Hindustan Oil Exploration Company Ltd
NSE:HINDOILEXP
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Hindustan Oil Exploration Company Ltd
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Ladies and gentlemen, good day, and welcome to Q4 and FY '22 Earnings Conference Call of Hindustan Oil Exploration Company Limited. [Operator Instructions] Please note that this conference is being recorded. I now hand the conference over to Mr. Anuj Sonpal from Valorem Advisors. Thank you, and over to you, Mr. Sonpal.
Thank you. Good morning, everyone, and welcome to the Earnings Call of HOEC Limited for the Fourth Quarter and Financial Year ending 2022. My name is Anuj Sonpal, CEO of Valorem Advisors, We represent the Investor Relations of HOEC Limited.
Firstly, let me mention a short cautionary statement. Some of the statements made in today's con call may be forward-looking in nature. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. Audiences are cautioned not to place any undue reliance on these forward-looking statements in making any investment decisions.
The purpose of today's earnings call is really to educate and bring awareness about the company's fundamental business and financial quarter under review.
Now let me introduce you to the management participating with us in today's earnings call and hand it over to them for opening remarks. We firstly have with us Mr. Elango, Managing Director; Mr. R. Jeevanandam, Executive Director and Chief Financial Officer. Without much delay, I request Mr. Elango, to start with his opening remarks. Thank you, and over to you, sir.
Thank you, Anuj. Good morning, everyone. Happy to connect with you all on this Q4 FY 2022 earnings call. Jeeva, our CFO and Whole-Time Director, is with me. Valorem Advisors, our Investor Relations advisers, are also on the call.
I hope everyone has received our updated earnings presentation. We've also uploaded it on our website for your reference.
I'm pleased to share that the well D2, which is predominantly gas producing in our VAT block has been brought online and gas production has commenced. After treating the produced gas to meet the specifications of ONGC, it is being pumped into ONGC pipeline to pack the line effective 31st May 2022. This is a 56-kilometer 14-inch line that has not been used by ONGC. Therefore, the volume of gas to be packed in the line through BAT gas will be discussed and agreed with ONGC. Post that, buyer will be formally notified to receive the gas to commence the commercial sales.
Initially, the well will be flown at lower rates. Post stabilization of all parameters, the flow rate will be increased to meet the committed gas volume of 10 million standard cubic feet per day. Our gas processing capacity is about 15 million standard cubic feet per day.
Being an offshore block, BAT development has posed multiple challenges. It has been a difficult journey due to the disruption caused by the pandemic and later the cyclone. Post installation of single-point mooring system and mobilization of floating storage offload vessel, we have started the pre-commissioning of the processing facilities at KGB Offshore Insulation. The facilities include separators, gas dehydration unit and compressors among others. These were installed more than a year back as these equipments were not onboard for more than a year without being used. Commissioning of each equipment took much longer time than expected.
Tuning of these each process equipment are required to be carried out by introducing hydrocarbon by adhering to high level of safety standards. The contractor has to mobilize personnel and staff from the original equipment manufacturers from various parts of the world. Overall, this has taken much more time than initially envisaged.
Subsea pipelines and umbilical systems were installed in May 2021 before the cyclone. We observed some losses of hydraulic fluids in the umbilical joints while opening the wells. This was subsequently addressed with the help of ONGC dive vessel through subsea diving operations. Rectification was successful in respect of D2 well. However, in D1 oil well, after holding the pressure for some time, we observed the loss of hydraulic fluid once again. We are drawing up plans and procedures for mobilizing the DSF of ONGC again to attempt rectification of the umbilical issue of D1 well at the earliest.
Therefore, initial production is only from D2 well. This will be followed by D1 well on successful repair of the loss of hydraulic fluid, which is being attempted with ONGC support.
We wish to clarify that both the wells have demonstrated the expected reservoir pressure while flowing, and we have not seen any issues with the productivity of the wells. The delay in commencement of commercial production from BAT by more than a year has caused severe strains on company's resources. Offshore assets requires safe maintenance, whether it is operating or not.
We had to stretch our limited resources to deal with the unanticipated challenges. Our plan is to remain focused on B-80 as we have to bring it on full production mode.
At Dirok, we pursued a strategy of value over volume to realize a better gas price. During Q4, we continued to supply gas at a premium price to Numaligarh company refinery, Assam Gas Company, BCPL and NEEPCO. Due to this, in Q4, the premium sales constituted 40% of total gas sales, reaching a premium of over $1 per MMBtu to the government notified prices of $2.9 per MMBtu. Balance, 60% of the produced volumes were supplied to oil at government notified prices. However, lower offtake by downstream consumers reduced our average production in Q4 to about 28 million standard cubic feet per day. Overall, Dirok field continues to perform very well, maintaining excellent reservoir performance. Till date, the field has delivered nearly 50 Bcf of gas and 1 million barrels of condensate. The Hollong Modular Gas Processing Plant emerged as the role model plant in Northeast region and safely clocked 1,480 days of lost time injury-free operations as on 31st March 2022.
On PY-1, the Dispute Resolution Committee recommended a settlement package that has been accepted in principle by both HOEC and government. The issue was related to method to be adopted for calculation of royalty. Terms of settlement require both the parties to not disclose its content. Liabilities arising out of this proposed settlement had been provided for in the books of accounts.
Once a settlement agreement is executed and payment limited extension of PY-1 PSC for 10 years will be granted by the government. This brings to an amicable end, a long outstanding issue. This would also pave the way for PSC extension and future development drilling to increase production. Meanwhile, adopt extensions are being granted by the government.
A similar situation prevails in Kharsang, where the issue relates to cost recovery limits as there are differences between the contractor and the government as to the amount eligible for cost recovery. Discussions are ongoing between the government and the operator. This cost recovery eligibility issue is likely to be referred to Dispute Resolution Committee.
In our Cambay assets and the approved field development plans, we will be drilling 2 development wells at Asjol and North Balol each. At Palej, ring fenced PSC has been signed by the JV for [ R2 ] area and has been submitted to MoPNG through DGH for final execution.
In January, mandate-free public hearing was completed as part of environmental clearance process to implement these development plans. In our other northeastern block, Kherem, Umatara and Greater Dirok, there has been further progress in the regulatory process for forest and environmental clearances.
I now invite Jeeva to share the financials.
Thanks, Elango. We report that the company made a revenue of INR 38.24 crores in the current quarter against INR 36.24 crores in the previous quarter. For the year-end, the stand-alone sales revenue is INR 130.5 crores, comparing INR 99.44 crores in the previous year. In the consol accounts, the revenue from sale is INR 42.21 crores against INR 43.93 crores ((sic)) [ INR 43.94 crores ] in the previous quarter. And for the year '21/'22, it is INR 155.73 crores comparing INR 113.86 crores in the previous year.
Increase in revenue is mainly from increase in sales price of gas in Assam and higher realization for condensate due to increase in oil prices. The profit on stand-alone before exceptionally is INR 23.4 crores in the current quarter against INR 17.6 crores in the previous quarter. For the year '21/'22 before exceptions, the profit before tax is INR 70.19 crores comparing INR 37.47 crores in the previous year.
However, after adjusting the exceptional items, the profit for the period after tax is INR 35.83 crores, comparing INR 65.06 crores in the previous year. In the consol accounts, the profit after tax is -- tax for the current year is INR 19.95 crores against the INR 53.46 crores in the previous year. The exceptional items represents INR 28 crores related to settlement with the Government of India on royalty issue to secure 10 years extension of the block PY-1.
Provision has been made for an arbitration report against the company for INR 6.47 crores. For the [indiscernible] block CBOS1, we have no amount is carried in the books, which was surrendered much, much earlier.
The total expenses of stand-alone including the DDA is INR 20.85 crores comparing INR 20.59 crores in the previous quarter. For the year '21/'22, the total expense is INR 77.12 crores, comparing INR 73.79 crores in the previous year.
Operating costs are not linear to increase in revenue. However, the statutory levies such as the royalty and cess are at [indiscernible]. In the consol accounts, it is INR 36.34 crores comparing INR 28 crores in the previous quarter. This increase is due to operating cost of floating storage offshore, here effective to its commissioning on 26th of December 2021 and the depreciation thereon.
Operating cash flow stand-alone for the year is INR 79.58 crores comparing INR 52.8 crores in the previous year, which do not include the working capital changes. In the consol account, it is INR 79.3 crores comparing INR 54.24 crores.
