Hindustan Oil Exploration Company Limited (500186) Earnings Call Transcript & Summary

Ladies and gentlemen, good day and welcome to the Q4 FY '20 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, sir.

Thank you, Ayesha. Good morning, everybody, and a warm welcome to you all. My name is Anuj Sonpal from Valorem Advisors. We represent the Investor Relations for Hindustan Oil Exploration Limited. On behalf of the company and Valorem Advisors, I would like to thank you all for participating in the company's earnings conference call for the financial year ended 2020 and the fourth quarter of financial year '20. Before we begin, I would like to mention a short cautionary statement as always. Some of the statements made in today's earnings conference 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 information currently available with 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. I would now like to introduce you to the management of HOEC participating with us in today's earnings call. We have with us Mr. P. Elango, Managing Director; and Mr. R. Jeevanandam, Executive Director and CFO. Without much delay, I request Mr. Elango to give his opening remarks. Thank you, and over to you, sir.

Thank you, Anuj, and good morning, everyone. Hope you all are safe and fine. We extend a very warm welcome to our call on annual results for FY '20. I have with me our CFO and Whole-Time Director, Mr. R. Jeevanandam; and Valorem Advisors and Investor Relations advisers. We welcome team Valorem, who have joined us this April. I hope you all have received the updated investor presentation. We have also updated -- uploaded that on our website for your reference. All of us are witnessing unprecedented times. This global pandemic has brought uncertainty to businesses across sectors. In oil and gas industry, we faced the added challenges of price crash, excess supply and demand cut. Through the lockdown, we have managed to continue our production operations at all our operating sites. We could secure the permits to continue since oil and gas production fall under essential services. We took all the precautions required to protect the health of our employees and associates. We also helped the communities around our operating areas, both in Assam and in Tamil Nadu. However, production has been curtailed significantly due to end consumers shutdowns. Subsequently, Dirok offtake has improved during May to touch the near-normal production rates during the last few days. During FY '20, various offtake issues at Dirok and PY-1 fields and lockdown during the last week of March prevented us from delivering to our full production capacity. HOEC produced an average of around 7,800 barrels of oil equivalent gross production per day during the year. This is 20% lower than our production capacity. Unlike oil and gas, gas production will continue to be determined by end consumers offtake. In B-80, we have safely and successfully drilled, completed and tested our second well. This was done by continuing the drilling operation through the COVID lockdown despite formidable challenges. However, lockdown and other operational issues stretched the campaign duration, resulting in time and cost over well. The results from the second well have been much better than expected. As a team, we at HOEC are delighted that we could identify a block with the resource potential, bid, win, plan, fast track, drill and test to demonstrate a production potential. These 2 wells have been completed with subsea systems using a jackup rig for the first time in India. Obviously, we would have been happier to have established such an excellent resource base in western offshore at a different price and business environment. In the current uncertain environment, we wish to proceed prudently, sourced more diligently to optimize the remaining CapEx commitments. In parallel, we await announcement on fiscal relief and incentive packages from the government that can help to bring down the breakeven price below $35 per barrel. B-80 field has now demonstrated production potential of 8,000 barrels of oil equivalent per day from both the wells. When brought to production, this will double HOEC's current gross operated production levels. The FSO Prem Pride meant for B-80 is mobilized to Sri Lanka, drydock and other refurbishment and additional fittings work can commence only after the lockdown is lifted. We will place orders for flexible pipelines and CALM buoy mooring system once the current lockdown situation ceases. We will also watch out for post-monsoon insulation work in western offshore, so that the cost can be optimized by sharing required insulation marine spreads. Our endeavor would be to undertake all the insulation work post monsoon in November and complete as well as possible dictated by weather conditions. We expect B-80 gas to fetch a better gas price. This is because Gujarat gas market is supplied through imported LNG via long-term contracts at premium prices. Since the current gas market conditions are not conducive, we will delay our marketing tender and float it at an opportune moment. Considering the current uncertain environment, we plan to focus only on bringing B-80 to production. We will defer any other significant capital outlay until the market and prices stabilize and the government reviews its current gas pricing policy and formula. Our short-term strategy, therefore, for this year is to focus on reducing operating costs and working with the end consumers to improve gas offtake from Dirok and PY-1 fields. In custom, we are optimizing production and reducing costs in close collaboration with the operator, GeoEnpro. We will choose an opportune time to execute Phase 1 involving drilling of 18 rigs. The industry has requested for fiscal relief from the government involving reduced royalty set profit petroleum and free market pricing for gas. The government has constituted a committee to suggest relief measures for upstream oil and gas companies. Irrespective of the decision of the government on fiscal relief, we will continue with our production operations and complete the B-80 development project to deliver first trial. I now invite our CFO, Mr. Jeevanandam, to take you through the financials.

