PTTEP in Total in Thailand and the World Bank. And of course, we continue to have a very capable individual, Mr. Krishnan Raghavan, who is our Chief Technology Officer, and has a lot of experience across the globe, but also in HOEC and both the Eastern and the Western blocks in India.

So our immediate priority is to embed a high-performance execution culture underpinned by strong governance, uncompromising safety standards and a disciplined capital allocation.

Reflecting on the past year, FY26 was both significant and challenging. We have learned from all the challenges, and we are in the process or we have overcome quite a lot of these challenges.

On the positive side, we achieved continued production from our core assets, albeit that we had some upsets once in a while, but that is the nature of the beast.

Meaningful progress in development planning and advancement of key drilling programs, and we'll talk about those when we talk about on the slides and strengthening of our technical organization, which you just saw, and we have a lot more at the next levels in the organization where we have strengthened capability and competency and progress on infrastructure and monetization initiatives. But at the same time, we faced a number of operational and commercial challenges. I have a few that you probably would know, but even so, let me draw your attention to a few of those.

We had delays in certain monetization initiatives, which essentially means drilling wells, doing workovers, etcetera. That was driven by some of our ability to complete our commercial settlement on the sale of crudes, etcetera, and we'll talk a little bit of those because they are highlighted items. Infrastructure constraint, especially in the East, pipeline infrastructure constraints, and we are happy to talk about those as well. Of course, everybody has suffered with the global energy market.

So, the cost of running your operations, especially if you are relying on diesel and other stuff in the offshore, the prices of those commodities have really shot up. Therefore, you have to bear with some of these. There is a positive angle to this also because the oil and gas prices go up.

But really, that is an area which troubles everybody because the cost of rigs and other things also go up.

Importantly, these challenges have sharpened our focus on risk management, operational reliability and value maximization. We want to preserve value and increase value. Preserving value essentially means creating higher uptimes for our facilities. We are emerging from this phase stronger, more resilient and better positioned for our next stage of growth.

With that background, I'll now take you through a brief overview of each of our blocks. The B-80 is one of our flagship blocks. It has seen a lot of ups and downs. It is -- but it continues to be our most strategically important asset. This field represents a highly attractive offshore oil development opportunity with substantial remaining reserves.

So, just to put things in perspective, we have 2P reserves of 26 million barrels of oil equivalent in this field, out of which we have just produced 1 or thereabouts. Therefore, what remains to be done is right in front of our eyes. And we will not be wanting to go after this very important fields to maximum potential.

So, what we are planning to do, therefore, in this field is workovers. So the 2 existing wells will do workovers. We are also planning to do production optimization by making some configuration changes on the facilities so that we reduce our suction pressure on the facilities, and therefore, are able to pull more gas and oil from the wells. We can flow with less of backpressure. So, we're doing some changes in our compression and what have you.

Additional development works, we'll be drilling there, reservoir management improvements and this is an area which will need a lot of attention and now we have capability, as you saw, a global expert in reservoir management has joined us, and facility debottlenecking.

Long story short, B-80 has the potential to become a major long-term production and cash flow generator, a contributor for the company. The asset also offers significant operational leverage because much of the core infrastructure is already in place, and that is very important in oil and gas development. This also will lend itself to supporting some of our other development programs like B-15, and we will evaluate opportunities to see if we can bring the B-15 crude to B-80 and those kind of things.

So, the utilization of the structure, offshore installation, we’ll try to clock to the maximum. So B-15 is the next one that was awarded to us by the government, and we would like to thank the MoPNG and DGH for imposing confidence in us, awarding this field to us. We have not lost time. We are on a FDP maturation path very quickly. We are looking at expecting now the long leads and in fact, let me take a step back. We're trying to look at a few different… I'm sorry to interrupt, sir. Your voice is muffled a little. Can you come closer to the mic? Still your voice is muffled, sir.

Can you hear me now?

No, still the same issue, sir. Can you come closer to the device, sir?

I am speaking, keeping it in my hand now.

I'm sorry, we are not able to hear you. Sir, try speaking something now. Am I audible?

Sir, your voice is muffled. I'll unmute the backup line. Yes, please start speaking. Yes, I am sorry for the interruption. Audible sir, you may please proceed.

Okay. So I don't know where you lost me. I was saying about B-15. Were you able to hear that? Yes.

Okay. B-15 represents an important future offshore growth project for us and as soon as it was awarded, we have -- or even before once it was told to us that you are the selected party for this, we have started the FDP process. We have looked at 2 or 3 different concepts. We are in the process of zeroing out on the concept that we will use.

Then as a standard practice where you have very clear stage gate deliverables, identify, assess, select, define and execute. So we will be getting the deliverables for the select phase. So, we will have one development concept selected, and then we'll do the front-end engineering design for that, which will take us a few months, and then we will get into FID and then execution. So in parallel, we are also looking at what are the long lead procurements required and working on the reservoir model for this.

Then we have PY-1, as you all know, has been our development project for a very long time, almost 2 decades now. When it came on stream, it was it had 50 million SCFs or 45 million SCFs of production daily. But then stuff happened, the offtake, etcetera, had become an issue.

But now we are trying to work on it again. This field has an offshore platform facility. It has a 55-kilometer subsea line, which comes to our onshore facility, onshore gas processing infrastructure and significant redevelopment potential.

So, we believe that by drilling new wells by reservoir activation, production optimization and by restoring meaningful gas production, we will realize full value from this project. Now this is not just our view. To be able to understand whether this is possible, we went to one of the entities who is producing from a similar basement reservoir, and that is PetroVietnam, and they are one of the largest producers. At one time, they were producing 100,000 barrels from the White Tiger field. So, we went to them and we had an assessment of what is the remaining potential in the

field, and we have very positive results from that. So, we are planning to drill wells in PY-1 as well.