Outstanding finance loan as on 31st March 2022 for the group is INR 329 crores. And the average financing cost is less than 9% with the gross currency swap. The total investment made in B-80, including the assets were captive use through its subsidiary is INR 955 crores. Delay in commencement of production from B-80 can't sustain on the cash flow of the company.
As stated by Elango on commencement of production from B-80, we would be able to file the working capital issues as well as liquidate the debt at a faster mode than the tenure accredited to the banks. [indiscernible], only about 23% of the investment in oil and gas assets and revenue mode and the balance would move to revenue mode on commencement of B-80 production. This will enable the wholly owned subsidiaries on revenue mode and sustained on their own.
We submit that better numbers could be reported on the commencement of production from B-80, which will make the new beginning, and our focus thereafter would be on the other dormant assets in the company in Western region as well as PY-1. Thanks, and back to Elango.
Thank you, Jeeva. Anuj, we can open the forum for questions now.
[Operator Instructions] The first question is from the line of Akshay Satija from Alpine Wesco.
Sir, in your earlier presentations, you've talked about B-80 gas production could go up to 15 to 23 MMSCFD a day. Now our current contract is 10 MMSCFD. So by when can we expect this 14 -- this number to go up to 14 to 23 kind of levels?
Yes, we've never mentioned anything beyond 15 million cubic feet as far as B-80 production is concerned. We are -- the sales volume -- what we have committed is we expect the production to range between 12 million to 15 million cubic feet. We will have our internal consumption of gas. So we have safely made a commitment of 10 million cubic feet.
We know that demand in the region is there, and we have the ability to deliver additional volume as well. But overall, limit is 14 million cubic feet per day. Out of that, internal consumption could vary between 2 million to 3 million cubic feet and the rest will be sent on sales.
Okay. So is it safe to assume in the 10 million to 12 million cubic feet around that level itself?
Yes. At this stage, it is fair to assume 10 million cubic feet, that is what we have committed.
Okay. Sir, on second question on the B-80 thing. Earlier, our stance was that we will share our 20%, 22-odd percent government -- with the government and we'll manage our production accordingly. Right now with oil prices going above INR 100 -- $100 per barrel, does that stance stand because at those prices, our production is going to be very low from B-80, if we consider the B-80 government share.
I think we wanted to flow the well to its optimum level. And in a way that if the price rise goes, we have to share more revenue with the government. But at the prices of -- if you assume around, say, average price of about, say, $85 to $90 over the period and we cannot take an operation prices above 1 month and say about $80, $90, we will be sharing with the government, which is in the order of 1/3. It should be around 33% to 34%, excluding royalty. With the royalty, the government is more beneficiary to the extent of around 45%, the balance [indiscernible].
So we have produced more even if we have to pay more to the government because earlier our stance was even only up till a point, like 20%, 22% will be shared.
Yes. The initial operation, which happens, we expect the oil price close to $120 or in the pricing for the whole year or something. But we cannot think to the minimum. We have to flow the well to an optimum level. But optimum, we will continue to maintain. If even you could be some more share to the government.
Okay, okay. Sir, also earlier point, we had earlier also indicated that from D2 well, our production cap varies from 16 to 23 ml this year. We did commitment of volumes, but there wasn't...
No, we have never mentioned that. I'll clarify it, we never mentioned anything beyond 15 million cubic feet from the gas and that has been consistently 15 million.
The next question is from Varatharajan from Antique Limited.
Am I audible? Hello?
Sir, your voice is coming a little muffled. May I request you to speak through the handset?
Is it better now?
Yes, sir.
Yes, sir, I would like to know at two questions. Three questions in fact. B-80 now I would like know what should we take as a commission for oil? Should we take -- pose it as a window of using the answer which you have given.
As I said in my opening remarks, our -- the rectification plan that we are drawing up for D1 would require the help of ONGC's dive support vessel. But these actions does not involve lifting of any heavy equipment. Both can be performed during this weather window also. So it doesn't have to wait for monsoon to be over. It can be performed. Obviously, we would look for the right condition before deploying the rest.
Fair enough. Secondly, this premium in the Northeast gas of $1, now that gas prices are 6.1 so we should continue to take $1 kind of a premium or higher than that or lower than that on the 40% of the volume?
Yes. You can continue to take that $1 premium over the current price of 6.1, yes.
And volume should you take it at a normalized level or...
The volumes are also quite sensitive to the price. What we have seen since April is there was a difference in the offtake in the volume. But it is again picking up a bit. So there is a sensitivity linked to that. But mostly in Northeast, what we are saying is it's the shutdowns of the consumers plan also determine that. But there is certainly a sensitivity. But our contract is tight, meaning anyone who wants to meet their big demand approaches and we deliver the gas at the premium over the government notified price that has been established.
Sure. My final question on this PY-1. So now obviously, we required to do additional work and all that. And what is the kind of production we can expect? And the existing offtake contract with deal, does it stand? Or is there a scope for you to enter into a new contract in terms of the work?
The existing contract with gas GAIL is very much valid and running. We've actually recently restarted the production, the small volume from PY-1, just a couple of weeks back. And meeting the GAIL specification, that is running.
As far as the increasing the production from PY-1, as you said earlier, would require drilling new wells, for which all the technical work has been completed. We have initiated the environmental player in process, and this will require a lead time of around 9 to 12 months in terms of recurring or the tangibles. So the drilling activity can happen in the early part of 2023.
So post that, what is the kind of production we should take so -- we should go back to 10 to 15 number of [indiscernible] or lower than that?
No. I think before we faced the problem with gain on the specification, we are producing a small volume of roughly about 1 million cubic feet per day. That is what we have thought now.
Fair enough. Just a clarifying on this entire PY-1 proposition, given that your price is like a fixed price would be -- would it even make sense for you to invest significantly to actually produce more at those prices?
I think our first priority is to resolve the outstanding issue with the government related to the royalty calculation, which has been resolved now. And this is the first time the government has through the dispute alternative to the dispute resolution mechanism has come to a settlement with any oil and gas company. So that way, we are happy that we didn't have to go through the normal legal route and reach a settlement.
The first priority is to secure the PSC extension that should happen. We have now restored the production to a very small level. Overall, I think we've discussed this earlier also. The way we see PY-1 is there is unrecovered -- there's a huge basket of unrecovered costs. And we have a pretty developed infrastructure. So the investment is that of a marginal nature that where you drill the well, as long as you are able to recover the well cost, there's no other investment is required.
Pricing is -- once you commit to a price, you have to live by that contract. That's what we will do. But overall, our plan would be to revise it, but timing of it will definitely in terms of priority, as I outlined, it would be getting the B-80 on full production mode first, parallelly getting ready for investment in other blocks. But do the actual investment only after we are not fully stabilized.
Sure. And if I can squeeze in one more question for an update on PY-3.
PY-3 status quo remains -- there is the new development plan. We have not seen any activity on the ground. And we -- our attention has been on B-80 only.
[Operator Instructions] The next question is from the line of Abdul Karim from HDFC Securities.
Coming to the Kharsang project. Outstanding issues related to the cost recovery limits to be referred to the Dispute Regulation Committee. And the second is the 18 numbers of wells to be drilled in the near future. So could you update on this?
Yes, first is in Kharsang, we are -- we participate in Kharsang through our subsidiary entity, Geopetrol, we have a 25% stake in this. We are a nonoperator there. We also have a 50% ownership of the operating company GeoEnpro. So all Kharsang matters are dealt by the operating company, one.
And like every 3 mail block, there are a lot of legacy issues associated with these production sharing contracts, which were signed 25 years back. When the timing is coming up for extension government is really putting a pressure, pay up whatever was put as the demand by the government, pay up that to get the PSC extension.
So in this case, unlike PY-1, where the issue was -- at least there is a clarity in the different positioning taken by us as the contractor and as the government which relates us to the way the royalty should be calculated. In cost recovery, it's a much more complex area where which cost will be allowed and beyond which point, et cetera, et cetera.
So what we have said is as a nonoperator, our other position has been out of the total amount being demanded by the government, certain portions, which can be agreed and the remaining portion can be referred to the Dispute Regulation Committee. But the decision has to be taken jointly by all the JV partners. But I can tell you is there's an intense discussion going on between operators and the ministry DGH. By next quarter, we should be able to provide a more clear update on that.
Okay. And the second question is, you have increased your loans from almost in double. So what is your future plan regarding the loan and the long-term loan borrowing?