Thanks, Elango. We report that the company made a revenue of INR 35 crores in the current quarter against INR 51 crores in the previous quarter. And for the year, the revenue is INR 201 crores comparing INR 247 crores in the previous year in the stand-alone accounts. In consol accounts, it is INR 55 crores against INR 67 crores in the previous quarter. This reduction in revenue is due to poor by offtakes by Oil India limited in Dirok and the reduction in PY-1 production. Profit before tax with the exceptional is INR 140 crores comparing INR 150 crores in the previous year. Profit after tax, including exceptionally item of INR 26 crores, which includes a write-back of INR 22 crores and 2-decade old tax refund order of about INR 4 crores. This quarter profit on stand-alone is INR 19 crores against INR 30 crores in the previous quarter. In the consol accounts, profit after tax for the year is INR 137 crores against INR 157 crores in the previous year. There is a reduction of about INR 20 crores. Total expenses of stand-alone is INR 87 crores comparing INR 99 crores in the previous year. For the quarter, it is INR 17 crores against INR 21 crores in the previous quarter. Statutory levies such as royalty and cess and depreciation, depletion are linear to production, which is the reason for a reduction in the cost. For this quarter, the total expenses, including depreciation and depletion in the consolidated account, is INR 30 crores comparing INR 24 crores in the previous quarter. In the consol accounts, the total expenses for the year is INR 113 crores comparing INR 123 crores in the previous year. Operating cash flow for this year is INR 149 crores comparing INR 177 crores in the previous year. In consolidated accounts, the operating cash flow stands at INR 154 crores comparing INR 190 crores in the previous year. The company's stand-alone has a working capital of INR 185 crores with the cash and cash equivalent of about INR 141 crores as on March 31, 2020. In consol accounts, the cash and cash equivalent is INR 176 crores as on March 31, 2020. [Audio Gap] mobilized and installed. Mobile offshore processing unit is ready to move from yard at Dubai and is to be dry-docked, which will be connected to the single-line mooring, planned to be installed in the last quarter of this year. And we will make a reasonable return at an even at an oil price of $35 per barrel. And our post-tax rate of return on this project even at $35 would be 25% plus. These facilities are normally procured through service companies with the long-term contracts. These facilities are resourced through our own subsidiaries with borrowed capital of about INR 85 crores, which leave us around 33%. These assets such as mobile offshore processing unit and the FSO are movable assets, and there is a value uptick when it is put to use in the field. These facilities are owned and operated by our own subsidiaries, which could unlock about 20% post-tax return at the current market prices. This will enable us to operate the B-80 field with a marginal cost, which ensures a more recovery from the field. The overall growth of E&P assets in HOEC and its subsidiaries in oilfield services could be funded by internal accruals and asset-backed borrowing through subsidiaries. Thanks, Elango.

Thank you, Jeeva, and we can now open for questions, please.

[Operator Instructions] The first question is from the line of Chintan Sheth from Sameeksha Capital.

Hope HOEC team is safe and sound. Sir, first question on the fourth quarter consolidated OpEx, which increased sharply from INR 2 crore run rate quarterly to INR 8 crore this quarter. Can you just point out what led to such sharp increase? That's one. And second one, the CapEx, we have spent around INR 300 crores on the consolidated account this year. What will be the CapEx in FY '21 we have planned?

Okay. And the first is consolidated accounts that you could have seen that the INR 6 crore increase, we made a provision for one of the disputed liability, which is being with the government, the auditors insisted, you make a provision for it. So that is a noncash item we made a provision for about INR 6 crores. That's why the other expenses you could have seen from, it has increased from INR 2 crores to INR 8 crores. That's the only the major increase. Otherwise, you look at the cost and share of operating expenses remain the same. And royalty and cess is effective from -- it's got reduced. And the employee expenses as benefit expenses increased because then some of the allocation cost of the GeoEnpro has to be made into the books. Then -- but for that, there is no increase in any of this expenditure, which you couldn't see that from the accounts.

So I can see in the cash flow, unwinding of discount on decommission liability of INR 5.35 crore. That is what you are referring to for accounted this quarter?

No, no, that -- you go to the other expenses. The previous quarter was only INR 2 crores. That has increased to INR 8 crores. Okay? This gives us the twin benefit because even the account for it because Geopetrol, we have to pay the tax. So that gives us the tax cushion there on. So we have accepted that as a liability in the books, but it is a long-term dispute, and there is no cash outflow on that.

Sure. Okay. And on the CapEx front, sir?

The CapEx as such, we have to incur this financial year about [indiscernible] for our share, about $14 million to $15 million. This is if you take from the March through, from April to year-end, we will be including the facilities, well connection and all, we have to incur about some additional $15 million from our side, so 50%. Then the balance would be funded by the partners.

So in total, will be around $30 million or...

$30 million, right?

The next question is from the line of [ Ravi Sundaram from Sundaram Family Investment ].

Hope you and team are doing safe. My first question is on B-80. So your recent press release was very informative, but when are we expecting that the first oil will flow and start being commercialized, sir, any time line?

