Hindustan Oil Exploration Company Limited (500186) Earnings Call Transcript

Ladies and gentlemen, good day, and welcome to Q1 FY '22 Earnings Conference Call of Hindustan Oil Exploration Company Limited. [Operator Instructions]. 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 a very warm welcome to you all. My name is Anuj Sonpal from Valorem Advisors. We represent the Investor Relations of HOEC Limited. On behalf of the company, I would like to thank you all for participating in the company's earnings conference call for the first quarter of financial year 2022. Before we begin, I'd like to mention a short cautionary statement. Some of the statements made in today's earnings 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 conference call is purely 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 conference call and give it over to them for opening remarks. We have with us Mr. P. Elango, Managing Director; and Mr. R. Jeevanandam, Executive Director and Chief Financial Officer. Without any further delay, I request Mr. Elango to give his opening remarks. Thank you, and over to you, sir.

Thank you, Anuj. Good morning, everyone. Happy to connect with you all for this Q1 FY '22 earnings call. Jeeva, our CFO and full time Director, is also with me, and Valorem Advisers, our Investor Relations adviser, are also on the call. I hope you all have received our updated earnings presentation. We've also uploaded that same on our website for your reference. After a year of similar focus on B-80, Q1 FY '22 was about making adjustments to realign for first oil from B-80 in Q3 FY '22. While we are dealing with the time and associated costs over in issues, through renegotiation, we are excited about the prospects of the feed over the long term. We already announced the much-awaited updated reserves number from B-80. With the multifold increase in the 2P reserves, B-80 has emerged as the anchor asset, which will transform HOEC. The reason for such increase is on account of post development drilling whereby HOEC revised the B-80 3D geological model by applying all the data from the feed, which includes the previous wells drilled by ONGC as well as the current 2 additional development wells drilled by ONGC. We have initiated engagements with the market to identify potential contractors to mobilize the suitable marine spread to complete the remaining project works post monsoon and bring the field to production in Q3 of this year. On the marketing trend, our plan is to roll out an e-option for gas sales and will store the oil initially to carry out sampling and assay of settled crude to discover the best market prices and sell the oil as the delivery point in the FSO. At Dirok, we continue to operate without any downtime due to COVID pandemic despite severe restrictions in the area. That further demand for Dirok gas exists is being proven both operationally as well as through the e-auctions that was conducted for Dirok gas earlier. To achieve further production from Dirok, the expansion of processing facilities would be required at Dirok which is part of the Phase II execution plan. As indicated in our last call, our focus in Dirok now is value over [indiscernible]. To achieve this, we let the e-auction in June and are now in the final stages of contract conclusion with the buyers. We expect gas sales from these contracts to commence from Q3 FY '22 onwards. Expected increase in the 6 monthly government notified prices will positively impact the revenue realization from these contracts. This is a significant development and has a potential to increase the realized gas price from Dirok from Q3 onwards. The current arrangement will continue with Oil India to ensure smooth transition using the pipeline infrastructure of Oil India. Once we move to the new arrangement, Oil India will act as a transporter for Dirok gas for which models are being worked out. This pioneering e-auction has helped to discover the natural gas pricing in the Northeast, especially upper Assam. We are in parallel preparing for the Northeast market being opened up for the rest of India. As the North East Gas Grid, Indradhanush is progressing at a rapid pace and is expected to commission the Guwahati-Numaligarh pipeline portion in 2023. In PY-1, production has declined and the offtake has been inconsistent during the pandemic year. Our efforts to revive the well to original production capacity was not successful. The field will now require rig-based intervention to increase production. Our geological studies have been completed to plan the next drilling campaign in this unique fractured basement reservoir. The next drilling campaign in PY-1 will be planned after first oil from B-80. Although the current production from PY-1 is very small, we remain confident of bringing the field back to production -- back to producing to its potential after the drilling campaign. Final investment decision will be taken after independent technical assessment and derisking. In our Cambay assets, we have initiated the environmental clearance process to drill additional wells and the much delayed execution of R2 PSC in our Palej block is in its final stages of approval. Similarly, there's been further progress in Kherem to secure the PML with the consent of the state government of Arunachal Pradesh. Overall, our plan is to continue our focus on delivering first oil from B-80 while progressing the planning and regulatory processes in all other assets and take up execution immediately after first oil from B-8. Updates at a couple of other matters are: firstly, amendment of B-80 revenue sharing contract to reflect the increase in HOEC's participating interest from 50% to 60% has been cleared by the Law Ministry and is in final stages of execution. Second, PY-3 arbitration award is still under challenge in Malaysian high court. Next year it is expected in September in a parallel manner, matter initiated by Hardy. For enforcement of awards, the Gujarat High Court directed HOEC to file its objections. HOEC requested for a review on the premise that till award becomes final post-Malaysian High Court verdict, it is not correct to ask HOEC to file its objection. On 10th August, the Gujarat High Court rejected HOEC's request for review. Action is underway to appeal to Supreme Court. We've also made a disclosure in the results about this. You can defer that. I now invite Jeeva to share the financials.