Now Dirok is in Assam, and it's an area of high focus, especially now when there is a lot of shortfall of gas. So, people are looking at why are we not producing from Dirok when you have the capacity to do so? The field has very strong reservoir quality. It has 3 layers or 3 zones, which is Girujan, Tipam and Barail and there's a lot of untapped potential there. We have established production facility, existing market demand, as you know, especially now and there are significant upsides and we'll be drilling wells there. One of the key areas there is the availability of evacuation pipeline infrastructure. We are talking with the government, with the other stakeholders to be able to work on a credible technical evacuation path regardless of who owns these facilities and those kind of things because India needs it.

So, rather than putting on an HOEC hat or an Oil India or any other company hat, we are together trying to see what is possible to do so that we can increase production from this. As we speak, we have -- we are producing around 0.3 million to 0.4 million standard cubic meters per day.

A few years ago, we were producing 1-plus million standard cubic meters from this, and we can still do that because those wells have been choked back. So, with a very short notice, there is an opportunity to increase production from this field.

Then Kharsang has been good news for us. It represents one of the largest medium-term growth opportunities within the portfolio. We have drilled 9 wells, and we are planning to do 9 more.

We found oil. The production from there has doubled. But what has surprised us, not a surprise from an oil and gas sense, but surprise from a commercial sense is that there's a lot of gas, and we have to figure out how quickly to evacuate that.

Then we have the Greater Dirok and Umatara areas, and these assets have important exploration and appraisal upsides. The objective is disciplined exploration with focus on commerciality, infrastructure-led monetization and capital-efficient development pathways, which we will obtain for any oil and gas asset that you would have, especially here because this is a remote area, so you have to be very careful about what development concepts you choose.

Cambay assets in Gujarat, as you know, these have been with the company for a very long time.

The company started in Gujarat actually 40 years ago. We have to revisit some of the philosophies of operations there or development philosophies and the focus would be on workovers, production enhancement, secondary recovery and low-cost incremental production growth.

So last, a few more important items that we'll talk about, and then we'll hand over to Mr. Allen to talk about the finances, and then we'll open for questions. So, on the reserves, one of the strongest indicators of HOEC's future potential is the reserve base. That's a key thing for any oil and gas company.

Our 1P to 2P reserves, just valuing the reserves would stand at USD3 billion to USD5 billion depending upon what oil price we choose. There are substantial upsides beyond the booked

reserves. 1P for people who are new to the oil and gas sector is P90, which is around 40 million barrels of oil equivalent and 2P is possible and probable, which is P50. Globally, all the project FIDs are taken on 2P and are stress tested for 1P and 3P. So, our 2P reserves are 60 million barrels. Then there are substantial upsides for the 3P, which is the P10 reserves, which is around 109 million barrels of oil equivalent.

So importantly, this has been certified by independent agencies, global agencies and management believes these considerable opportunities will improve, which will have a very high recovery factor across multiple assets if we did the things right, we have to get it right and that essentially means we manage our reservoir better. We have all the modeling and we understand we do history match, and we really understand what is the optimum production profile for those -- for these plays.

We have to continue to drill infill wells because if you do a good reservoir management, you know where are the areas of accumulated reserves and you can continue to drill. And then we have to optimize production from the existing wells by understanding what are the limitations.

There is a term called produce the limits and people do this workshops, produce the limit workshops, and those are the kind of things we'll do and Of course, infrastructure enhancement.

So what are our production growth trajectory? So you will have a slide that you'll probably see on the growth trajectory on Page 36. We currently are 1.5 thousand barrels of oil equivalent, plus roughly 0.4 to 0.6 or 0.7 million barrels or 1,000 barrels of oil equivalent locked in because we don't have the infrastructure. Our target is to by 2027, we want to get to 10,000 to 11,000 barrels and then by 2028, 22,000 barrels of oil and then by 2029, to 32,000 barrels of oil equivalent.

These are backed by the drilling opportunities, by the reservoir studies about the potentials and we do hope that we will have support from both from the investor community and from our stakeholders to help us realize these targets, and we'll work together with all of them to be sure that we carry everyone along.

Just the last bit, which is important and which must be on your mind, how will you fund all of this? So, at this stage, allow me only to say that we will fund it both with our internal accruals and with facilities that we'd like to get from the banks to raise capital. But importantly, both of these activities will be underpinned by a very sharp capital discipline, and we will exercise flexibility so that we don't unnecessarily sort of dilute our gearing ratios.

So, with that, let me stop, and I'll hand over to Mr. Allen for the financials. Mr. Allen, as I said, is our CFO, and he will walk you through quickly on the financials. Thank you very much, and I stay open for any questions that you may have after Allen's short speech. Allen, over to you.

Thanks, Baroruchi. I think Baroruchi has set the tone very well for me. It's a short speech. What I'd like to do actually is, can you go back to the second slide, “HOEC at a Glance”. What I'd like to do is give you a brief of what the corporate structure is because this is the thing that determines our sources of income and our cost base.

For instance, HOEC is the consolidated entity. It's also stand-alone in terms of owning participating interest in various PSCs. HOEC has two 100% subs. One is Hindage and the other is Geopetrol International Inc., which owns Geopetrol Mauritius Limited. Geoperol Mauritius Mauritius owns GeoEnpro Petroleum Limited, which has a PI in Kharsang. Hindage Oilfield Services owns the vessel in which our oil are stored.

Quick recap on our financial performance, Market cap, revenue, EBITDA, PAT are all in the negative this time, mainly because of a couple of key incidents that have happened during the year, underpinned by the fact that we had an HPCL issue where we had to account for a sale which was made to HPCL and reversed. Should that sale have gone through, our revenue would have been INR559 crores. Our key return ratios continue to remain 4.5% and 2.5%, similar to what we did in the previous year.

Can we go to the consolidated statement now? I'll run you through the P&L. Yes. So, the consolidated P&L basically reflects the income and operations of the entire group. Just one second.