Yes. As we explained, the remaining part of insulation work can start only after post-monsoon, which is after November. What we are looking at -- sometimes depending on when the weather window sets in, we would come and see insulation work. The work in itself is about 45 to 60 days duration. But as I pointed out in the opening statement, we will look for what level of activities are going to occur in western offshore, so that we can share, if possible, the mobile offshore spread to optimize the cost. So in terms of time duration, it's 45 to 60 days of work. It will require some offshore insulation spread, which we'd look for. In any event, we expect everything to be done by end of this financial year for sure. So it could be anytime between -- it can happen by January; if you find the right resources, in November itself and completed in November-December; by end of December, we can start; or if you had to delay by a month or so, we would do that. The idea is to ensure, going forward, CapEx is fully optimized, and we do diligent sourcing.

Okay. Okay. Sir, that was informative. So one quick follow-up. So when we say first oil, I think they're also talking about gas as well, right? I mean both become commercial at the same time. Is that what we are saying?

Correct. Yes.

Okay. Both become commercial at the same time.

Okay. Sir, the second question is on something related to what you had mentioned in the opening remarks. Is there -- as a forum, from our industry, is there some pitch that's being made to the government about reducing the cost of production? I think you mentioned $35 is the production cost for B-80. So to reduce royalty or related costs that we pay to the government, is there some progress on that?

Yes, look, there are 2 different bodies. One is the Association of Oil and Gas Operators, which predominantly consists of all the private operators, including public sector companies. There is another forum called SEBI, which is dominated by all the public sector companies as such. Both the forums have made representation to the government. In fact, the average breakeven price for major producers in the country is about $45. That's what the representation they have made. And the government has reviewed the representation -- formulate -- set up a formal committee to look at the representation from the industry. We do expect some relief to come from the government. But as always, it's something that one cannot be certain with any time frame. But specifically, the B-80, what we had earlier advised was our breakeven price would be below $35. And so our focus is to bring it down further by optimizing the remaining CapEx, and as Jeeva explained, we've got a fairly flexible OpEx model because both the mobile offshore process unit as well as the FSO would be the company -- group companies of -- 100% subsidiaries of HOEC would have a ownership stake. So there is some flexibility to ensure that the upstream field always remains, the breakeven point is further reduced.

The next question is from the Sreemant Dudhoria from Unifi Capital.

So firstly, a few questions on the B-80. While your current breakeven price is $35 and if you're looking to start the first oil in the month of, say, December or January, if the prices remain at the same level, would you be looking to commission this project? Or would you be looking at better pricing?

Our effort would be to continue to complete the project and commission it because, in addition to the oil, we have -- the field will also produce some gas. So broadly, we are looking at -- we would -- over the next couple of months, we will be able to determine gas price, there's enough demand for the gas in the Gujarat market. We expect the gas to be -- priced to be in the order of $4 or so. And with that revenue, meeting the operating cost of this facility will not be a problem. So we are not planning to wait for the prices to turn around. We will continue and see how we can focus on reducing the cost further.

Sure. So based on your assessment and the initiatives that you are taking to bring down the cost for this field, what is the realistic kind of assumption? How much could the cost come down to for your further investment in this field?

See, the project to be executed is around some another $12 million to $14 million, right? This $12 million to $14 million, we can optimize the cost when there is a vessel movements taking place in the last quarter of this year. That will reduce at least about 10% of the total cost to us. So every penny earned, say, rupee is earned to us. So that is a good for us. Second thing, this block is having a potential to produce about 8,000 barrel of oil as such. That's what been told. If that is the case and that has been tested also. So in essence, at $35, we would be -- the project return is more than 25% post tax, right? So we have no problem in putting the field on production at $35. Second thing, we have got a floating storage offshore, which is having...

Sorry, sir, your voice is breaking towards the end.

See, we have -- at $35, we should be making a return, which is 25% post tax. On the top of it, we have a facility there, which can accommodate about 6 months production, at least 6 months production can be stored in the facility. So by floating production storage offshore, the vessel which we purchased is about -- can hold about 1 million-barrel as such. So we are not in a hurry to sell the oil immediately. We would like to store the oil for an appropriate price. And in -- and that makes us more flexible to us, at a right price, we can sell, and we are not posed to sell an oil at any price which is there in the market.

Right. So if I connect the statements made to the first query that I had, once you commissioned the project in the month of, say, December, January, if the prices remain at the current levels, you will be looking to store it for 5, 6 months because you have that much of storage capacity, and maybe you'll wait for better pricing. Is my understanding right?

Your understanding is absolutely right. That's what we will do it also.

Okay. So then the actual realization may be coming in a few months after taking the first oil from this field.

That's right.

Okay. I got that point. Secondly, coming to the PY-1 basin. Sir, I think the production levels have come down drastically in PY-1. How are things now? Is there an increased offtake by your clients? Earlier, you have also guided that you are looking to partner with a few more clients in this basin. What is the current status here?