Thanks, Elango. We report that the company estimate a revenue of INR 27.56 crores in the current quarter against INR 24.19 crores in the previous quarter. In the consol accounts, it is INR 31.79 crores against INR 29.68 crores in the previous quarter. Increase in revenue is mainly from increase in the sales gas in Assam and higher realization of oil prices. This profit on stand-alone is about INR 11.71 crores against INR 6.59 crores in the previous quarter. In the consol accounts, profit after tax for this quarter is INR 10.93 crores against INR 5.54 crores in the previous quarter. On the expense side, if you look at including DDA, this INR 15.85 crores comparing INR 17.6 crores in the previous quarter. Operating costs are not linear to the production except stage 2 [indiscernible] such as royalties, which is at [indiscernible]. In the consol accounts, it is INR 21 crores comparing INR 24 crores in the previous quarter. In the overall, this contributed to the increase in the cash flow for the company. Operating cash flow stand-alone is INR 11 crores for this quarter -- sorry, before working capital change is INR 14 crores comparing INR 11 crores in the previous quarter. And in the consol accounts, our cash flow stands at INR 16 crores comparing INR 12 crores in the previous quarter. In terms of all-inclusive is about INR 619 crore is in the capital work in progress and on commencement of revenue from these assets, it will move to oil and gas producing assets. Better number would reflect on the commencement of cash flows from these assets, which would provide a new impetus to the business. In effect, 1/3 of the oil and gas assets are in production and 2/3 is working to -- is working -- is capital work in progress, which will yield better numbers once the B-80 has begun production. Thanks, Elango.

Thank you, Jeeva. Anuj, we can open the forum for questions.

[Operator Instructions] The first question is from the line of Akshay Satija from Alpha Invesco.

First question is on Dirok. Sir, could you help us with what would be the aggregate investments in Dirok. As I'm trying to calculate the investment multiple. Also, what would be our CapEx if we go ahead with the expansion of capacity from [ $36 million to $55 million ] and maybe 5 years down the line, we look at increasing it to [ $75 million ] in HDFC.

In the -- currently, we have in the FDP, field development plan, the first field development plan. We made an investment of roughly about $60 million gross investment in developing the Dirok Phase 1 of the field. In the second development, which has already been approved, the HDFC investment is about $60 million, and our share would be less than $18 million. The second phase of the development involves a 38-kilometer pipeline and drilling of few wells as well as expanding the existing process capacity in a modular format. So what we had. Our existing infrastructure itself is capable of producing about 40 million cubic feet [ on par ] on occasional demand. We have delivered more than 40 million cubic feet of gas per day. So our plan is to first implement the e-auction contract in place and commence the -- recommence the sales directly to the end consumers through this -- using the Oil India's infrastructure, then take up the phase 2 development, and we have some flexibility to initially decide on the number of wells and the [ expected yield ]. So overall, for the entire phase 2, including the pipeline portion, is about $60 million gross. And our share of that will be less than $18 million.

Okay, okay, got it. My next question will be for first a clarification. So as per our April 2016 investor presentation our 2 key results for PY-1 stood at some 31.5 Bcf. Now already extracted somewhere around 5.5 Bcf in the last 5 years. So do your current reserves stand at 26 Bcf or we're looking at this wrong way?