If you look at the year-end '25-'26 and '24-'25, a few things that have impacted. The performance are related to the decrease in production and the fact that we acquired producing properties from an entity called Adbhoot, where we acquired the 40% share. As far as our profit before tax is concerned, it's again, reflective of the fact that our net income is lower because of the impact of the HPCL sale reversal.

The next one is the balance sheet. Balance sheet growth is steady, again, reflecting the increase in the producing properties reflects the acquisition stake in Adbhoot and the B-80 increase in the participating interest. Everything else is more or less as per our operations, defined mostly by the lower production that we've had this year.

On a stand-alone basis, HOEC has made INR288 crores compared with INR344 crores that we did last year. The INR288 crores after stripping out all the unusual impact. So, the net sale for the year is INR274 cores. Our cost base continues to be strong. If you look at the lifting cost, it's $28.4 a barrel actually, which compares well with the previous year, which is again $28.6 a barrel.

It talks of the strong financial discipline that the company has exercised during the year. One impact that has come in the year is the exceptional item, which is the result of the acquisition stake and the booking of the unusual profit of INR32 crores.

Again, the stand-alone asset and liability statement, nothing much to report except the fact that the acquisition assets have been added, have increased the oil and gas property, producing property base. There's virtually nothing unusual to report as far as the other assets and liabilities are concerned.

On that note, we'll open this for Q&A.

Thank you very much. We will have a Q&A session. The first question is from the line of Harshit Khadka from Robo Capital. Please go ahead.

Thank you for the opportunity. Am I audible?

Yes, sir. Thank you. Sir, just wanted to understand what is the target for net production in FY27? and it will be really helpful if you could give the split by oil fields? and what will be the contribution from Kharsang, B-80 and so on?

All of that, most of it is covered in the presentation slide that we have sent. We are targeting to get to 10,000 to 11,000 barrels by June of next year. Now that is underpinned by our ability to drill a few wells in PY-1, 2 wells and coiled tubing intervention, which is basically saying that you change the production zones and clean up the well, etcetera.

So PY-1, 2 wells we will drill and on B-80, we are wanting to do 2 workovers. Many existing wells, we will re-enter and change the oil and gas producing zones to ones which are more prospective. That will give us roughly 1,500 to 2,000 barrels of additional oil. Then we are also planning to do 3 wells. So that would again add to something around 1,500 to 2,000 barrels.

If we are able to complete all of that by June, then you would be looking at 12 million to 15 million SCFs from PY-1 and you would be looking at 4,000 to 5,000 barrels from B-80. But as I said, there is a lot that needs to be done, especially from the financing perspective and the weather perspective, the availability of the rigs because with the oil prices high, the rigs are in short supply. Everybody wants to drill as much as they can.

Then in Assam, we are wanting to get to 70 million SCFs right now. Our potential is 45 million standard cubic feet, of which we are producing only, let's say, 15 million standard cubic feet because of the pipeline constraints. So, we may not be doing the wells, 3 wells in Assam until the pipeline is available, but we do hope that we will triple the production to 45 million standard cubic feet.

Then in Kharsang, we would be from the 9 wells, and you might have noticed that I'm giving you a range, not an exact number, but that is how I view to understand oil and gas fields work.

In Kharsang, we will be drilling 9 wells. Currently, our gross production is 700-plus barrels or thereabouts, and you know our equity participation in Kharsang, so you'll be able to find that.

So, we will look to double our production in Kharsang again. We doubled it by the 9 wells that we drilled, and we'll try and double that again by the campaign of 9 wells that we are planning to do in this year. So in sum, we are in the line of sight of getting to definitely above 8,000 barrels, but our planning is to get to 11000.

I'm not differentiating it here that the date of 31st of March 2027 because that is not how the oil and gas fields work. I'm trying to tell you before June of 2026 because the drilling goes on all

the way up to May – June of the next year because all the way of May next year, the drilling will go on. Does that answer your question?

Yes, sir. What is our debt and EBITDA outlook for FY27 and FY28?

So, at this stage, I would say let's leave it to understand a little more of how fast we will drill and those kind of things. In the next quarter, we'll give you the details because otherwise, you and I will run the danger of believing in a number and things might turn out to be slightly different. So let me do it next quarter.

Okay, sir. And the last question is regarding...

I am sorry to interrupt Mr. Khadka, you may please rejoin the queue for follow-up questions.

Thank you. We will take our next question from the line of Mehul Panjuani from 40 Cents. Please go ahead.

Thank you so much for the opportunity. Sir, by when we'll be able to get the decision on the HPCL revenues? That is my first question.

Okay. Do you want to go for your second question and then I speak or you want me to first address this?

Yes, sure. The next question is about the connectivity which is pending for a long time. Almost every quarter of last conference -- every conference call of last 4 quarters, we have been getting an update that it will be done very soon, very soon. That's what we have been hearing so far.

Okay. Noted. Thank you. So let me tell you in short about the HPCL crude sales issue. So we have had very constructive discussions with HPCL and thank you to the management and the leadership of HPCL. We continue to have that engagement, and we are looking to an amicable solution, albeit that the COSA requires some processes to be followed for conciliations and what have you. But we are on that path.

As far as the crude itself is concerned, we have reversed the invoice. We have canceled the sale to HPCL and mutually agreed between 2 parties. We have resold our crude to third-party buyers.

The crude is still stored in HPCL. As we speak, we have trucks coming to pick up the crude from HPCL, and we are realizing the sale of crude, but to third parties, not to HPCL.

The only thing is because they are being clubbed, the entire sales proceeds will not come to us in one go. It will be over a period of 2 to 3 months. We are trying to do it ASAP, but given that there's a huge shortage on diesel, etcetera, it is becoming a little bit of a slow process, but we'll catch up very soon. So that is on HPCL. And number two on the -- yes.