So the current status is -- look, at least this in this part of the country, there is a huge drop in the demand for power sector. And because the gas price in PY-1 is fixed at $3.68 per MMBTU against the APM price of $2.39, any gas-based generation from this gas obviously comes far below in the merit order in addition to the overall demand in the power sector. Gas can be only sold to power sector players in Tamil Nadu because they are the only consumers. We do not have anyone else. That is one. The second issue that we are facing is because of this inconsistent offtake at a much, much lower uptake, the well productivity has also come down. We are facing 2 different challenges here. One is that the offtake level is very low. The other is well productivity has come down. Therefore, this will require us to mobilize a rig for intervention, which we will not be able to do that immediately. We look at that along with the overall drilling program to access additional resources in PY-1. A lot of technical work is going on to prepare for a full field development for PY-1. With that, we should be able to address both the marketing and production issues.

Sure. So given the kind of vagaries of production at this field, how much has the production level, the capacity has come down? Earlier, it was about, I think, 10 to 11 MMSCFD. What is now the peak production from this field?

If the production is consistently -- if the offtake is consistent, we should be able to do about 40% of that capacity.

Okay. It has come down to that level. Is it about 6 MMSCFD?

It was doing about 8 to 10. Now it can do about 4 to 5.

Okay, okay. You had plans to kind of increase spend further CapEx in this field. You're expecting that the rig cost would actually come down, and the current scenario would help you to expedite the CapEx in PY-1. Is there any change of plans in PY-1 because you'd earlier mentioned in the opening remarks that you will hold on all your further CapEx in the near term?

See, essentially, we are looking at need capital for this block. And if you bring a rig for the workover, we would be rather drilling a couple of wells in the nearby vicinity. So that's what our plan there on to it. So these wells are at the shallow wells, which is around 1,600 meters, which contributes at a cheaper cost. So we are looking that this current market is the right time to develop this type of a field because the value is prefixed because the gas price is prefixed there into it, you are not getting worried about it. So your cost is getting reduced, it gives us an opportunity to develop this block. So our G&G group is seriously working on this block. And they will come out with the location, and then we'll work it out an economic model. And then we will see that once -- sometime in the month -- in the year-end, we will start planning to drill some wells and depending upon the availability of the rig in the vicinity. We don't want to pay any mobilization costs. If the rig is available in the East Coast, we would like to mobilize it and puncture some holes, and that would be able to -- it will ramp up the production back to the previous level.

Which is about 8 to 10?

Yes.

Right. So in the near term, in the next, say, in the first half of the current financial year, the production from this well, should we expect at the same levels as that of quarter 4?

I think probably that would be the best way to look at that.

Sure. Coming to the Dirok field, you had mentioned in your opening remarks that the offtake from this field has come back to near-normal levels. If this -- there were some disruptions at your client level in this field. Is it all back to normal? Or have you found out new customers had oil or you found out new customers in the Dirok field?

So it is -- there are no new customers that have been added. We are -- existing customers are Oil India, who are coming back after the lockdown. So the demand has picked up now.

Okay. I meant customers for Oil India itself, your indirect customers.

Yes, correct.

Right. Okay. Sure. On PY-3, sir, any further developments there?

No, there is no further update on PY-3.

Sorry, sir?

There is no further update on PY-3. I don't know viability at the current price level.

The next question is from the line of [ Vaibhav Badjatya ] from [ SMI Investments ].

So we have been mentioning about the breakeven cost of production for various fields. So can you just give us a highlight as to whether this -- what is the breakeven cost of production for all the fields and including and excluding the depreciation and amortization charge, so that we can have an idea as to at what level different fields will at least recover its cost for investments?

See. One way is looking at the marginal cost and marginal revenue. If you don't look at the development costs, the cost there into it and all our gas, any price more than $1, we are viable there on to it. And in case of an oil, but for the government levies, anything about $25 to -- anything about $35, we make a 25% post-tax return. And in absolute cost terms, we'll be able to operate around $20 to $22 comfortably.

So this is including the -- you're saying this is including the amortization charge?

Excluding the -- see, when you talk about $35, I talk about the project return, which is including the capital cost incurred there on to it. When you talk about the marginal cost, then my operating cost alone comes into the picture, none of our field is operating at a high cost. That is at the low-cost operation. Even in B-80, our operating cost per barrel is only $10. So we will be -- any price at $20, we will be posting some cash revenue to the company.

The next question is from the line of [ Sharat Sharma ], individual investor.

Sir, a quick question. The pricing of $2.29 MMBTU till now is not kicked in in Q1 also, right? It will -- the first effect will be from October 1 through September 30, 2021. Is that correct?

No, no. This $2.39 has kicked in effective April 1.

Okay. Kicked in effective April 1. Okay. But -- I mean -- and till when would the effect last in our books? Would it be 12 months through March 31 '21?

Till September, the end, will be this plan for Dirok. And so PY-1, it will be at $3.68.

Got it. But Q1 and Q2 of this year, there will be a marginal hit of around 20%, 25% due to the pricing, correct? The rough pricing.

[indiscernible] two things. If the government comes out with some reduction in the royalty and says the -- removal of the royalty and says that will get compensated. That's what the industry demand as at the moment.