See this, when you look at PY-1 reserves, it is basically the -- whatever we were producing on that, actually, that time, we've estimated B-90 reserves thereon. Now the B-50 reserves is much higher than that. That is being the reservoir model is being now worked out, and we have got a new expert geologist, he's working on it at the moment. With the revised numbers, with the revised number of well drilling assets, we will come out with a new plan there on to it. Because whatever you could have seen in 2014 and '15 and '16, we have impaired most of the assets there on to it, and we kept out of the bad minimum in the books of accounts. Now we have to revisited the whole thing, and we will come back with the revised numbers that will be classified under the P50 reserves. And after drilling the wells, we move into P90. So till the time the results showing in the books of accounts are much lower than that.

Okay. Sir, one more thing on this, sir. Sir, when we actually should report our results in the earnings report for results are actually the initial results? Or we actually keep them updating every year considering whatever we have depleted or removed that year?

Yes, every year, the results will be recasted, which will be based on the new data thereon. If there is -- then we have to adjust the production number there on to it. That is the way results are revalued every year, year-end actually on 31st March of this year, we'll revalue the results there on to it and the production there on to be adjusted there. And based on that, the balance recoverable results will be get reported.

Next question is from the line of Rohith Potti from Marshmallow Capital.

A couple of questions on B-80. So first is, I mean, we've mentioned in the past that the netback for us as far as crude oil is concerned, is around $23 on a $50 crude oil price. But could you share a broad calculation for the gap that we'll be producing there? I think we'll produce around $17 in MMSCFD there?

Yes, the gas, we expect the production -- total production to be about 15 million standard cubic feet per day. And the sales volume will be about 12 million standard cubic feet per day. About 12 million standard cubic feet in terms of MMBtu is about 12,000 MMBtu. So 12,000 MMBtu on a -- we expect the price to, discover site for that would be roughly about $4 per MMBtu -- $4 per MMBtu. And primarily, the operating cost really gets covered by the -- in the -- from the oil price realization. -- business separate operating cost for gas as such. So net of royalty, we should be -- the revenue would be flowing back to the operations.

Okay, sure, sir, that was helpful. And sir, broadly, my second question is on the royalty calculation itself. So in the previous -- I mean, not in this presentation, but I believe in the previous quarterly presentation, we had given the calculation for B-80 based on both the lower revenue point and the higher revenue point. So I mean, I was hoping if the management could explain that a little better because I'm not able to calculate -- I'm not understanding how to calculate the government share of revenue, let's say, if it is $60, how do we go about calculating this?

Yes, no, the revenue sharing [indiscernible], the way it works is, if a daily value of production is less than $10 [indiscernible] 12%. The daily gross value of the production from the field is more than $1 million a day, then the share of government goes up to 56%. So in -- on an average for the current production rate of 5,000 barrels of oil and 15 million cubic feet of gas per day production, our expectation is around 20% to 22% of revenue will go first to the government. First, on the -- whatever is the price, let's say, the price is $50 per barrel. -- 10% of which will go towards royalty, which is $5, then roughly about 20% to 22% will go towards the revenue share, which is roughly about $6. Then the operating cost and the balance is the netback. On that basis, only we indicated this $23 per barrel.

Yes. So that was helpful, sir. So what is -- so am I right in thinking that this percentage increases a little non-linearly with higher revenue generation or higher oil prices? So let's say, if it is $60, then are we talking about the -- so the royalty will remain constant at 10%, but the revenue share will be higher than 22%, 23% that you indicated?

No, the revenue share will increase linearly only depending on the value of the oil.

Okay. So let's say, if it goes from $50 to $60, we are looking at, let's say, about 25% of revenue that is shared, is that right?

Think I would like to explain to you this is 2 elements of component. The royalties will stand at 10%. This is nothing to do the royalty. Then it comes to the revenue share to the government. Revenue set to the government is more on a progressive model, which means that it is a low rate of low revenue. That is when your revenue is up to INR 10,000 rupees. It will be a percentage of 12%, we share with the government. If your revenue is 10,000 and less than 1 million per day, then you can be progressing it according to it. So what will happen now that your proportion rate is your increase in the revenue [indiscernible], actual revenue by USD 900,000. So it is a progressive model. It is not a linear expansion model, right? It will be progressing at a slower rate actually. So that is why what happened. You have to work in this type of field revenue segment model, given share to revenue. So if you pickup a revenue model in such a way, you keep the price -- your revenue share to the government to pick up a number, say, around 20%, 21%. Then accordingly, you adjust your volume of production. So your production is -- your price is low, you increase your volume to your desired level. If your price is high, you reduce your volume in a manner that you keep the government take in an order of around. So royalty around 10%. So 1/3 of the revenue goes -- 30% of the revenue goes to the government. If you look at any revenue, any price profile as such, you can say roughly 30% goes to the government. The balance comes to the company assets to meet its operating cost, as well as the net back for its capital expenditure. So I hope this is clear.