Sorry, sir, can I interrupt you, sir? What about when will we realize the revenues I mean...

So we've already started realizing as we speak. Every week, there are X number of 300 to 500 tons or in some weeks, we have also 700 tons. So every week, we have trucks coming in, on some days there may be none at all. But every week, we have trucks coming in and they are picking up the crude from HPCL refinery, and we get advanced paid. So our best guess is 2 to 3 months, we should be able to sell all the crude. Okay. yes. That is helpful. Thank you.

Thank you. The second question was on the pipeline. So may I draw your attention to the graph on Page 21, the pipeline map on Page 21, do you have the slides with you, gentlemen, I forget your name. Otherwise, I can only say that the DNPL line which is 16-inch x 192-inch, that is the line which currently is flowing roughly 1 million, and it has all of the capacity to go up to 2.5 million.

So, we are working with Assam Gas Company and with NRL and of course, with Oil India to figure out how that capacity can be utilized. Now in that DNPL line, there is a patch of 55 kilometers, which needed replacement because of asset integrity issues on that pipeline, maybe it would have been thinning, etcetera.

So that 55-kilometer pipeline has been laid. Now that pipeline has to be connected back to the main line. So, the line is complete, but it has to be connected to this line. Now there are 2 ways in which you can do it. In an ideal world, you will shut down, you will remove all the gas from that pipeline. NRL will bleed off all the gas or use it and then you purge it and then you cut it and connect.

But really, other options are also being seen so that NRL does not have to take a shutdown and that is in process. But in the event that, that is the only thing in the next few months, NRL will take the shutdown and then we'll connect that line up. Once that line is connected back to the DNPL line, we are done. Now there are 2 things there. NRL may still not be ready to take all the gas by their capacity increase.

Therefore, they are also looking very actively and thank you to Oil India and NRL and the team, they are also trying to see if they can have a short connection in their facility to get to the National Gas Grid. As you can see where it's a missing link for connecting IGGL to NEGG. So that bit is a very short 300, 400 meters line, which NRL is already working on. They already have some connections, so that might be activated. So long as NRL is not able to use the gas, they might become a reseller. But I have to qualify this. This is my view. The team is working on it. So this is not about the completion of the line anymore. It is just about how quickly we can tie the line that has already been laid, the 55 kilometer so that the bad patch in the DNDL line is moved and we are able to flow the gas. Yes?

Yes. So sir, when can we expect to sell some gas?

Yes. So that is a question of which I might have an answer, but it may not satisfy you. That is we are working with all our stakeholders to fast track it because this property does not belong to

HOEC. But given what we have been, through there will be an opportunity to complete it in 1 to 2 months, 2 months maybe.

But what is important is where we stand today as a country, there's a huge requirement of necessity to get every molecule that can be produced to meet the requirements. So everybody is well aware of that, and we are together working to a situation where we can unlock the potential of Dirok and produce as much as is allowed in that pipeline, okay?

Thank you so much sir. Thanks a lot for all the clarification. All right.

Thank you. Next question is from the line of Dhruv from EverFlow Partners. Please go ahead.

Good morning, and thank you for the opportunity. So, I have a couple of questions. So my first question is, sir, by when do you expect the national grid connectivity for Dirok to be solved?

And if that happens, what sort of production could we see from Dirok and what are the production levels as of now?

Good question. Let me take the next one, which is in my control. That is a controllable factor.

So we have well potential to produce more than 1.1 million to 1.2 million standard cubic meters.

We are producing 0.3 million to 0.4 million standard cubic meters per day.

So, and the wells which had produced 1.1 or 1, they are choked back during the COVID times when there were shutdowns of some facilities of Oil India and other entities, we were allowed to, we could produce 1.1, but now we are producing only 0.3 to 0.4. Now that is on a gross level.

If we are allowed to get into that pipeline, theoretically, we can go to 1.1 to 1.2. But my view is we might get to 0.8 to 0.9 because that facility might also be shared by other locked in production by other operators. This is again my view, but that's why I need to qualify it.

The second is when can this be done? As I said in my previous reply, there is a huge awareness if that's the right word to use among all parties that India as a country needs gas. So we'll all have to take away our individual company hats. We have to put on the India hat and make things happen. We are doing that. We had multiple meetings with PNGRB, NRL, Oil India, Assam Gas Company, which owns the pipeline and with other operators. Everybody, the alignment of users is there, which is to get it done ASAP. But I can't put my finger to a date. I hope in 1 or 2 months, we are able to start flowing, alright?

Thank you for such an elaborate answer. My next question is for the B-80 revival.

I thought you already asked the second question. But okay. So was the question on B-80 revival?

Yes. It's on the B-80 revival and the production from that, normalized production and how do we see it going forward, specifically for B-80?

Okay. So B-80 is, we have proven reserves, as I said, of 26 million barrels of oil equivalent, of which we have produced just 1. We have 2 subsea wells, which will need workover. It should have been done last quarter. But because of financial constraints, INR260 crores tied up in invoices for our crude sales, we couldn't take that up.

But post-monsoon, we'll take up the workover of these 2 wells, and we have in plan to drill 3 more wells. The facilities are already there, the MOPU, which is the Mobile Offshore Production Unit, it can take all of that gas and oil.

So, and the tanker has sufficient tonnage to take all the production. So it is just about drilling the wells, how fast we can drill it. But nature has to be kind and allow us to drill in November, and there has to be funds to do that. Those are the 2 things and rig availability, which is the 3 things.

But our target is to start working on this completely in real earnest and get everything, the entire work program liquidated by June of next year. Okay?

Thank you so much for your answer and all the best wishes.

Thank you. Next question is from the line of Sangeeta Purushottam from Cogito. Please go

My question has been answered. So thank you.

Thank you. Next question is from the line of Manprit Aurora from Aurora Wealth Advisors. Please go ahead.