Got it. And just the second question, sir, for March 31, 2020, what was the impact of stock valuation or something just given the oil prices are crazy? And what would be the quantum of write-back?

Write-back on the -- which one you're talking about?

Just stock -- any stock in [indiscernible] as of 31st you evaluate at the oil price?

The only that we are selling the condensate and the gas, and a very, very small volume of oil is there, which will be taken on the March 31 price itself. So there is...

So nothing material write-back, no write-downs in March as such?

Yes.

[Operator Instructions] The next question is from the line of [ Nirbhay Mahawar ] from N Square Capital.

I just wanted to understand the DAT, for -- in the press release, you have mentioned that in our D2 drill, we got output of around 3,300 to 4,600 BOPD. And in D1, we have got 7,000 barrel plus output. So the -- if you put together, I think this number comes around 10,500 barrel and we are talking about 8,000 barrel plus. So what is the disconnect?

See it's not disconnect. What happens on the test conditions, we will -- we don't want to flog the vessels at the same level. So it is our reservoir modeling will advise us. So that's why we have not put the entire volume into that because that would be a much higher number. But we reduced the numbers to maintain the reservoir purchase and overall hail. So the studies are going on to it. Probably we may come up to that number, but we don't want to -- for all practical purposes, we took it as 8,000 barrel oil equivalent.

So we are trying to give conservative guidance, right.

That's right.

Yes. So -- and what would be the breakup of this? Let's say, this 8,000 barrels in terms of gas and oil, what would be the breakup of this?

Oil is about 5,000-plus barrels, and the gas is about, say, 3,000 oil equivalent.

Okay. So around 20 MMSCFT could be gas?

Around 15 to 18, we are talking about.

Around 18%. Okay. Now sir, what is the total CapEx of this field?

The CapEx of this field is coming around $50 million, all put together. And then it is having an additional -- the two facilities, which we are going to mobilize, that is about 1 MOPU and FSO that would cost around, say, additional $35 million to $40 million. But that's movable assets, which is usable elsewhere, which is salable also.

Okay. So would it be -- let's say, if we take an assumption of around $4 rate gas realization and a $35 oil price, would it be fair to assume that next year onwards, we can have close to INR 600 crore field level revenue from this?

No, you understand that we are having about -- your assumption is absolutely correct. That is INR 600 crores would be the revenue, INR 600 crores plus would be the revenue. Our share would be INR 100 crores. The cash would be about INR 125 crores because the INR 25 crores will go to our subsidiary in essence because they are putting the facilities thereon. And we have to give about some INR 45 crores to the government take. So total put together all would be INR 170 crores, we'll be making a profit, which is in the order of INR 100 crores to INR 100-plus crores.

INR 100-plus crores. Okay. And when -- so can we say breakeven price of $1 or $35, so this includes capital cost also?

Yes, it is. Capital cost and the return for our risk capital.

That also includes at breakeven level. Fair enough. Fair enough, and sir, I was just trying to understand this revenue sharing model. So -- so you've got government share of revenue at -- LRP is around 12% and it goes up to 55%. So how will it move, I mean, just to get sense?

It is actually based on the linear. So it has to divide by 55 by 1 million and the revenue there on, that would be the rough with plus/minus 5%, that's the volume to be shared with the government.

So in the initial phase, you will be hearing 12%? Or how is it? I'm not able to understand this.

What happens, suppose I make $10 million revenue, then I have to pay every $1 million if it is $1 million to $10 million [indiscernible]

I'll just explain that. See, if the revenue per day is below $10,000 from the project, right, then it is at the lowest point, which is 12%. If the revenue per day is more than $1 million per day, then that will be at the highest point. The revenue in our case would be, if you take about $200,000 per day, so it will be linearly moved. On an average, we had guided about 22%, 20%, [indiscernible] that you look at $200,000 divided by 20% or 55%, that's all about 12% would be the revenue sharing. If you look at our presentation, we put the model there. You can just take a -- refer that out.

Yes. I was trying to understand through that, but I was not able to. But in any case, yes, now I'm getting. Also, what is the reserve estimation? So what is your field life estimation based on the ?

Yes, this field is having a potential because our geologists have come out to the -- they've carried out all the test and the data required for any geological model for this. What we have got -- the D1 well, you can look at, they've got all the data. With that, this is only one side is estimation, which has been made. Now we have to look at the northern side there also into that. So we will be looking at bigger reserves -- little bigger reserves than what we initially estimated. They will come out with the geological model, which will be vetted by the [indiscernible] client, and they will come out with the correct number, authenticated number to you by 3 months down the line.

Okay. So the number, which is mentioned in your environment clearance thing of 30 Bcf and around 1 million barrels, this could be much bigger than that, is what...