This is very, very helpful, sir. We'll try and maintain -- basically, we try and maintain the total value of production from that field at a broadly stable level so the netback to the government -- the payment to the government is roughly 30% of the total revenue on a daily basis.

Absolutely, that is the way.

Next question is from the line of Manan Patel from [indiscernible] Capital.

Sir, first of all, I wanted to understand our revenue stream from the subsidiary investments that we have made. We have made around INR 250 crores, INR 260 crores in the subsidiary. So I wanted to understand what kind of revenue streams -- stream will come from that? And is my understanding correct that the 10% OpEx -- sorry, $10 OpEx or $12 OpEx that we are considering, part of that revenue will flow to the subsidiary itself. So if you can throw some light on that.

Okay. These are the 2 wholly-owned subsidiaries because basically, we get into a model of keeping this field less on the clutches of the contractors because this being subsea production. And looking into the volatility of the prices, we wanted to run this field for longer years. So that is the reason we resource this facility through our in-house assets. So when you look at these assets are normally put on to an IRR in the order of say 30%. So the way it is return to those type of assets. So we will look into that manner. So this out of that, say, look at that $100 [indiscernible] will flow back to the group only $90,000 goes to the outsiders. So these prices are currently, which is in the order of around totally for these 2 facilities, which we are looking around some 80,000 less. It will be more of a market driven. We will, being a material-related party transaction, we will take a relevant benchmark prices in the market then we will decide the price -- then we fix the price there on in a way that we are not profiting from the subsidiaries. At the same time, we are not subsidizing to the field as such. That's what the plan as such.

Understood, sir. That's very helpful. And sir, just a clarification on the previous question on the royalty. So that is on the revenue or the production? Because I understand you mentioned around 15 MMSCFD of gas production was the sale of 12 MMSCFD. So I just wanted to clear that. So royalty will be calculated on production or the sales.

No, no. See, in India, all the royalty is calculated based on the revenue realized, not on the volume of production there on. Whatever the sales which we make, that would be the -- based on the sales, royalty is payed out.

Okay. And sir, last clarification. So you mentioned initially from B-80 production, we will sample the oil and then -- so like will it take a long time for that oil to get converted into revenue?

No, we have the storage capacity of the FSO is about 900,000 barrels which would -- could store potentially 6 months of the production, right? What we thought was rather than taking the sample based on the very testing, we'll do the initial production, let's say, for a couple of weeks, and then take the sample. And this whole exercise can be done in -- within 3 weeks' time, we say. Then we will have a right parcel size to load a tanker. -- let's say, typical tanker load is about 240,000 barrels. And we will then offer it for sale to the interested refining companies. So he doesn't have to wait till the end. But the idea was you will realize better value or understand the property is much better if the sample is taken from what is known as set [indiscernible] crude.

Next question is from the line of Hardik Jain from ISJ Securities.

So in B-80, you said we'll produce around 15 MMSCFD of gas per day. And how much will be the oil per day that we'll produce from it?

Oil will be 5,000 barrels of oil per day.

5,000 barrels of oil per day. Okay. And this will be around $3 to $4 discount to the Brent.

We haven't really gone but our -- what we know so far based on the initial assessment is our oil is closer to -- In terms of quality closer to Brent, then we will -- once we take it through that pace, we'll decide to engage in the negotiation with the buyers to at the price.

Okay. And sir, now, so we understand that after the monsoon very little work is left that we have to do. So should we expect that by the end of October, we should start the production from B-80, hopefully.

Not really, we'll just stick to the Q3 guidance because the -- one is to exactly figure out the end of the monsoon period with the kind of changing weather the exact date needs to be first understood. Then before we actually mobilize the marine spread, we don't know the situation. We incur huge costs, mobilize spreads and the value is not right for the job. So we'd rather like the weather to settle first properly and then mobilize. So we'll keep you updated as we make progress on that.