We look at the total investments made in B-80 is about INR 960 crores. Out of that, we have taken about only 1/3 is the loan. The balance 66 is internal funding. If the B-80 commenced the production, then we would be able to repay the loan quickly thereon. Then every assets, we don't want to borrow more than 1/3 of the CapEx required. So our major investments, next we are looking at only from PY-1. So we will be able to raise some element of funds actually, which may be either a debt or equity as the case maybe. We have no plan at the moment, but we are banking on the B-80 revenue. If everything subject to the commencement of production and the price holding it, we would be able to have a cash flow, which is in the order of around INR 500 crores, we should be able to meet with the requirements.
The next question is from the line of Rikesh Parikh from Barclays.
Congrats on getting the B-80 operationalized. Sir, my question is on B-80. With this new development, sorry, if I sound [indiscernible] I might not be aware of it. But it is -- what is the kind of complication in PY-1 well? And what are the current volume? So we had an estimated 8,000 barrel of oil equivalent per day. So with only D2 operational, what should be the kind of oil we can expect for the -- to be operationalized -- which is operationalized as such?
The numbers that we have indicated as a total for both wells put together is somewhere between 7,500 to 8,000 barrels of oil equivalent. Out of that, the oil component was somewhere between 4,500 barrels to 5,000 barrels and the gas component constitutes that 2,500 in terms of oil equivalent in terms of gas as such. Right now, the gas that is -- the well that we have brought our production is predominantly gas. It also produces a little bit of oil. We've just started a few days back, and we'll be monitoring the volume that comes.
Now whatever volume -- little volume that we produce along with the gas, we've already -- we're able to export that into our FSO for storage purposes. So we have done the transfer of this oil in FSO. Through that, we have tested the whole system as well.
When the most -- so if the total volume would really depend on by when we are able to bring D1 into production. At this stage, we don't have a specific date to commit. And all I can assure you is we'll make every attempt to bring it on stream as soon as possible. As I said, this will require underwater operations involving ONGC vessels.
So as well as we bring it on board, we will make an announcement about that. So until then, it is basically the gas well, as I said, gas well from a revenue point of view, what you need to consider is 10 million cubic feet. Right now, we are producing at a low rate, but we will be able to ramp that up to ensure a sale of 10 million cubic feet.
Okay. And second thing is regarding the Dirok fill, we have seen a reduction in the offtake over there. So do you think that the higher prices of offtake is lower over there and even over the existing partner, Oil India, who is being the first consumer. So they are taking on the lower size as such? How should we take it as such?
Yes. You know, I think you're right. There is 2 factors that are at play. Number 1 is the -- obviously, all our customers have got access to Oil India gas as well as that of Dirok gas, all the customers. So their first choice would be to exhaust their volume from Oil India, which is always at a lower price. But we have been able to successfully position ourselves as a peak demand supplier. So every company has -- with every company, we have managed to hire the contract, and they know there is -- whenever there's a demand increase in their plant, we are there to supply them as well.
So the uncertainty, not only in Northeast, we are seeing at all over India. The Indian consumer is very, very sensitive to the gas prices. So there is a certain percentage of that is strings by the price institute per customer. That is one.
The second thing is what we also observed is whenever there is a shutdown of a major player like BCPL or NEEPCO or any other major player, there is a straight away offtake gets reduced. So I think what we are seeing is we've seen in the current quarter also, a slightly lower offtake, but it started picking up recently. I'll be like really wait and watch.
The third development is, earlier, we were the only private supplier in Northeast market. Right now, there are other couple of players also coming supplying in different regions, both Vedanta and Oilmax. So all this will outplay and we'll watch all these developments before we make further investment in drilling additional well. So good news is our wells are producing very well, and we feel that the oil is of excellent quality. We'll be able to meet the demand of the market but it is very difficult for us to generate demand in the market. We will play to the demand of the market.
Sir, one more additional question related to the previous one. So since I understand from the fact that we have got an approach in the foreign department for the increasing the output. So let's assume whenever it is we increased from 35 MMSCFD to 50 MMSCFD of gas. Would we be able to have a captive demand for that for the additional ARPU?
What -- the way we are planning is, one is the Dirok field development plan Phase 2, which has already been approved, really involves 2 components. One is to drill additional wells to increase the production. And the other is to create our own infrastructure, which is the pipeline infrastructure, which passes through the forest land. This is the second component.
So we are keen to really continue with the pipeline infrastructure, which will help us to directly deal with the customers, multiple customers and have the flexibility. Also, derisk our dependence on Oil India's very old pipeline as such. So that's how we see that. So we have got the stage 1 forest clearance. Stage 2 should be coming through.
As far as drilling a well, there are 2 ways of -- we have already demonstrated. The existing well can deliver and delivered up to 42 million cubic feet per day. That's our first milestone to ensure that the existing wells, we deliver the market demand. If required, we can always undertake our core operations which will involve increasing production from existing wells. If not, we have always have the flexibility drill additional well. So we will take this investment decision in a phased manner but we'll always be ready to meet the demand of the market.
Now your second part of your question, as far as the demand is concerned, we expect the major demand to really come in Northeast once the Numaligarh refinery expansion project is completed, which I believe is on track. That project completion would significantly increase the demand from a premium customer like Numaligarh refinery.
[Operator Instructions] The next question is from the line of Sunil Jain from Nirmal Bang.
My question relates to B-80. Regarding D1 well, can you say how technical difficulty -- technically it is difficult to correct the problem or anything on that? Like in this well, you are sure that we'll start production?
It is technically difficult to answer this question seriously because we have in consolidation with the OEM and the experts came up with a solution that worked in D2 but they did not work in D1 after pressure was held for some time, but did not subsequently work. So we are consulting networks to make definitely one more attempt.
And what is the good news is, earlier we thought certain type of operations cannot be undertaken during the monsoon period. But the nature of solutions that we are looking at can be executed during this window also. So that is our effort. It's very difficult to really predict the outcome.
So if suppose given this corrective action, what you are planning, it doesn't work, which has not worked in the first attempt. So doesn't work, and what would be the course of action thereafter?
So the course of action is to continue the production from D2 well as well and take an overall review of everything subsequently, which would involve lifting certain equipments to the first phase and rectifying it. As you said, there is no problem with the wells per se, there's no problem at the mobile offshore process plant also. To a layman example, which is like the TV is functioning well, but the remote alone we are having a problem.
So we don't see it as a major issue. At the same time, if the whole umbilical system need to be lifted, that can only be done through post monsoon. But please give us a couple of -- I mean, some more time to make an -- make another attempt as it can be done during this period. And as well as the results of that, we will compete. Time is only a factor here.
Yes. And sir, another question related to this is that, what is the fixed cost which you need to pay as a cash outside per month during this period? And what could be the capital cost, which you may be incurring on doing all this activity rectification?
So you are talking about the future CapEx for this repair growth?
Yes.
That should be about less than $400,000.
And the running cost of gas operations is -- will there be government this royalty or government on -- because gas, I think is not attracting that.
The gas, we have to pay the royalty. And this is being a revenue-sharing contract, whatever the revenue share actually in proportion towards whatever the quoted rate for us. So roughly about 55 divided by the million, that is about say 54%, multiplied by the proportion to the $1 million to the revenue. So roughly around, say, if there is my revenue is $100, I'll be paying to the government, which is in the rough, say, [ $20 ].
Okay. And apart from that, cash running costs will be for the whole -- what was earlier you had predicted around $15 per this thing or it will be less, sir?
What is happening, it is more of a captive plan for us, only the 40% we have to share with others. So if you look at an open and transfer model as such, we'll be having our cost is about, say, $100,000, $135,000 a day. So it would be more economical and meaningful if we start the oil will also on production.
If you start only with the gas, we will be making some money as such. But our all over MOPU and FSO would get paid. And we'll have still some money, a small amount of money, which we can share with the government and to the partner there. So we have full production from the field vendors.
Next question is from the line of Riddhesh Gandhi from Discovery Capital.
First, congratulations on starting off with the gas well. So wanted to understand, given the now reasonable amount of free cash flow, we're going to be generating out of Assam and the cash block and [ at present ] the oil block. If you could outline to us the future plans you have with regards to sort of -- optimizing with the production out of all of our assets given the current oil and gas prices and the environment right now?