In our presentation, we had it the -- because it was a discovered field, so when the government announced these blocks, they had ONGC's estimates on the in-place resource in the field as such, in the block area as such. Subsequently, we have carried out our initial assessment without -- prior to drilling the wells and then went with the field development plan, with our resource estimate, which is what we have shared in our presentation. Now what Jeeva was explaining is post drilling of these 2 wells, you've got much more data about the well, and the team is working on revising the estimate. What we are confirming it, it will be more than what we had initially advised, whatever drives in the initiative, right? We will come the -- we will complete our internal work, and we will give you with DGH post that, we will also have an independent third-party view of that and then come with the final numbers related to B-80.

Just one more question regarding PY-1, sir. You have mentioned that PY-1 is operating -- in the presentation, you have mentioned that it is operating at a below normal level. So let's say, over a medium period of, let's say, 3, 4 years, what kind of output, we can again target from PY-1?

PY-1, as Jeeva explained, we will come back with a plan. What we have done, if we take, 2 years -- a couple of years back, we did undertook an intervention program, which we reentered the existing wells and sidetracked them. And that resulted in increased production. Unfortunately, for us, the offtake was not consistent. What happens in offshore wells is if you keep on -- have to keep on reducing varying the production rate, it affected as well productivity and performance. This is what -- unfortunately, we are caught in the situation where there was inconsistent offtake. Now we are reviewing all data. We believe the resources definitely exist. And we need to do an intervention, which also looks at drilling additional new ones, leveraging the current environment. Right now, as I said in my remarks, we just want to focus on B-80, complete the remaining work and bring it on production hopefully by end of this year. And then parallelly, the work is going on on the PY-1 to reach a level. On the demand question, I just want to further clarify. When you achieve a larger production rates, then you have your option of marketing that opens up into multiple sector, which -- so overall, we do not believe that there would be difficulties in selling the gas if you increase the production rate to a below -- above a particular level. So give us some time to complete the work on PY-1, we'll come back.

So sir, we -- like in this field, initially, we had an output of up to 55,000 MMBTU. And then it got below 10. Now let's say, what could be the potential back if things -- if we are able to...

You're asking like a journalist question now?

Sir, I don't understand -- my technical knowledge is very limited. So please, excuse me for my...

I'm also saying allow us to do our work and come back with a plan. And I think you've got to -- in the context with which we are currently there, we can do -- we will focus on B-80, get it on stream. And then we have all the resources to do whatever what wish to do in PY-1. The work is already happening now based on what we observed.

The next question is from the line of Chintan Sheth from Sameeksha Capital.

On the PY-1, again, sorry to dwell more into it. You mentioned that once the critical size is being achieved, then it's not an issue for the marketing and finding new clients and sell it. So that is our -- the last call we had mentioned about one of the power plants nearby which we are in discussion with, that will be one of the clients we are looking at vouching for new production?

Correct. That would be one of the clients. And also, as I said in the last call, there are other players who are located in the -- this -- our plant in particular you told is located in Tamil Nadu, it's very close to the Pondicherry Union Territory border. But due to various historical tax advantage reasons, a lot of industrial players are located with the -- in the Pondicherry region as such. And some of them are keen to source the gas either through pipeline or have a captive power plant in their respective unit and then do the power transfer as such. So the point I'm making is if the volume of gas that we produce increases, then we would be able to address the marketing issues much more efficiently.

Right. But then you also mentioned that at a fixed price of $3.65 and the drilling prices being lower, that also hurts the offtake because the packing order from the buyer will prefer the APM gases whether they buy from fixed rate gas rates from your field.

Correct. That affects power producers who depend on -- who generate power and sell it to the state electricity board. It's not players who want to use it for captive power consumption.

Right. Right. So they don't mind paying higher, but the consistent supply will be of more importance for them.

Correct.

And on the Dirok, again, the -- now the Dirok part which we were planning to explore further, we are kind of pushing it back to FY '22, that's the right understanding now?

What we are doing in Dirok is, there are 2 things. As you said, effective 1st April, the gas price for Dirok has come down to $2.39. The demand from all the major players in North East region, which are basically ONGC, Oil India and us, with representation to the government to either free the gas marketing and pricing to the companies and/or reset the formula as such. Because at this formula level, because we have a lower operating cost model, we are able to generate cash surplus. But it is on an average, if you look at cost of producing a field in North East region, definitely, these prices will not sustain up. So one is, over the next couple of months, we expect what policy changes in respect of gas pricing and marketing the government will announce. We expect some cost at least to come there, but it's something that we would look at. The second part is about consistency in offtake in Dirok as well to come back, which we are seeing now. But if you look at the whole year last year, we had -- we were able to maintain about 80% -- 75% to 80% offtake only because overall offtake was at that level. Though we had a capacity to produce on an average 1 million cubic meters per day consistently, but the offtake was about 75%, 80% only. So we are also pushing and looking at what kind of an alternative customers that we can identify in Assam and slowly reduce the dependence on Oil India. This work is also we're doing. So -- and third element is in terms of the project execution, while continuing the production operation from a ring-fenced area is safe, spreading your resources for a project execution raises health risk which is a different level. So overall, before we take any call on doing projects in onshore, spreading our resources, we need to see how this pandemic pans out, what kind of a policy support government is going to give, and thirdly, what kind of an offtake -- how consistently the offtake will be. So these things on basis of which only we will be taking. We have not really stopped any work. We are continuing to place orders that are for long lead items. We are continuing to pursue the regulatory approval process. For example, the public hearing which was scheduled to be held could not be held due to the lockdown. All that will happen. I think by the next quarter, we should be able to have a much more clearer picture on that. But we are -- we have not put a hold on the project. We are doing -- focusing on the long lead item and we'll come back, depending on how the next few months pan out, we can further schedule.