Yes. Thank you for the opportunity. Am I audible? Yes you are.

Yes thank you. So first of all, very happy to meet the team management and very positive commentary. So thank you for that. Just a request, since this is our first interaction, if we cannot limit the call.

So you are, sorry, can you speak a bit slower and closer to the mic? Sure. Is it better now? Yes, it's slightly better. Yes.

Yes. What I was saying was, sir, since this is our first interaction, just a request that if you can have a longer call today so that all our queries are answered. But that's just a request. I understand there are other things you might be busy with.

So my first question is, sir, on the crude sale. Now if you can explain a little more. So we have reversed the invoice from HPCL and now we are taking crude from their storage and selling it.

Now the prices that we are selling it are as of today's price, sir, with a certain discount?

Yes. No. So it is definitely not today's price. It is prices or today's prices with significant discounts to the Brent, but almost near to what we sold our crude to. But they realize that then there are transportation costs and other stuff.

So definitely not the 100 barrels that you see today, there is a significant discount to that. For a period of time, it was a firm price, and then we have linked it to Brent so that we are fair to all the buyers.

There's a Brent minus X, and let me keep that because it could be confidential. But we are nearer to what we had sold our crude to, albeit that there would be some additional costs, which will relate to high cost of diesel, etcetera, which the buyers will bear, but we are alive to a situation where there is a shortage of diesel. They are long 6, 7-kilometer long queues for diesel and those kind of things.

So we'll work with our buyers, but we are near about in that ballpark. Now things might change going forward. But as of now, it's Brent minus X. Initial few weeks, we were firm and that we had agreed in our COSA with these buyers, and then it is Brent minus X. X percentage.

Yes. So just a follow-up on that, sir. So do we have to do anything to that oil from a quality perspective because there were questions around contamination and therefore, are we preprocessing and then selling it? Or is it being sold as is and there are no quality checks that need to be checked.

No, they have taken the samples. The buyers have taken the samples. They have analyzed whether they can use the crude. As of now, they have agreed to take it on an as is where is basis without any need for any party, which meaning HPCL or us to do any processing. So, this is being taken by the buyers.

Now how the buyers use it, I would leave that for the buyers to decide. But essentially, one of the ways in which this kind of crude is used is by dilution or for, or technically where you don't see very high temperatures and you do some straight cut products. But let me leave it at that, and that might be hugely technical.

But long story short, the buyers have looked at the crude samples, have analyzed it by third parties and the basis which the COSA has been signed and they are picking up on an as is where is basis. Sir, my second question is on the… I am sorry to interrupt Manpreet, you may please rejoin the queue.

Ma'am, this is my second question. First one is only a follow up. This is my second question.

Please proceed.

So, sir, on the FSO storage that we have of the oil. Now in the past, we have said that, we will let it fill up to 450,000 barrels and then only sell it. But if we have to sell it, like, if it's half full or let's partially full, then we have to take a $2, $3 discount to the current going prices. Now that the oil prices are so high, do we want to wait till it becomes full and sell it or rather take a $2, $3 discount now? and are we able to sell it now, so that we are able to lock in these prices because by the time we wait for 450,000, we may not get these prices as well. So, is there a possibility there? And what's your thought process if you can?

That's a very good question, and I get asked this question very often, including by my Board.

The issue is more technical than commercial. The crude can be sold at Brent. We don't need to discount it. The only thing is you might have to have a tanker, which will get the daughter tanker might have to pay some demurrage to the daughter tanker. The buyer might have to pay some demurrage to the daughter tanker for picking up a smaller cargo.

If you have a smaller volume there, then the dead stock issues become a concern and use. So technically, if we get to 100,000 to 150,000 barrels, it becomes a good parcel to sell. We are at roughly 150,000 plus, it becomes a good parcel to sell. We are indeed looking at options to sell it even now as we speak. But then, we have to get the right buyers, and they have to arrange the right vessels. Let me stop here.

Thanks very much. I will come back in the queue.

We will take our next question from the line of Manan Mundra, an Individual Investor. Please go ahead.

So, my questions are more related to accounting. First of all, we had an exceptional gain this year, fair value gain of around INR32 crores. While I was looking through the cash flow statement, the amount has not been added back -- sorry, reduced from the operational cash flow. So, can you give a reason for that?

No. See, this is a result of the fair value estimate of the acquisition of the 40% share. It is based on the total estimated value of the share, the prospect of the field, as well as the joint venture outstanding that was there in the books. So, all of this, the netting off of all of this has resulted, as you know, Ind AS requires us to fair value the entire stake when there is a business combination.

As a result of that, the amount of INR32 crores has been booked in this quarter. So, I don't know if I have answered your question, but there is no cash flow. This is a valuation gain, which has resulted in an exceptional item, which is posted to our P&L.

Okay. No, my question is related to cash flow only. I know it's not a cash flow accretive transaction. So that is why, it should have been reduced from the profit before tax starting line

item of the cash flow, but it has not been reduced. Even if you look at your September '25 statement, it has been reduced from the profit and the cash flow from operating activities.

Okay. I don't know what the disclosure principle was at that time, but we took a view this time.

While disclosing, we've had a fresh look at the valuation. We've looked at the reserve. We've looked at the future estimate of the valuation and have arrived at this, which has been taken as an exceptional item. I think in our previous disclosure also, we have included that amount as an exceptional item. Like I said, if there is no exchange of cash, the valuation difference is a noncash profit.

Leave it at that, I would suggest at this stage. If you are very free to ask this question in more detail offline...

Happy to explain. Extensive discussion we've had with our auditors, KPMG as to the exact nature of the disclosure. After a lot of technical discussion, the disclosure has been made appropriately.

Okay, my second question is, we have booked the inventory at the closing crude oil price, which is the standard accounting practice that we use for the sale that has been reversed from HPCL.