See, we have to come out of the working capital issues at the moment. That is our first priority. Once that is done, actually, the next priority is to bring down our loan in a manner that it is not staying at the daily moment as of yet though it is about less than 9%. Then our -- you look at now the Dirok, it will be a self-sustained unit because even if you wanted to ramp up to production of 55, that can be done with the existing wells, it is a small capital involved.
Our major capital expenditure would move to PY-1 that will be our next priority. And parallelly, we will be moving some investments to the Western region. This is the way when we have a free cash flow that is our priority. First is the working capital, come out of it. Second, pay off some debt. And the third one, put some money on to the PY-1, redevelopment, we call it, and then to the Western region. This is our priority of expenditure.
Sir, and the other question was with regards to -- do you see any risks with regards to the production from D1? Or is it just a question of this timing as opposed to effectively seeking any risk could be actual production outcome?
That one thing I would like to submit, we are all talking about subset base. So this will always entail with some risk. And we cannot say it is a risk-free by any means. With a caveat towards having a good technical team and their understanding is good, and we are able to execute the project well, these are all already approven blocks and having the oil and gas established in the field, and we will be able to produce. That is our confidence level. But at the end of the day, the risk is there with all the blocks, which were being operated under -- because the production comes from the subset.
Got it, sir. Sir, last question is with regards to actually -- I mean, when do we expect the commercial production to start from, I mean, D2?
Yes. As Elango already explained, now the land packing is going on, we are going to have a discussion with ONGC. Once that is started out, because it is a long line that is after that. The moment we commercialize the sales, we will inform to you as a matter of our compliance.
But is that expected to be -- is it a question of -- I mean -- is it 2, 3 weeks? Is it a question of 2, 3 months? How should we be looking at it?
It's not in months, but it should be in weeks.
Right.
But is this an agreement with -- I mean, we need ONGC to sign off on? Or I mean just wanted to understand the reason for this and any risk associated with this.
No, no. This agreement is -- has been finalized as far as the overall transport agreement has been finalized with ONGC. There are no issues around that. We just need to take their help in how we could expedite this packing and what can we have. That alone needs to be discussed. So we don't see any issues with this on that.
The next question is from the line of Rohith Potti from Marshmallow Capital.
Congratulations on beginning production from B-80. My first question, again, is on B-80 itself. So you mentioned that it will take some time to ramp up the production to 10 MMSCFD. And you also mentioned that the pipeline is a little old. So is there any risk to the pipeline itself or it's already been tested and you don't see any risk to supplying of gas from B-80 to wherever the customer location is?
No, we don't see any risk as far as the pipeline is concerned, this is a well-maintained pipeline of ONGC. What I really meant was ONGC had not charged this line with gas in the past because one of their field was not ready. Otherwise, it is a very, very well maintained pipeline, there's absolutely no issue. What happens is when you initially introduce the hydrocarbon in a line, you need to pack the line before it -- please remember, from B-80 to Hazira, the distance is roughly 150-odd kilometers pipeline. It has got 2 sections. One is a section up to what we call WO platform of ONGC, which has not been charged with gas in the past. So first time gas going into the line is from B-80. The other section of 100 kilometers is what is one of the largest pipeline network, which delivers gas to the HVJ pipeline of GAIL.
So there's absolutely no risk on that. It is just basically reaching an agreement with ONGC on how much of B-80 gas could be packed in the line and seeking their request to place some of their volume also here so that we can monetize quickly. And we do expect ONGC to fully cooperate with us as they've always been during all these challenges that we faced.
Okay. This is very helpful. Sir, just a follow-up. So you mentioned in your comments that it will take time to ramp up to 10. So is it because you want to test our systems properly to ensure that there is no loss of pressure like last time and then you'll ramp up. Is that the reason?
Exactly. We just wanted to ensure the well is broad slowly online and testing each of the subcomponents as well as for ONGC to receive, it starts with a slower number and go up. We don't see any problem at all in the well's ability to deliver the 10 million cubic feet. It's just a subset system needs to be taken at pace safely.
Okay. So basically, what this means is it will take a couple of weeks -- a few weeks for commercialization with ONGC? And after that, how long does it take for you to -- I mean it will be in this quarter itself that we'll reset in MMSCFD. Is that the right thing to think -- is that the right way to think about it?
Definitely, definitely.
Okay. Perfect. So my follow-up question -- Last question is on Dirok. So when Jeeva sir mentioned the priorities for HOEC, so this year, it looks like primarily, we're looking at managing the working capital and reducing debt. And then he talked about the Western and PY-1. But so what's happening with the Dirok, the alternate line that the pipeline that we're planning today? So is that below the priority -- below PY-1 and Western region in terms of priority list? Or is it the next thing that we'll be looking at in this year or the next year?
What I said was that our people have done -- considering the reservoir performance, we have 6 wells in the field. The 6 wells can itself a little workover can meet the demand therein. So that's the reason there is -- even if you infuse the capital there by drilling additional wells, there is -- you need to have a demand-to-supply for the trade. So that is the reason when the existing wells can do it, these capital can be deferred till the demand is built up. So that will take about a year or so, but 1 or 2 years, then drilling those wells will not take more than 3 to 4 months. So we will be able to quickly ramp up the production if required. So -- but the pipeline is a small venture, smart capital items, which is our share is only 21%. Other partners are willing that can go -- that is not a very high capital intensive project there.
Okay. Perfect. So just to confirm, so the existing wells can produce -- it has produced a peak of 42. But can it produce 50, 55 or for that, we need additional wells?
In terms of workover, our geologists are confirming but they will be able to go up to 50 comfortably.
The next question is from the line of Tejas from Unique Stock Broking.
Standard for general complaint versus what we have, there's no communication from HOEC [indiscernible].
So sorry to interrupt, there's a lot of echo coming from your line.
There is no confirmation of your lines in terms of any communication to the exchanges for the gas production or anything. Now you're saying 30 years the production started for the gas of your connected surprise after the result mix, it jacked up by 15%, 18%. But market is not aware. You are declaring it today that 30th, the thing has started and the price has already jacked up. Even whenever we complain or whenever mail [ Josephine ], there's no communication at all saying we cannot disclose what is happening. There is absolutely no communication from your side coming. If you can throw some light on that.
Yes. First of all, just to clarify, the HOEC specification of gas and injected into ONGC pipeline on 31st May, not on the 30th. 30th we declare the result and 31st May, only we could achieve the specification. Until then, it is about commissioning the system. There's no commercial production.
In fact, we would have ideally liked to have commenced the commercial sales and made the announcement. But having this call, we thought we should disclose the current status as such. Now for us, the 2 things are important. One is to comply with all the requirements of disclosure as and when a major event occurs, which in our assessment, it has a clarity and certainty. That is one. We have never diverted from that connection. Obviously, in calls like this, which we hold at every quarter, we are able to explain in much more detail, clear the participants, please understand, these are technical in nature. And as long as I have a [indiscernible].
So sorry to interrupt you. [Operator Instructions].
So when we are -- what I was saying, and this is -- I meant it for every other audiences and participants who may have this issue. So what we thought was whenever we are certain about certain outcomes, then we would be -- it is easier for us to communicate that. When we ourselves are not very certain, we just focus on the operational matters and ensure whenever there is a -- we achieve -- complete an activity, we make the disclosure, and we will continue to do so.
Agreed. But I request even at the time of Valorem Advisors, there was your 31st last day, the management backed out and there was a notification saying production will not start because of whatever delay and the price spend and the management did not come for any explanation at all. Not on anything. So even at that time, that's a lost money.
I respect your question, but this is -- you're not dealing to the management, which you'll ever back out from anything. We are very determined to meet the -- all the promises we made, we are doing our very best to achieve that. And on communication, I told you, we would -- whenever we have the certain information, we will definitely make the announcement.
[Operator Instructions] The next question is from the line of Vaibhav Badjatya from HNI.
Sir, I just have 2 questions. One is on Dirok field. So what is the minimum production we'll like to continue given that there might be a possibility that if production falls below that level, maybe because of the demand level or something? Coming back again to the optimal production might be difficult due to the nature of the field. So what would be the minimum production that you would like to continue at Dirok? That's the first question.
Secondly, on B-80. So is it the problem that B-80 faced as anything related to the frustration in the production from the wells itself? I mean, the frustrating pressure or frustrating production, the well created this problem? Or is the problem related to the equipment itself or any other services related to the equipment?