[Operator Instructions] The next question is from the line of Siddharth Misra from Fidelity Investment.

My question is on Dirok. You mentioned that by end of May, the offtake has come back to normal level. So the peak production used to be 35 MMSCFD. So has it come back to those levels? Or it's still lower than that? And what was the trajectory over April and May for Dirok?

So it has crossed the 30 MMSCFD level, and we expect it to come back to 35 MMSCFD level going forward.

Okay. So this has crossed 30 MMSCFD right now. And in April, when the lockdown was there and all, there was...

Much lower.

The next question is from the line of Sadanand Shetty from Truequity Advisors.

My line has dropped between. I don't know whether you answered this question. What has been the oil price realization for the last quarter? And the second question is you talked about delayed CapEx. Can you tell us which segment you are delaying the CapEx?

What is the first question?

What is your first question? Sadanand, we couldn't hear you.

Yes. What has been the oil price realization for the Q4 of FY '20? And what has been a different point of oil price in that quarter? Just trying to understand how did you manage to get price when now oil price has collapsed?

The average oil price realized for this quarter, fourth quarter, was $46 and quarter 3 is $56.

Yes. Was there a different price points in the Q4 when the price actually has collapsed?

Yes, because the price started collapsing in the March, offtake has been severely affected.

Okay. Can you able to tell us the lowest price point that you realized in that quarter?

The lowest price point is about -- we have gone up to, say, $37 or $36.

Okay. And the CapEx, the segment where you think you will have to delay the CapEx?

See the delayed CapEx is -- for B-80, we are going ahead with the full stream, we wanted to put the field on production as quickly as we can at a cost-efficient manner. And delayed CapEx means, for example, that whatever we want to do additional work in the northeastern states for drilling some of the wells, we have got an exploration block, that work will -- may get delayed a little. And the development well drilling, depending on the good service company available in India to build the wells because today, we don't have any good drilling company available for onshore drilling. So these are the things we have to look at carefully on this. And after that, we'll put some money there into it, but that will take place only in the next financial year, not this financial year.

The next question is from the line of Sunil Jain from Nirmal Bang.

Sir, about B-80, you said that 8,000 bopd production can be expected. So this is pure oil or it include gas also?

The oil will be 5,000 barrels plus and gas will be around 2,000 -- about 3,000 barrels of oil equivalent in terms of gas. So 5,000 and 3,000.

Okay, okay. And another question is like what we had seen risk in other field also like PY-1 when it was started long back, do you see any risk in this field also, B-80, after starting production, we may face some problem and all?

No, no, the PY-1 is what we call the basement reservoir. And B-80 is very -- a proven resource base in -- as part of the Mumbai region.

No, I was just talking from the point of view of like after starting production, then the production, what we assume is to scale down because of some geological reason and all.

We have about totally 7 wells in the block, which has been drilled by ONGC first. We drilled 2 wells, so our crude oil and gas as such. So there is no question of -- there is a -- on the subsurface, you cannot predict in a 100% basis. But our B-90 (sic) [ B-80 ] is the basis for your 8,000 barrel of oil equivalent because our geologists have told there is a 90% probability of achieving this.

Okay. Great. Great, sir. And sir, last question about -- you had mentioned something like a new lead. What that lead means? You expect -- what you explained right now that there will be higher reserve or something else?

There is some lead they've got in the Deccan Trap, and that would be -- they have to -- next well drilling will prove furthermore onto it. Then we will declare that as a discovery and then we put the reserve volume there on to it. Till the time, it will be considered as only a lead.

Okay. Means there could be another discovery as well?

Yes. Another -- it will add the volume to the -- in the block.

So that will come in our territory only?

Yes, yes, it is in our territory.

The next question is from the line of [ Mukesh Karthik ] from Barclays.

Sir, can you share the CapEx plan for 2021 and current year and next year?

Next year. Current year and next year.

See, 2021 is a focus year for the B-80. So the total investment plan is about $30 million for the block, out of which our share is $15 million. Other than that, small investments which we will look -- plan for the PY-1. And it all depends on the availability of the rig. As such to the plan from -- at the moment is about the B-80 development.

Okay. And for next year?

The next year is, how this year pans out, after that, we will decide about it. We wanted to look for a good drilling rig to do the work in the Northeastern region. If that we could identify a better rig which can deliver what we wanted, then we'll go ahead with that because we're having enough time there on to it and resource is also there into it. Because our G&G group, there's a new team is constituted, now they are reviewing the whole thing in a different manner as such.