So, my question was, have we decided anything with HPCL regarding compensation to them since the oil prices have changed considerably from the time that we had sold to HPCL?

No, no. I think that's part of the commercial transaction, which Baroruchi can explain best.

Yes. So, look, the moment we reversed our invoice and we gave them a credit note, there is no further commercial interaction with HPCL. Of course, we have to get into a conciliation process, which is as per the COSA, because it was a dispute and it has to be closed out properly. Now what comes out of that conciliation process is something to be seen.

In the next few months, that will be sorted. But as it stands now, there is no use by any party to anyone. Going forward, we'll see what comes out in the conciliation, and then we'll take a call on that basis. Okay. Thanks a lot.

Thank you. Next question is from the line of Sashwat Jalan from NV Alpha. Please go ahead.

Thanks for the opportunity. So, I just wanted to get some understanding, and if you can help in bridging the gap between the current production, and the production that we are targeting. I think you already mentioned that one of the major pipelines will be from our PY fields. If you can expand more on that. I'm talking more from a horizon of 3 years pipeline that we have mentioned in our presentation. What is the potential we can see from there?

Secondly, if you can expand more on B-80 and B-15 fields. So, if you can answer partly from the perspective, both of near-term FY27 or maybe FY28 and a longer-term perspective, how each field we can see a ramp-up, and what pace we can see that production coming in, because currently, the visibility that we clearly have is from Dirok, once the pipeline facility is cleared.

So outside of that, I just wanted to get bridging how that is going to take place.

No, thank you. So, I've already answered the first part for up till June of 2027, what we will do and what is our target. When I say target, I'm qualifying it, all ducks lining in a row, we'll get to that. We have already said that. Long term, let me answer Dirok and the B-15 because B-80, we've already answered. But let me rehash it once again for you, 3 wells to work over from B- 80, and that could get to a range of 5,000 barrels and 10 million or thereabout of gas or 7.5 million to 10 million SCFs of gas for B-80.

For B-15, the development plan is underway. Now, we will have to take a call on how much we produce the in-place reserves of 15 million barrels of oil equivalent. We have 3 to 5 wells that we might have to drill, but that is in the concept stage, and we'll get back to you at the right time.

We are targeting to 4,000 to 5,000 barrels from that field as well and roughly 10 million SCFs.

Now on B80, B15 is 60 kilometers or 50 kilometers from the existing facility. So various options will have to be seen, whether we can tie it back to the existing facility or it has to be a separate export to an export line and those kinds of concepts are being talked about.

On Dirok, our current line of sight is 70 million SCFs. Our ability or the potential today is 45 million SCFs of gas. We have to do three more wells, and we'll get to 70 million SCFs. But that we will only do, if you can see in the chart on page 21, this DFL to Duliajan, 24-inch 175- kilometer line in 2 to 3 years because that will then provide the complete pipeline capacity to evacuate the additional 35 million standard cubic feet of gas that we could get from 3 wells or 4 wells. Three wells is what is being planned now, but we could do more. Then, of course, we have North Dirok, where we will do an exploration well, very high potential there.

When I say very high, I have to qualify it because we are in an oil and gas field. But what we have seen is once we do a 4,000 to 5,000 meters well, we'll get to a very good oil and gas bearing structure and should be able to produce that. So that will also add to Dirok, which could be10 million SCFs to 15 million SCFs, but that has to be done only after exploration. I'm just giving you a number, which is based on our initial understanding. I'm sure you would not hold me to that because that well has still to be drilled.

Then we have Greater Dirok, which is the next, where we will be drilling wells and will be expanding. So, Greater Dirok is 100% us. So, there is an opportunity to drill more wells. So Dirok's potential, let me put it this way. The existing potential is 45 million SCFs on a gross basis, and it can go to 3 times if all the wells are drilled at the right time.

But again, the key dependency there is the pipeline evacuation network. That will be there truly and completely in 2 to 3 years' time when that dotted line that I showed you is built. Then we are continuously in the game. So these are the things that I wanted to tell you about. Thank you.

Sir, if I can just ask a second question. In terms of split between gas and oil, if my understanding is correct, the Dirok and Greater Dirok is something that will be dominating on the gas side. The crude target that we have mentioned in our presentation as well, it will be largely led by B-80 and PY fields, if there's any correction on this understanding, please?

Largely, you're correct. But look, when you produce gas wells, you also have associated liquids.

So in Dirok, currently, when we are producing 15 million SCFs or thereabouts, which is 0.3, 0.4 MMSCM, we are producing around 200 to 250 barrels of condensate, which is the word that we use for the liquids that come out with the gas. So, when we go to 45 million SCFs, we would be getting around 700 to 900 barrels of condensate, and that is on a gross basis. So it will be material. It is not that you have only gas and nothing else because our last cargo of crude that we sold was at USD109 per barrel. So, although the volumes are small, there definitely will be contribution to the liquids from the gas fields as well, yes?

Right. Sir, if I can just add a follow-up on this. What is our pipeline priority in terms of drilling as far as PY and B-80 is concerned in terms of number of wells that we want to achieve by FY27 in drilling? If my understanding is correct, the numbers that you have shared is something that is achievable FY28, not really March '27.

Yes. So, the two fields will, our initial understanding or initial planning is we'll have two rigs drilling on both sides. There could be an overlap, but we will have two rigs drilling on both sides. That will then offer an opportunity to drill them fast, because also the mobilization and demobilization from one field to other itself will take 25 to 30 days, and that is not any commercial sense that anybody will have. So we'll have two different, and this is again subject to the funds position and all of that.

But currently, we are planning two wells by a rig and one coiled tubing intervention with the coiled tubing unit, which is a small job. On B-80, we'll have another rig, which we will be doing two workovers and 3 interventions. You are absolutely right. March could go to March to May.

That's why, as an oil and gas professional, I'm not too worried about what Allen thinks about the financial year.