Okay. I'd say, clarify, there is absolutely no problem with the well, I'd say. In fact, we also tested the D1 well for a very, very short period and brought the oil to the surface also. So we don't see. And our technical team is able to monitor the pressure in the well even now remotely. So there's no problem as far as the well flow or productivity of the well is concerned.
And where we -- each well, I'll try and explain. Each well, to open the well, it's kind of a remotely operated system. Please understand these wells are created at 80-meter water depth. And you have what we call the Christmas tree and below the water. It is very similar to the deepwater developments, that's what you see. So everything is operated remotely from the surface. To open the well, you need to pressurize what is called the hydraulic actuator line through a hydraulic fluid. I emphasize it is a hydraulic fluid, which is water-based chemicals. When we pumped that into this tube, it was not holding -- so without that pressure being held, the walls will not open -- or will not be kept open. We were able to open, but we are not able to keep it open. Just to help you understand, it is like a window beach-facing house, you can keep a pressure on the window because the wind is coming from the other side. It's a similar analysis.
So we have no -- so we are able to open. We, in fact, flowed the well. Even also for a very short period. But then the pressure losses, they well will close itself. This is the system. So our attempt would be to just go and see whether this pressure loss could be identified under 80-meter water depth. This cannot be performed by normal divers. It requires what is called a saturation divers. Fortunately, ONGC has vessels and divers, and they've been very, very helpful among all their priorities to lend these vessels to do our operation. So we are also consulting them. This is -- I hope I'm able to clarify a little bit, but this is what the nature of the problem.
Got it. Understood. And the second question on the Dirok, if you can answer, that would be...
Yes. In Dirok, what we've seen, as you've seen the number in this quarter, which is about 27 million cubic feet per day. This quarter also, we saw some lower offtake. And April will be the first quarter at the new price level price point. We saw a lower offtake, slightly lower offtake in April, but people are coming to realize this is the price of which we will get. So we have seen recently, just in a couple of -- in a week or so demand picking up. So I would expect the average we should be able to definitely achieve about 25 million cubic feet, if not more.
Yes. Sorry but my question was not around what we can achieve or what. So basically, generally, in some of the periods, there are issues that if the production falls below a particular level, then it becomes really challenging to bring it back to the old level. So I just wanted to understand what is that level in Dirok?
We have no issues of that kind as far as Dirok is concerned. We have the flexibility to take the production as you have mentioned 42 without anything million cubic feet per day and this will flow up to 50 million cubic per day. So we are just positioning ourselves as long as the demand is there, we are able to quickly ramp up or ramp down the production and the reservoir is good quality reservoir, we see no problem at all.
The next question is from the line of [indiscernible] Shah from Visa Securities.
What is the Indian value for gas from D2, which will be there for 10 million cubic feet, what you are saying? And expected level of profits out of that?
Can you repeat the question?
From the D2 well, the expected sales is 10 cubic feet or 10 MMBtus what will be the Indian revenue that we are targeting out of which? And what will be the profits coming out of that? Because you said some 100 is the cost of 20, what you will need to share it with the government as royalty or whatever. So -- but what is the value on that?
Actually, we first -- we get flow of the 10 million cubic feet and price was fixed in terms of the brand equivalent. And 22% of the brunt. But till the time we reach that 10 million, even if you take the lower say, around say $15 per MMBtu and we will be able to make a revenue, which will be in the order of INR 250 crore to somewhere around INR 225 crores. That should be the revenue base. Out of that 25% goes to the government of India. So the balance meets an operating cost, we still end it with a profit of over from INR 75 crores to INR 80 crores.
Around INR 75 crores to INR 80 crores, that is per annum you are saying, correct?
That's right. We're annualizing to this year.
Okay. And if you can clarify on the royalty part, for the D1 you said, if the oil is around $90 or odd, 33%, 34% will go towards some extra royalty and total royalty will be 45% and plus your expenses in the tune of $15 to $20 or how exactly?
No. If I may clarify that. It's a revenue-sharing model. In the revenue-sharing model, it is whatever the revenue we earned that has to be shared with the government, at the agreed predetermined rate. What the rate we have -- we separate is LRM and HRM is varying from 12% to 55%. So in the context, at a $90 oil price, if they make a 4, 500 barrels of oil and say about 1 million to 10 million cubic feet of gas, I have to share with the government 1/3 of the revenue as a revenue share.
On the top of it, whatever the value I'm realizing there on to it. 10% would be called as a royalty, which is as [indiscernible], it is not fixed. Okay? So the revenue share to the government would be about 42%, 43% on the revenue. The balance is further operating cost and the risk goes to the company for sharing.
Okay. And the operating cost is what, $15 or $20 for the oil?
Operating cost for the field, we are expecting, which is our captive 2 subsidiaries are holding the major assets, which is one is the MOPU another one is our floating storage offshore and the single point moving. It is owned by us. So these companies will take a revenue, which should be in the order of say $95,000 per day. And putting together the helicopter and supply vessels on top, we should be in the range of around [ $523,000 ] a day. Out of that resource generated and which comes to the group is about $95,000. The balance goes to third parties.
[Operator Instructions] The next question is from the line of Nirbhay Mahawar from N Square Capital.
Congratulations for the commencement on B-80. With the commencement, we must be aware of the dynamic data and there must be more informed quality of reserve as well as field life. So what is our stance on that?
We will -- as I said, we are able to flow the well since 31st May now, 2, 3 days. And the pressures are -- the earlier testing results as far as D2 is concerned. D1, we have flown it for a very, very short period just to get the system. As I said, the important aspect our technical team look at is, what is the pressure being held by the well, and that is as per the expectation. So we are -- we remain confident that we'll meet the tested number, which was -- oil is about 4,500 to 5,000 barrels per day and gas about 12 million cubic feet per day.
Sir, any sense on that field life in terms of number of years, what is our -- any better sense on the field life data?
I think we have -- there are 3 things that we will be able to do the material balance again after putting up production for a year or so. So our current estimate goes, there are 2, 3 values out there, P-90, P-50 and P-10. And if you look at that P-10Ks we will be going to the entire contract value that will be for 20 years. And P-50, we should be able to produce from at least 10 to 12 years. And in our all probability, the minimum duration of 7 years will be completed in the P-90.
But now we have got a lot of low-hanging fruits in terms of existing results we have got for like Kharsang, as well as PY-1. So from a balance sheet point of view, when do you see you'll be able to open a new field and you'll be able to -- do you see this happening in FY '23 only, that you guys can ramp up?
I told you already that we have to come out of our working capital issues and to the -- and some repayment of the loans, and we wanted to leave up to the minimal level. And after that, we'll embark on the development. Our first priority of development is PY-1, which is already have some capital of $383 million sitting there, which we wanted to bring back some value on these assets. And then subsequently, we'll embark one by one.
So how long you think with the cash flow of D2 at least? When do you see this investment starting?
So it is all projection subject to the caveat of B-80 concerned team, and we have the revenue generated thereon. Our PY-1 initial planning process has been completed. Our geologists have come out with the location. Our drilling manager is making a drilling plan there on tour. To execute there, it needs about actual drilling of the about -- actual drilling and completion of about 3 months. And however, subject to the availability of the rig at the right price. So any vessels moved into the West Coast, we'll keep an eye on it and if we have the capital at that point in time, we will be trying to start commencement, drilling thereon. So we wanted to do the work at cost as such, and we don't want to do at any cost as such any development in future. So we wanted to be careful in future on that.
Nirbhay, may I request you to come back in the question queue for follow-up question.
Sir, does it make sense to bring in any...
Nirbhay, sorry to interrupt you. May I request you to come back in the question queue for follow-up question. The next question is from the line of Ashwin Reddy from Samatva Investments.
Congrats on getting B-80 on board. Sir, firstly, regarding the rectification plan and if that fails, the subsequent plan that you are outlined, which was at [indiscernible], what would be the amount of money you would need to spend on both these plants? And because the reason I ask is, you mentioned about the working capital issue and the liquidity issue and all. And recently you also the [indiscernible], so in that context I wanted to understand how much money do we need to spend on these plants to get the D1 wells onboard, in both the cases?
These operations essentially involves hiring the vessel from ONGC, which has a full complement of equipment and diving team, and we put our own team to supervise the job. So overall, the estimate is about $400,000 for this operation, which we've made arrangements...
Sure. But this is the rectification or for the overall thing that you said, in case the rectification fails, the post-monsoon [indiscernible], if you have to overpay, what would that cost?
Yes. Now this is for the rectification that we are talking during the monsoon period.