Okay. So whenever we start the production October, November, whenever, how much time will it take us to reach to the 5,000 barrels of oil per day production and 15 MMSCFD gas per day production. Will it take a long time to ramp up the production or it happens immediately.

See production, what happens, there is gas sales goes immediately to the revenue realization. Gas is not getting stored either in the pipeline or anything. It gets into [indiscernible] terminal for sale. I will look for a parcel size. So the first parcel size will be taking about, say, 2 months. So after the 2 months, we will start the first half date. Then it will be a continuous uptake on 30 days, 40 days depending upon the availability of the shuttle tank. So then it will be a regular as such. Still first revenue realization from the oil will take about 2 months. The first offtake will be made after the 2 months, then we'll take about 30 days to realize the revenue there on.

Okay. And sir, netback, so at around, say, $60 per barrel price, the netback -- how much netback can we guess for this?

See, you can look at as such about that the government revenue and revenue sharing on all goes around to assume at 30%. The balance will be the for the OpEx and CapEx reinvestment. Out of 40, you look at around, say, $10 even go for OpEx, you'll still make $30, $32.

Thank you. Next question is from the line of Rajesh Agarwal from AUM Capital.

I just wanted to understand your perspective on potential of DSF.

Yes. So -- In the DSF around the government has taken 1 important feedback from the industry, which is to increase the size of acreage, acreage size. The example, B-80, the acreage size is about 56 square kilometer. The industry represented to the government that for offshore, in particular, the acreage size should be larger, that the risk that are taken by the companies are properly rewarded. So the government has come up with an average acreage size of about 400 to 500 square kilometer particularly in Western offshore. And right now, the bidding dates have been extended to the end of October. And overall, both onshore and offshore. In the onshore in our part, we have seen very high competition in offshore fee, but the competition is limited in offshore. So we are looking at wherever there is a synergy we'll be looking -- evaluating the blocks, whatever looks more strategic we will look at that.

Next question is from the line of Varatharajan from Antique Limited.

I have 2 questions, 1 on B-80. I think somebody announced when you will reach the 5,000 level in days or month? In the same breath given the increase in the reserve numbers, has there been any change in your plan in terms of drilling additional wells and maintaining this production for a longer period of time? My second question is on Dirok. Given the auctions which you have done, should we go ahead with 30% of the volume going at your pricing? Or should we take up some fallback volume also on to the calculation going forward in terms of our assessment of these.

Okay. On B-80, we will not require much ramp-up time essentially once the wells are brought on production one-by-one. Within a month or so, we should be hitting the production level. On the -- based on the reserve increase, we are not revising, we are not planning any immediate investment. Our plan is to initially put the field on production maybe after -- within a period of 2 years, look at additional wells to be drilled, which will primarily insure, we'll be looking at both water injection and development wells, which will primarily increase the plateau period of the field as well as result in some margin increase in production, which we will come back once we gain production of [indiscernible] from the initial products. On Dirok, what we have done is our arrangement with Oil India continues, but we've got a full volume demand on a fall back basis from the customers who will be paying a premium of minimum $1 per MMBtu. 1/3 of it is on a firm commitment. So you can reasonably assume that 1/3 of the current volume will be off taken at a premium level. The balance 2/3 would be based because they have been contract call back basis based on the demand from the market, those volumes will be sent. So every day, what we will do is based on the demand we received from the market based on the better pricing, prices will get the first option, And then the balance volume will go to Oil India. And the other point to note is the industry is expecting an increase in the government notified prices also effective 1st October. So all in all, it would be very reasonable to assume at least a $1 more price realization from Q3 onwards.

We'll move on to our next question, which is from the line of Sunil Jain from Nirmal Bang Securities.

Sir, my question is about B-80. Considering the P2 reserve, what could be the life of this B-80 well?

See this life of this field is linked to 2 factors, okay? One is the price. And because we wanted to have a revenue stabilization as such. So when we look at this field size minimum, which should be around -- we'll look for another extension. This is feel like the production sharing contract is about 20 years. We look for another 10-year extension there on to this. That is our current prognosis of the field development.

Yes. That is like -- let's considering the reserve that can be the life of the -- from current rate of production?

Yes.

Next question is from the line of Akshay Sabia from Alpha Invesco.

Follow-up question. Sir, is it possible to please share the 2P reserves for all the different wells that you have?