I'm worried about when will my rig not be able to deliver. I will not be able to drill or it has to get down and get pulled away. Otherwise, the tow insurance expires, and that is by May.

Therefore, by May of next year, my hope is that we will have done three wells on B-80 and two workovers. Okay? Understood. Thank you. Yes, thank you. Okay. Thank you. Thank you. Yes.

Thank you. Next question is from the line of Anubhav Goel from Cosma Ventures. Please go

Sir, you mentioned in terms of funds, we are looking at internal accruals and bank loans. But at some point, it would be likely we raise funds from shares too, right?

That is a question that I may not be able to answer now. But what I have to say here is whatever makes commercial sense for the management and for the Board and for the shareholders, we will definitely do that. But I will have exceeded my brief here if I told you and also from my ignorance of what equity sales, etcetera, could bring. At this stage, we are looking at internal accruals and raising debts in the market from the institutions, from the banks, etcetera, to fund.

Allen, you would like to say something here?

Yes. At this point, we are looking at various proposals with our people to try and organize for the immediate fund for our capex program. Remember, our operations are run on our cash and to a great extent, our limited capex has been funded internally by cash generation. But like Baroruchi mentions, we do have plans to access at some point the bank loan or the bank facilities to try and take forward our drilling program.

Yes. So on a one-to-one, we can talk in more detail about some of these because that will give you a good understanding of what are our capital raise plans. Be very assured that we have thought through all of these, but I'm constrained by my ability to say more at this stage.

Okay, sir. Even before the war broke out, I think we were facing an issue on sourcing rigs and the right equipment for B-80 drilling. So, if you can just elaborate more on the challenge we have on both these fronts in terms of availability and costing and how this can constrain us? and can these challenges delay time lines, our drilling time lines for 3Q and 4Q by, say, 3 months or 6 months? Just want a sense on how firm are these drilling timelines we have set?

See, drilling of the wells, so let me first answer on the workovers. I think workovers are always a challenge, but we will properly plan for it. The trees which are on the wells, they will need to be pulled up, and we have the original equipment manufacturers or the parties who will do all of that. So, there is always a risk in well intervention. But at this stage, I can't put a number to it or a number of days to it.

But all I can say is we'll go full prepared with all uncertainties that you would see in a workover of a subsea well, including whether the existing Christmas trees will work, can it be used again?

Or do you need a backup Christmas tree and subsea tree and those kind of things. So we'll be looking at all options and be prepared with the Plan A, Plan B, Plan C. So let me leave it at that.

But your question helps me clarify my thinking, and so thank you. Bottom line is the team is very clearly aware of all the aspects and we'll plan accordingly.

Okay, sir. And just one quick question, sir. So, assuming even if the pipeline is connected and the refinery restarts, so my thinking is the refinery will consume it internally gradually over a period of time as the utilization goes up, plus other operators also may get preference as it's a captive carrier. So, it would be fair to assume our increase from 15 million SCF to 45 for Dirok would be gradual and limited, right? Because if you go to 45, that would imply the bulk of the extra 1 million which DNPL will provide will be provided by us.

Yes. So, I have to be a bit selfish. I want all of it, but you're absolutely right. There would be other claimants to it, and therefore, it would be up to Assam Gas Company Limited who owns the pipeline to tell us what is our pro-rated portion. But we do hope that we would be able to put at least 0.4 million to 0.5 million more in the 1.5 million additional capacity that the pipeline has. But you're right, it is not in my gift to be able to say that I will go to 45 million because that's what I want. It is dependent upon what capacity we get. Let me stop there.

Sir, just confirming, 0.4, 0.5 million we can sort of expect out of the 1.5 million being added. That is a reasonable assumption?

So, I'll tell you what, we could always charge you $100 per barrel for asking so many questions, but realize this, our capacity is 1.1 million. We can go to 1.1 million, which is 45 million SCFs.

And we hope in various discussions that 0.4 million to 0.5 million could be given to us. But I will not hold anybody to the sword if they say, why you are not getting 0.5 million or you're getting only 0.4 million and those kind of things. So that discussion is going on, and we will get to a point, and you will know it as soon as we are fine. Thank you so much.

Thank you. We will take our next question from the line of Manan Mundra, an Individual Investor. Please go ahead.

Hello. Hi again, sir. My question is related to the DFL to Duliajan pipeline that is still in progress and it will take another 2 to 3 years. So, I wanted to get a perspective. Once this line is completed, I mean, what will be the capacity at which we'll be able to export the gas?

I've said that already. The target would be 70 million SCFs, but there are upsides from North Dirok and from Greater Dirok.

Thank you. Next question is from the line of Vibhor Talreja from Nest Amplifier. Please go My question is still with respect to the HPCL. We have valued the inventory as of March 31, and we are selling it as of today when prices are lower. So, is there a loss that has to come in accounts as we sell this in the next couple of months? Also linked to it is the fact that the Q4 consol PAT is INR9 crores, and that includes INR14 crores due to derecognition of HPCL revenue because we have valued the inventory at a particular price. Without that, we would have had a loss in Q4 despite higher prices. Just want to make sure that my understanding is correct.

I'll let you answer this and then I'll ask my second question.

So, on the HPCL realization, as I said, it is linked to Brent. Our initial few weeks, we had a firm price. But after that, it is linked to Brent. So, we'll let the year play out or the quarters play out to understand. As I said, 2 to 3 months, and we will know whether we are booking a loss or we are just about getting even.

Realize though that the buyers are going through a situation where they're not getting diesel and transportation trucks, etcetera. So, there is a level of pain in that exercise also, which might show up in some costs, etcetera, which we'll have to talk about. But let this quarter get over, and we'll have a better understanding of what kind of realization we are getting. Let me stop there. So that was the first question. What was the second question, sir?

On the first, the future realization, none of us can predict, but my question was more to the CFO.