Okay. And if it is post that, how much would that cost?
If you have to do the full...
Basically, this is a subsea system. And the system works, there should not be any problem. And even if the post monsoon, it should be work, which we wanted to do the overall the whole system and come back and doing it, it's just about it should not cost you more than INR 10 crores to INR 12 crores, at least. It's about $1 million to $1.5 million, the max exposure. But I don't think if there are -- if it is holding as such, then we don't need to spend so much of money on that. But anyhow, that's overall capital we incurred, which is in the order of $125 million. This is less than 1% of the work, which we have to carry it out.
Ashwin, I request you to come back in the question queue for a follow-up question. [Operator Instructions]. The next question is from the line of Manan Patel from [ Airavat ] Capital.
Congratulations for pre-commissioning of B-80. [indiscernible] $95,000 per day comes to the group and $125,000 total operating cost. So that comes to around INR 340 crores. So does that start as soon as the production is started or like it is linked to the commissioning of D1, D2 and other wells?
It is -- see, normally, it is under commercial sale. That is a relevant date for us. See, whatever the time which we spend, we may produce some oil, we produce some gas. Till the commercialization take place, the date of commercial production is considered to be the take for the commencement of revenue to us, which can be either oil or gas, whatever it is.
Okay. So the cost is also related to that.
Yes, that's right. Because for this operating cost related to that because without these facilities, neither the gas, nor oil can be evacuated. So operating start [indiscernible] the date of commercial sale of this plant.
Okay. Got it. And sir, second question is, today, article related to DSF 3 came, but we are -- HOEC was not mentioned in that article. So are you not participating in DSF 3 at all?
Yes, we have not participated in DSF 3. We thought we would focus our attention on B-80, bring it on full stream and then look at opportunities within our portfolio, where, as you said, there are several low-hanging fruits within our portfolio. We would focus on them, invest and then look at other opportunities in future only. We didn't want our attention to be diverted in anything other than B-80.
And sir, lastly, can you just throw some light on why -- what's the [indiscernible] and was it personal reasons? Or was it for the company itself?
Not for personal reasons. I lead a simple life, so I don't need that much money.
The next question is from the line of Rohit Balakrishnan from ithought PMS.
Hello, am I audible?
Yes.
Yes, you are.
Congratulations on getting B-80 started. Sir, most of the questions have been answered. Just a few clarifications and follow-ups. So first was, sir, that assuming that D2 gets commercialized, which you said should happen in a few weeks, what is the kind of revenue that you mentioned that you can sort of do in this year, which will accrue to HOEC? I missed that number, sir. If you can just...
I think subject to the caveat on D1 comes back to production. We will start with the production of 2,000 barrels and ramp up to 4,000 barrels, and it can further ramped up also. It will be a slow process. We will be keeping the system tuned towards to receive the oil to its capacity of the well. The test production of this well is more than 5,000 barrels. But we will be reaching to a number we should be -- the plant can handle it in a comfortable manner as such. So till that time, it will be [indiscernible] average production of, say, 4,000 barrel a day. So you can multiply the 4,000 barrel into the price. Price, I cannot determine as such. Today, it's holding 120 and tomorrow, it may go to 90. And if an average price, you can take it at $100, it is $40 million. It can make INR 300 crores actually.
Right. So all this math that you mentioned is only considering D2, right? It's not considering D1. Is that understanding correct? Or...
D1 is on the production mode at the moment. But D2 is in a production mode at the moment. D1 is an oil well, and that we have to put it on production. The repair is being carried out. And once it is successful, and we would be able to ramp up the production from starting with somewhere around 2,000 barrels, and it is having a capacity to produce more than 5,000 barrel as seen from the test results. And we have to tune the plant in such a manner, it is comfortably able to receive and process the oil to that extent. Then accordingly, we will increase choke size of the well. So on an average, if you assume a production of 4,000 barrels, we will be making revenue depending on the price prevailing after 2 months of production because minimum of uptake size is about 200,000 barrels. So once we reach the size of 200,000 barrels, then we will be able to sell that oil. So it takes a lead time of about 2 to 3 months.
Actually, sir, my question was from the point of view that, let's say, D1 well takes some more time, then I mean, what kind of -- I mean what kind of cash flows that can we get? That was the question. So basically, you are saying that even if D1 takes time, D2 can give us this kind of revenue and cash flows.
I'll tell you, this is caveat on 2 things, on production sustenance, demand sustenance, price sustenance. And with all these things are happening, we would be able to have a cash in hand which is in the order of around INR 400 crores to meet our -- to meet the working capital demand, meet the repayment some of the debts and as well as we are embarking on the new capital thereon.
Sorry to interrupt you sir, may I request you to come back in the question queue for a follow-up, please.
I'm just sort of -- just a clarification, can you just complete this and then [indiscernible]. So sir, I mean, my question was just to -- I mean, in an unfortunate scenario or in a scenario which is not expected right now, but D1 takes a lot of time, will the cash flows from D2 alleviate the working capital require -- I mean with working capitalization that we may have, will those be solved? I mean that's what I'm trying to understand. So assuming, obviously, the price, whatever we have -- I mean, the price holds and the demand holds. So...
I think we should be able to have no working capital problem after the commercialization of D2 assets.
The next question is from the line of Karthik Sharma from [ NVS ] Brokerage.
I just have 1 question in 2 parts. How do you see the volatility in the oil market? And what could be the realization for that in the company? And do you see the fuel prices to remain firm? And the second part is what is -- what would be your take on the volatility on the prices?
So we are seeing whenever there is a higher prices, particularly the gas price at a higher level has a tendency to distract the demand, destroy the demand as such. That is what I understand is certainly, the Indian consumers are very sensitive to the price. And at the current price level, there is a strike -- there is a reduction in demand across [indiscernible]. Oil [indiscernible] if you try to predict what really happened there...
Sir, I'm sorry, I couldn't hear the last part. I don't know there was some disturbance from your end, I believe.
Okay. No, I was saying that Indian consumers, particularly I was talking about the gas are very sensitive to the gas price, and there is a reduction in demand at a higher gas price points as such. So that is across India. That's the numbers are, demand numbers are reducing at a higher price point as such. As far as the oil is concerned, your guess is as good as my guess, the scenario what we see and read is the price is going to be at 3-digit level, but things could change dramatically. So we -- on oil price, as you are saying, we always are looking at around $75, $80 in all our calculations, probably $80.
The next question is from the line of Pankaj from [ Varuna ] Investments and Finance.
I just wanted some -- a little knowledge. On Dirok, you say, your production is 27.7 MMSCFD, that is equivalent to 572 BOEPD. And as far as B-80 is concerned, you say it's going to be $10 million. So what would your BOEPD equivalent on that deal?
Now first of all, in Dirok, that is the number reported is 27 million cubic feet of gas per day as well as 500-odd barrels of condensate. That is not a converted number. It is straightaway liquid numbers only. The 10 million cubic feet of gas will be equivalent about...
Somewhere around 1,650 barrels of oil.
1,650. But it is in volume conversion only. So don't apply any price to that.
Okay. So that is -- because business is so complicated. I mean you've got profit sharing and profit petroleum, and so layman like us really don't understand too much. I mean, thank you for being patient over the -- on your con call. But at the end, I don't think we really -- any of us really takes anything much home. So what we want is -- how is it going to impact my share price. So that's the key figure that we wanted to always find out. And what we find that coincidentally, all your trigger points in your -- the company's last 2 quarters has been on the last day. So that leaves a little bad taste in the mouth about the reporting part. I mean nobody is putting any blame on anybody, but I would believe that look at the sensitivity of the information that is there and it's not a question, it's just the commentary that I'm making that an earlier speaker mentioned it.
So it leaves a bad taste in the mouth, and when you come out with the results on the 31st or 30th and then you wait 1 day or 2 days to share it with the investors through a presentation like this. So not everybody looks to come to presentations. They look at more -- the basic information that comes out with the results. So on the day of results, I'm sure you could have probably put out a little caveat on how things are. So then probably it would have not pinched us so much. So that's the only thing.
No, I appreciate your comments. I just want to say one thing is, as a shareholder, you would obviously be looking at the share prices. All I can tell you is as professionals, both me and Jeeva, really never look at the share prices. We just focus on the jobs that we have in hand and do our very best.
Next question is from the line of Vignesh from [indiscernible] Investments.