No, I think in our announcement that was made June 30 normally, we do the EBITDA in -- as part of the annual report, there is a substantial increase in the number we made a special announcement, whatever data is provided there, that is what we get.

Sir, also 1 more question on the Kherem, sir, what would be your strategy there?

In Kherem, we are -- when we bid for Kherem, the idea was to look at building our asset base in the Northeast region. And at that time, frankly, we assumed Arunachal Pradesh will -- operating in Arunachal Pradesh would be pretty similar to operating in Assam. But what we realize is some government is far more proactive, and we are able to engage with them much more actively and the processes are relatively simpler than Assam. Arunachal Pradesh government, the large part of the area is controlled by the Forest Department. So even the initial petroleum mining lease has not been issued by the Arunachal Pradesh government. We had to take the help of government of India. Recently, there's been a lot of discussion at secretary level where some more further progress has happened. So it is not a large deal. Our estimate was about the field to produce about 400 barrels of oil per day. The wells need to be drilled. So once we get the PML, we will income with a field development plan and proceed with that.

Okay. Sir, 1 more question I had. So we believe the government is planning to spend some INR 9,000 crores in Assam for the pipeline. Can you throw some light on what sort of work has happened on the project? And can we expect the project to come on stream?

Yes. This is the -- the government has provided the additional fund and set up a company, which is executing the Northeast gas grid. Overall, the primary focus is to, right now, the gas pipeline exist in Northeast. The main marketing hub is Duliajan. And Duliajan and Numaligarh NRL refinery is right now connected through pipeline, existing pipeline. The first phase of the focus is to connect the Numaligarh to Guwahati city. That part of the pipeline work is progressing on a rapid pace. The information that we have, some time by end [ 2023 ], that pipeline will be connected as well. The other important development is initially, this pipeline where conceded to bring gas from outside Northeast into the Northeast market primarily to meet the demands of NRL the expansion, which was based -- which was being based which is being planned on imported LNG, regasified LNG coming to this Paradip too this year. Now with the increase in gas production, not really from HOEC by Oil India also. The gain is keeping a provision to actually, if required, additional gas can also be exported out of Northeast to the Indian market. So the old pipeline network becomes a single market with optionality to flow the gas into Northeast or outside Northeast depending on the demand in the particular regions. What we have seen is in the Upper Assam region where the Dirok facility is located, Duliajan is there, there is enough demand for more offtake. The overall summary is the gain led that company is proceeding on a rapid pace and the government of Assam is supporting them very actively.

Next question is from the line of Nirbhay Mahawar from N Square Capital.

I wanted to understand the PY-1 potential you talked about, when we drill additional what kind of volume we can expect in PY-1?

So, we have -- initially, we had got developed a field development plan, which basically envisaged drilling of 3 wells which will take the production to about 17 million standard cubic feet per day. But subsequently, we have done -- further studies are going on. So based on which we will revise and come better, which will also be weighted by an independent reserve auditor before we take the final investment decision. I think what we are really -- what draws continued interest in PY-1 is we all recognize it's a technically challenging field. But we also recognize it's a commercially very attractive field because of the fact that existing infrastructure is there, and we have a huge cost basket that is yet to be recovered as such. So I think the investment that will be required is to basically drill the [ wells ] and as long as that investment made on drilling a well ensures adequate return and go for that. So with a more formal plan before we take the final investment...

The initial plan you mentioned was 17, 1-7, million standard feet.

17 million cubic feet to 20 million cubic feet per day.

And the pricing is fixed, that $3.65.

Correct, yes, correct.

Another small follow-up on B-80, the weather window starts early in the Western Coast in comparison to Eastern Coast?

Normally, it is October, November. November will be a safer period. number onwards. But with the kind of change that is happening, we will like weather to open up first before we really make any financial commitment with the contractor and mobilizing the spread also. But we have -- we monitor the weather forecast on a daily basis and we'll move quickly as well as we see the window opening.

Next question is from the line of Rohit Balakrishnan from ithought PMS.

Sir, just 1 question. In B-80, sir, our oil production would be 5,000 you said, 5,000 barrels of oil equivalent per day. That is a net or gross. I just wanted to clarify that.

This is gross. Field production is 5,000 barrels of oil and 15 million cubic feet of gas per day, and our share in the block is 60%.