But when we have valued the inventory as of March 31, we all know that at that time, the prices were very high.

Yes, yes. So let me just pick that up from where Baroruchi left. The valuation methodology that we have used is a discount to Brent, and we have factored in a downside. So, the downside risk has been covered. As far as we are concerned, we have made a reasonable expectation of what the value of crude will be. So, I think we are protected on that front. Okay? Thank you. And the question was on the… I'm sorry, Mr. Talreja, please rejoin the queue for follow-up question. We have other participants waiting for their turn.

But we can take your questions offline. Look, we are very keen to interact with the investor community. And because we are in service of you all, you are the shareholders, and it would not be proper that we don't take your questions. So, you are very welcome to reach out to us, and we will be able to answer your question.

Very sure, sir, and we'll get in touch. But here's the feedback, sir. You are trying to be open and transparent. As you would have seen that there are 15 questions with respect to HPCL. So maybe the CFO, you can cover that in your initial commentary itself because that is a material event for the company. Then the questions would automatically reduce and we'll save time. Thank you.

Thank you. Next question is from the line of Udya R, an Individual Investor. Please go ahead.

So, I just wanted to know on PY-1, what are the upside potential on further exploration? Are there any further exploration planning over there? Because I think the field has been in non- production state for a long while, are we planning for further exploration in that block?

Very good question. So indeed, we are. The answer to your question is we have one well, which we will be drilling for exploration. Totally, we have 4 wells and one sits midway between exploration and appraisal because we have a lot of data. Two wells are firm and then 1 exploration well is there and 1 well that we are planning to do depending on the results of the first 2 wells. In this campaign, that's the expectation. But yes, exploration upsides will be explored, and we have a plan to do one well definitely.

Just a follow-up on that since...

I'm really sorry, Udya, you may please rejoin. Thank you. Next question is from the line of Raghav Bhutoria from Lindsay Securities Hello, sir. Am I audible?

Oil India had its Investor Day, and there were some comments made that they do not expect that DNPL pipeline will become a common carrier and only Oil India gas will flow through. So, will we be allowed as part of being a joint venture or a stakeholder with Oil India in our gas field, our gas will be allowed to go through that line?

So, I'll tell you what, this is the thing that I answered right in the beginning. We are meeting as individual entities to try and see how best we can use the capacity that is there. It is no more, given the circumstances that we are in today as a country, the paucity of gas needs to be overcome. Therefore, whoever has gas and there is a credible technical path for flow of those gas molecules regardless of who owns it, will be explored and all parties are working towards that.

Indeed, it will continue to be a line which is owned by Assam Gas Company, of which Oil India is a major stakeholder, and it would be dedicated to NRL and all of that. Our only submission or thing is while NRL is revving up capacity by doing upgrades, etcetera, if there is an ullage in that pipeline, others should be allowed to use. So, who owns it is not of immediate concern.

Even if it is for a short period, that capacity should be completely utilized. Okay. Thank you.

Thank you. Next question is from the line of Nishant Maheswari, an Individual Investor. Please go ahead. Am I audible?

Sir, my first question is related with the rig requirement. Actually, ONGC has floated a tender where they are willing to sell the rig, are we looking for that rig, to buy? I mean, will we be participating in that tender? and the second question is, what is the cost of production related with the gas and oil, both offshore and onshore? and the last question is 11,000 barrels, which we have projected by 2027, it is inclusive of gas, I mean, that the gas has been converted in barrels?

Yes. So, the last one is exactly right. It is, I mean, on a BOE basis, gas equivalent of oil. So that is right. Now, about the rig, see, owning a rig is only commercial sense if you have hundreds of wells, etcetera, and you are continuously using it. So right now, no, we are not looking at buying rigs, etcetera for offshore.

Now the cost of production of onshore and offshore, our total opex is around $28 barrel of oil equivalent, and there's a target we will work and try and optimize that further. Offshore is definitely more, lifting cost of offshore crude is more, but then you have also higher volumes if you get things right. Onshore is a lot less. So, Assam is one of our lowest opex per barrel production and B80 is high.

Estimated cost of production per barrel, I think $41, say, $16, what is the...?

Our current opex is on a company-wide basis is $28 per barrel of oil equivalent. Onshore is a lot less. There are other dependencies, etcetera, and we have to take a weighted average. But let me stop at this. Some of it is controllable, some of it is uncontrollable. So, the cost that we pay for the MOPU, I mean, the running cost of the MOPU, the running cost of the tankers, etcetera, the rentals, etcetera, albeit that they are all within the company, they are uncontrollable. But $28 is the overall. Okay. How much we have realized...

Sorry to interrupt, please rejoin. Thank you. Ladies and gentlemen, we will take our last question from the line of Nirbhay Mahawar from N Square Capital.

Would it be fair to assume that there is no issue with the reservoir quality of B80, because whatever contamination has happened, would it be fair to say it happened during the transit of oil?

I cannot say about the second part. But the first part, every second week, we have taken a sample in the last or third week, in the last few months, and we have established that there is zero contamination from the wells.

So, the existing inventory we have got for the new oil we are producing, it will be sold at Brent, almost at the Brent price. Would it be fair to say that?

I hope at Brent-plus, but definitely Brent, we'll go through an auction. On that basis, we sell our crude.

Sir, just one more thing. Whenever we get a better handle on our capex program, we would like to have more clarity, one on the offshore-onshore mix? and second on how will it pan out in terms of oil and gas production?

Most certainly. We'll talk about that, but whether we'll be able to talk about all of it because there are some other aspects other than just the capex of drilling wells, etcetera. But I'll give you some line of sight on this next year, I mean, the next quarter. But for now, I think we can sort of agree to end the call because folks are looking at me and saying you have started loving your voice.

Thank you so much, ladies and gentlemen, on the call. It's always a pleasure, and we stay on hot standby to answer your questions whenever you have them. Thank you.

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