Sorry, most of my questions have been answered, but just 1 or 2 clarifications, if you could give me on one of the gentlemen who asked you about the possible revenue or the free cash flow. Is the INR 300 crores revenue that you quoted subject to $100 pricing and the current demand sustenance? Is it only from D2 well? Or is it including D1 oil well?
It's the total as such. What I told is the total number as such.
Yes. So it's only from D2? Or it's entirely from B-80, all in total...
Under the D2 alone, it means the D1 also comes to play.
Okay. Okay. And similar things on the free cash flow, right, of INR 400 crores.
Yes. That's right. You are right.
The next question is from the line of Dharmendra [ Vora ] from [ Vora ] Family Office.
Yes. My question was regarding the analogy you have given of a television and a remote for a layman. Just wanted to understand, suppose the current resolution with the ONGC team doesn't work out during this monsoon period. So what is the next course of action when the vendor window permits? And what is the time line probably? And what is the cost time line regarding the commissioning of the D1? That is the first question.
Yes. I think if this doesn't work out, as Jeeva was mentioning that, this is not a major equipment. This is an umbilical system, where we know for 70% of the system is working absolutely fine. There is a component, which can be lifted to the deck of a vessel, which can be performed during monsoon period and replace or reconnected with the presence of experts at best. That's what needs to be done. And that cost we have estimated to be in the order of $1.5 million, and that can be performed immediately after monsoon, which is sometime in October, November period. If our other attempts do not succeed, we have every hope that this -- our solution will succeed. And these attempts cost us about $400,000 to mobilize and which we will be doing.
And what are the risks involved? Suppose this first attempt fails during the monsoon, what are the risks involved? Are there any other unspecified risks, which might crop up at that point of time apart from the cost involved? Are any different possibilities of entire thing not working in our favor?
No, we've seen it work. We have seen both the wells produce. We have seen both the well come to the MOPU very clearly. Therefore, we don't see any other problem as long as we're able to fix. If we're not able to fix the problem in D1 well, we will not be producing from that. There's not a risk, and we'll continue to produce from D2.
The next question is from the line of [ Devan ] from DS Investments.
Yes. It is just a reiteration of what you said earlier. Now we totally -- the B-80 total has a capacity of about 7,500 to 8,000 barrels of oil equivalent. Currently, we are producing about 20%, 22% of that, which is about 1,700 barrels of oil equivalent. So this, we will be commercializing probably by the end of June, and we will start receiving revenues from the end of June. And the balance 80% of the production, we hope to start in the next maybe 2 or 3 weeks once when this issue gets solved, and if not, maximum by October, November, is this the right understanding?
Yes. That's a correct understanding. I just want to clarify the capacity part that you mentioned that the we expect both the wells together produce about 7,500 to 8,000 barrels of oil equivalent. The capacity that we have built is with future in mind, that individually, we have the capacity to process 10,000 barrels of oil and 15 million cubic feet of gas. These have been kept -- this capacity has been built on the top side so that in future when we drill new wells or find the wells to be producing more, we are not constrained by the top side capacity. So your 22% analogy may not be correcting, but your 1,700 barrels of oil equivalent vis-a-vis 7,500 barrels of oil equivalent is the correct reference.
The next question is from the line of [ CS Chaudhry ] from CSF Financial Services.
This question was [indiscernible]
Mr. Chaudhry, sorry to interrupt you, but your voice is breaking very terribly. Sir, may I request you to rejoin the queue. Next question is from the line of [ Sai Das ], individual investor.
My question is regarding the D2 well. So on a stand-alone basis, you mentioned that D2 at USD15 per MMBtu will generate revenue of INR 225 crores, and 25% of this will go to the government. So is this 25% a fixed number or more or less or will it increase? And that's my first question. And the second question is, using these estimates, you said that the profits would be around INR 75 crores annualized. So this INR 75 crores involves the expense -- the money that you received from that MOPU and FSO units into your group? Or does it exclude that? That's all.
Okay. Now I'll give you a simple analysis of how the government share works. Government -- whatever the revenue is generated, the government is having a stake. If I generate $1 million per day, then I have to share with the government 55. So in that model, if you look at that if I generate about, say, $150,000 -- say, $250,000, I expect it should not be more than 1/4 of the money therein. So it comes -- it's starting with the about $12. It's 12, 12.5, it goes up to 20. I've taken the maximum upper limit of 20%, 21% because it will produce some oil there onto also. So with that, we have considered 25% goes to the government thereon, right?
So now your next question goes about operating costs. The operating cost is stand-alone. That goes from -- which is like any third-party contractor, this B-80 field has to pay for [indiscernible] subsidiaries. That is about $97,000 a day they have to pay for it. Okay. Now whatever the revenue generated out of the D2 well sales, first charge goes to these operating expenses. After meeting the operating expenses, after meeting the government revenue, the balance will come. That I estimated in the year-end annual to be about INR 70 crores cash net, okay?
Sir, the line from the participant dropped. We move to the next question. Next question is from the line of Abhishek Jain, individual investor.
We will move to next participant. The next question is from the line of Natwar Gupta, individual investor.
I'm going to ask a question relating to Dirok. Now Mr. Elango mentioned that the customers are price sensitive and the price being $6 around. And given how the global gas prices are, I anticipate that when the next revision come, they are going to be even higher. So in some ways, we are saying that the volumes might be constrained because the prices are high and the customer is sensitive to pricing. Now with that backdrop, you mentioned that you're doing the pipeline to Duliajan. Once you do that, do the customer mix change? Or is it the same customers? Does it give you access to more customers once you have done that pipeline?
Yes. Yes. The -- once we do the pipeline, obviously, it allows us to access few more customers. But individually, they are not -- may not be large customers. Mostly all the large customers are already connected through the Oil India pipeline. So that's not a [indiscernible]. But what it does is it kind of helps in meet -- certain sectors are not really sensitive to the price. For example, any refineries, I mean, you are competing -- your gas is competing with fuel oil, which is substituting the fuel oil, therefore, if you're accessing the refinery directly, they are not very sensitive to the prices.
Power sector, the government has pushed them to continue the production, whether they make money or not. So we had also seen power sector dry. It's difficult to really see with the next price increase, how some of these customers' behavior would be. But having said that, we see the pipeline as more of a strategic investment, which allows you to directly reach the market and reduce your dependency on Oil India at one level. And the other level is to kind of derisk the Dirok. From the point of view of today, if there is any kind of failure in that Oil India pipeline, then we will not be able to supply it to anyone. But having our own pipeline gives that [indiscernible].
So when do you expect the pipeline to be up and running? And second, in terms of demand change in that area, what I could then figure out is that only when Numaligarh refinery the capacity increases, there being a CapEx there, then sort of know the demand/supply balance changes. Would that be correct? And if that is true, then when do you expect that expansion plan to conclude?
Yes. The first thing is a huge Northeast gas grid is being built by the government. Based on the demand that has been assessed in the entire Northeast region with a lot of unserved areas as such. Government has actually given a project. It's a subsidized project by government to create that infrastructure, being implemented by [indiscernible]. That work is going on stream. One interesting part of that network is that has the ability to flow the gas out of Assam also and connected with the rest of the India. So it's like what you saw when the entire power grid in India got connected with multiple regions, you see the demand being managed much more efficiently across the region. So we do expect that to happen, but that's more like '25, '26 -- FY '25, FY '26 scenario. But all I know is both the Numaligarh expansion project as well as the Northeast gas grid project has been given highest priorities by the government. There are not local issues. All the approvals have been given to them on priority and the execution is going on in full swing.
Right. Now can I move to PY-1, where you have done a settlement on royalties. So now what does that change compared to the earlier numbers of royalty?
See, basically, earlier as per the statute, the royalty has to be paid at 10% of what is designated as wellhead value, which means whatever is the sales price you realized, you deduct the transportation and treatment cost for the gas from the wellhead to the delivery point, which is onshore. In our case, the wellhead is an offshore, the delivery point is onshore. So under the statute, we are allowed to do because the royalty is always levied on wellhead. Now after the entry of multiple private sector players, the government through various audit found that this is creating a lot of problem for them.
So they wanted to fix that sales price is a pricing point, you pay 10% of the sales price, which is not really in accordance with the mining license conditions or rules. So we felt we are very strong statutory legally in our calculation. And from a President's point of view, since inception -- sorry, since independence or since commencement of gas production in this country, we know that royalty has always been paid by both Oil India and ONGC at 10% of the wellhead value. And both Jeeva and me worked in ONGC for more than 10, 12 years, we know exactly how this is done. But the way we reach the settlement is basically the government took a view. Look, I'm facing a lot of problems with multiple players, all of you will pay some 10% of sales price as royalty.