Okay. Sir, please correct me if I'm wrong, have we scaled it down because we were earlier thinking of doing 8,000 as gross and 5,000 as net...

No, we have not changed any number. 8,000 is barrels of oil equaled that is both oil and gas together. So 5,000 -- the breakup is 5,000 of it is oil. -- about 15 million cubic feet of this is gas. Together, they make up for 8,000 barrels of oil we collect, all gross numbers.

Next question is from the line of Ashwin Reddy from Samatva Cap Investments.

Again, on B-80, a clarification. So I say I wanted to understand what is the capacity that we have for production of oil? I understand 5,000 barrels of oil is what you're guiding for what is the capacity that we have put up in place right now?

So we have the -- in terms of the [indiscernible] facilities, the pipeline and the processing capacity that we have is 10,000 barrels of oil. We have a adequate storage capacity, as I told you.

Right. So at 10,000 barrels oil, then I'm assuming correspondingly, the gas search will go up corresponding as compare -- oil increases. Is that the way to see it?

Not really, yes. The 2 wells that we have drilled indicate this is more oil field, and we will be chasing more oil in this field than gas.

Okay. I understood, sir. Sir, in the light of the recent commentary on B-80, where the results have been revised upwards. So this the impact of this would only be in the extension of the life versus the revenues going up in the next 1, 2 years? Is that how we should understand?

Yes, I think initially, definitely, we are absolutely certain that the extension of the field life for a much longer period, as you have explained, beyond even the current contract period. That -- and we have come up with a strategy that will ensure the economic fuel remains for a long period. In terms of additional production through additional wells really will be based on after seeing the production history for some time.

Okay. Because the reason I'm asking is because you intended to use the cash flows from this well in scaling up PY-1 and other assets. So I'm just trying to understand how do you balance it out? And what are your thoughts there? So is that -- in the next 1, 2 years, should we see it scaling up? Or what I'm trying to understand of about B-80.

No, definitely. In about 2 years' time, we would be doing additional wells in B-80.

Now we kick the 5,000 barrels of oil and that we should see next 1, 2 years.

Correct.

Next question is from the line of Deepak Poddar from Sapphire Capital.

Just wanted to understand like in terms of overall barrel of oil volume target for this year, FY '22 and FY '23, is there any kind of indication that you have given or would like to share?

Not really because everything really -- big change is going to be from the time we bring in B-80 production. That, as we guided, will happen in Q3 which specifically in which one is very difficult to predict [indiscernible] know about the situation.

So for the next year is -- that would give more clarity by next year. So...

Yes, true, next year. So on the -- what I've been saying earlier also that we will focus on the net production from now onwards. So if you look at last year, our net production was roughly about 2,300 barrels of oil equivalent. That as a net to B-80. When we bring the B-80 in full production mode, which will happen in Q3. Our net entitlement production will go up to 7,000 barrels of oil equivalent. That's almost 2x more than the current level and then onwards. So that will guide the next year production.

So 7,000 is what we are targeting next year, right?

7,000 barrels of oil equivalent total for the company net to company oil equivalent.

Next question is from the line of Rikesh Parikh from Barclays Securities.

Sir, can you just share the point about Dirok commercial production I mean how much volume we sold as per the new per sharing contract?

Rikesh, I think what you're asking is, right now, the field is producing roughly about 32 million standard cubic feet per day. Out of that, when we -- right now, whatever volume that we are producing is being sold to Oil India at the government notified prices. We went for an e-auction where we had given the option to buyers to quote both for on a firm basis as well as on fallback basis. For firm basis, we get -- we got bids for 1/3 of the volume at a $1 premium over the government notified prices. So from Q3 onwards, 30% of our production will be sold at $1 per premium on a firm basis. The balance will also be sold on a premium to directly to the customers, but they are on fallback basis, which means effectively, whenever there is additional demand by the customer, they will draw from this gas. -- if there is no additional demand from a specific customer, the gas will continue to be sold to Oil India. So as we move at least a couple of quarters, things will stabilize in terms of offtake by the private direct offtake by private customer. Now for the buyers also like the seller, they will also first exhaust the cheap gas before they bid for this -- before they opt to take gas from a premium gas like Dirok. So have I answered your question, Rikesh?

Okay. So the higher realization will be coming from the Q3, right?

Yes.

Next question is from Mayur Patel from IIFL AMC.