So in the DRC, we have made some kind of a settlement proposal, which I'm not allowed to disclose as such. But to answer your question, going forward, it doesn't change it any way other than we will pay 10% of the sales price as royalty. And that we have already started doing.
[Operator Instructions]. The next question is from the line of Chetan Phalke from Alpha Invesco.
Sir, this is regarding our exchange release dated 24th of February 2020, in which we had published our test results for D2 wells. So at various choke sizes and pressure flows, the production can vary anywhere between 15 to 23 MMSCFD as per the [indiscernible] or exchange release. While our sale size with GSPC is only, let's say, 10 MMSCFD, and we have been talking about 10 MMSCFD production and sales. So just wanted to understand when our minimum production capacity as per the test result was 15 MMSCFD, is there any change in our -- any revision in our production plans for this D2 well?
No. We've -- based on test results or even before the test results, we have indicated the gas production to be 15 million cubic feet. And we always have our own internal consumption, all the systems in the top side is run through gas. So there is an internal consumption, which we estimated anywhere between 2 million to 3 million cubic feet. So we were comfortable with 12 million cubic feet as a sales number. And when it comes to commitment, where there is a take or pay as well as supply or pay, the model is there from after first year onwards. We thought it was prudent to commit 10 million cubic feet. I want to emphasize that we have always have the option to offer the gas that exchanges also any excess gas that we produce, we can always sell it to any other customers also. So all the flexibility we have built in, but we just want to proceed on a conservative basis.
Okay. Okay. So is it fair to assume that once things stabilize, there is a chance that our tie-up can be higher than 10 MMSCFD?
Yes. Yes. Very good.
Okay. Okay. Any ballpark number how high we can go whenever things normalize, not asking for immediate guidance, let's say, after the year or so?
No, no. I said we have a limitation in terms of process capacity of 15 million cubic feet. We have the internal requirement of about 2 million cubic feet. So it can vary anywhere between 10 to 12, 13.
Okay. Okay. So the process capacity has to be taken up just in case the production capacity goes to...
See overall, the gas or oil production is really determined by our reservoir management team, which looks at the long-term how do you maximize your recovery over a longer period as such. What is the maximum you can recover or optimum. So they decide what is the optimum rate of production based on pressure data and other database, and we follow that only.
The next question is from the line of Rikesh Parikh from Barclays.
Due to no response, we'll move to the next participant. Next question is from the line of Tejas from Unique Stockbroking.
If you can share on the expenses and the other interest, what is being charged. And again, the vessel cost also being charged on the consolidated, if you can throw some light on that?
See, our cost of capital is less than the debt capital is about [indiscernible] and whatever the [indiscernible] we are getting our interest rate [indiscernible] it is less than 9% for all of our borrowings. So what is your question?
There is a cost in other charges, you mentioned interest cost. On the consolidated balance sheet also there are other vessel charges [indiscernible]
Yes, right. As I told you in that as such the vessel, the -- whatever the floating storage offshore and the single-point mooring system commissioned on 26th of December. So it is in an [indiscernible]. All the cost is related to the operating expenses. The system is fully commissioned, if the revenue earning is linked to the B-80 production. That's why the cost is in the balance sheet, which is in the order of around -- that the company has suffered a loss of INR 11 crores for this 3.5 months, including the depreciation, which is in the order of about INR 7 crores.
Okay. And normally, you charge depreciation, depletion and there are some other also. So will that be charged on full and what will be the effect after the B-80 starts? Means let us say when the B-80 starts, then the depreciation depletion cost will come to what? And whether it is 10% of the turnover. Even on the royalty side, if we see, it's around 20% is the royalty on the top line. What [indiscernible] to do what we are paying right now?
Okay. I can tell you what is happening as such on all the -- in case of B-80, the royalty is 10% in either case, whether it is an oil or gas. But in case of gas from Dirok, which is our major revenue generator, royalty is 10% of the gas. But whatever the condensate we produce, we have to pay 20% royalty, and then we have to pay 20% sales after adjusting the royalty. In effect, it comes to around 38% after revenue earned through oil in other blocks, okay? So that is a major thing. If you average it out, probably you may be looking at a number of, say, 20.
The next question is from the line of Nirbhay Mahawar from N Square Capital.
The content of...
Nirbhay, sorry to stop you. Your voice is breaking. May I request you to come in to a better reception area.
I am just hoping to follow up regarding my -- our existing portfolio development. Are we open...
Nirbhay, sorry to interrupt you, once again. Can I request you to come back in the question queue, please? The next question is from the line of Ashwin Reddy from Samatva Investments.
The first question is on Dirok. So the reduction in volumes in Dirok that we have seen, how much effect is due to the higher APM price post April? And how much is due to the maintenance shut down in the BCPL refinery?
The number that you've seen now is for the last quarter. In the last quarter, there was no price increase. That is very January, March quarter [indiscernible]. That is mainly due to shutdown and seasonal lower demand by the customer. The new price of $6 plus is effective 1st April. So in April, we saw a bit of a price shock within the customers to minimize thereof. But in May, recent -- about a week back, we started again seeing picking up of demand. So I think by the end of this quarter, we'll get a more clear picture on how much is the impact of price increase. But overall, we find mostly be any shutdown in any of the major customer impacts us [indiscernible] this quarter, we'll get a better sense.
Got it. Got it. And the second question, sir, as a clarification, so the INR 75 crores to INR 80 crores number that you mentioned that we would get from operating the purely the gas well, is that right. So is this the consol number at consolidated cash flow or only at the standalone because consol it also includes whatever you get consol level?
Yes. Consol level, we'll be getting a better number as such because then I have the 2 vessels revenue generation would also be there. So we will be expecting some oil production from the D2 well also. With all put together, I'll be touching a number of over INR 100 crores.
Okay. But in your share? Or this is the [indiscernible] your share, right, not [indiscernible] partner?
Our share.
Next question is from the line of [ Chaitresh Ranaut ], an individual investor.
Congratulations on the B-80 bill. So I just wanted to know like by when we can expect the D1 to be commissioned like [indiscernible] have available.
I wish I can give you a specific date on that. I think we explained that we will be making what [indiscernible]. We just hope and pray it ends up successfully.
And the other wells part in the presentation is missing in this particular presentation, like updates on other wells. So that was included in the presentation earlier. So any reason for excluding them? I mean...
You mean the other blocks?
Yes, other blocks.
Yes. No, we will be uploading the investor presentation. In the evening what we have done is the earnings presentation, highlighting the quarter results on each of the block. But we will have a comprehensive update on all other blocks also.
Okay. So as per earlier -- from the management like we are expecting to reach around 40,000 -- 14,000 equivalent of barrels oil equivalent per day in the next 2 to 3 years. Are we on track for that?
Yes, I think the -- really, the current year focus is on getting B-80 on full stream and also investing. After that, as Jeeva emphasized, we will focus on adjusting some of the working capital issues, bringing down the debt level as well as doing the investment in the existing portfolio of Dirok, PY-1 and Western as such. Our portfolio -- value of our portfolio remains, but investment only will unlock the full value. That will be determined purely by when we are able to get the full production from B-80.
The next question is from the line of [ Vrushul ], individual investor.
Congratulations on commencement of the production. My question [indiscernible] carry forwarded losses. So just wanted to understand if you can throw some light on the amount of losses we have in terms of carry forwarded and the set of duration we have or the time we have to set off in terms of number of years?
Okay. So carry forward last as on 31st March would be about INR 841 crores. The majority of them are the depreciation, which is no time limit under the law. So we should be comfortable as such till we reach the number of INR 841 crores.
Thank you very much. I now hand the conference over to Mr. Anuj Sonpal for closing comments.
Thank you, everyone, for joining us. I would request if management has any closing comments. Over to you, Elango.
Yes. Thanks, Anuj, and thank you, everyone, for participating in large numbers. Overall, considering the huge investment that HOEC Group has made in B-80 and critical tasks that are yet to be accomplished, we wish to remain focused on B-80. Post full production from B-80, we will take up investments in our existing portfolio to grow the production in this attractive price environment. Thank you again.
Thank you very much. On behalf of Hindustan Oil Exploration Company Limited, that concludes this conference. Thank you for joining us. You may now disconnect your lines. Thank you.