Okay. And second, about this B-80 gas output. So when we will start getting the gas output from the B-80 field?

It will be around the same time. Along with oil, we'll complete all the works. As he said, the post November, we'll start.

It's around November, December.

The work will start post November. So around December, January, we should be able to. That's what we are targeting.

And the marketing, we have already completed, I mean, tied up.

We've had some initial discussion with 2 of the major players in Gujarat market. They've expressed interest. Definitely demand is there. Because we'll discover the price post the lockdown, so currently, there is a very depressed situation in that market. So we will determine, and we'll also need to complete some gas specification analysis of that. So we established demand for the volume. We need to discover the price through a tendering process.

Sir, I understood -- in the previous call, we have talked about $35 level for the crude. So for gas, have you decided about what price level we'll be comfortable marketing?

So, gas is actually -- it is a byproduct in this because both the wells are running oil there into it. It's come as more of a byproduct. So any price is good for us because that will reduce costs as well as increases the overall revenue, but we are not invested to sell below $4.

Okay. And in general, can you share some of your thought about the gas prices because it has been on the downturn? So your thought on that?

So overall, there are 3 gas prices prevailing in the Indian market. One is the government-determined prices, which is, as I said, $2.39. Then there are production sharing contract of private players who have the freedom to determine the pricing and marketing. Those prices are $6 to $7 in the Gujarat market. I know a field which we're selling at $8 per MMBTU on a long-term contract in Gujarat market from Rajasthan. Then the third part is the LNG. 50% of the India's gas is imported through LNG. Again, LNG is imported through long-term contracts. The long-term contract prices are in the order of $7 or so, although the spot LNG prices have crashed recently because of the COVID situation and there are players who use the existing LNG regas facilities in Gujarat to import LNG directly from spot market. So there is a combination of prices in the market. But Gujarat is the best gas market in the country with lot of optionality in terms of end consumption, you can sell it to commercial units, you can sell it to CNG companies, natural gas, other industrial and commercial users and GSPC, which has got a good network within Gujarat and a lot of optionality. So we are in discussion with GSPC actually. And they have confirmed to us this kind of volume can be easily marketed. And as you have said, we are targeting a price not less than $4 per MMBTU. Our target will be to substitute long-term imported LNG consumers.

The next question is from the line of Ashwin Reddy from Samatva Investments.

I had a question on the North East and Dirok fields. So given that things are now stabilized after about 1 year, I wanted to know, assuming in the next 2 years, what is your outlook in terms of volume [indiscernible] especially considering that OIL is also putting their own pipeline right to the gas hub. So I wonder what is the CapEx of the gas pipeline? And second, given that you're putting this in place, in the next 2 years, what kind of volumes can Dirok do?

Ashwin, the -- our outlook from a long-term perspective in North East is quite robust because as you would know that the government has announced a North East Gas Grid, bring imported gas from Paradip into the North East region after doing a lot of studies of demand, et cetera. One of the anchor customers for imported LNG transported to a long-distance pipeline is the Numaligarh refinery owned by BPCL. They have a large volume of demand and their economics has been worked out on imported LNG basis. So from the long-term or medium-term perspective, we believe that the production level of 55 million cubic meters, which we have considered from Phase 2 of Dirok can easily be marketed. But currently, our constraint is we are selling it at a place called Kusijan to Oil India and Oil India has got a limited capacity pipeline to transport it to Duliajan. So this direct pipeline to Duliajan would take us to the central marketing hub of Duliajan. From there, marketing gases to multiple customers will not be a problem. And for the near term, as we said, we expect Dirok offtake to remain in the range of 30 million to 35 million cubic feet per day, which is about 1 million cubic meters per day.

So let's put it differently. So in case the price goes back to around $3.50, for example, if it is $3.50 is what the price is for gas, so what would the volume that you would look at to work down?

If the price goes back to $3.50 per MMBTU, we would expedite the Phase 2 of Dirok campaign and complete the project and increase our volume from 35 to 55 by drilling the additional well.

And it can be done in the next 2 years -- in the next 2 years...

Yes, yes, definitely. On the -- let me explain that. There are 3 modules to the Phase 2 of Dirok. One is doing the additional well. And the second is expanding the existing plant capacity. The plant already has a capacity to process 40 million cubic feet per day. It has to be expanded to 55 with a very limited CapEx. We don't have to build a new plant, we just need to expand. Pipeline to take it to Duliajan, which we have already ordered the pipe, the pipes have already arrived. So this component -- all the 3 components can be executed on a fast-track basis. But the critical part item in a project of this nature is the regulatory approval. As I said, the public hearing which was to be held in February, could not be held due to various reasons. Earlier, there was the Citizen Amendment Act issue. Subsequently, the corona issue. So in terms of actual execution, it's a fairly simple project, linear project to be executed, and we will be able to do that definitely within an 18-month period.

The next question is from the line of [ Ravi Sundaram from Sundaram Mutual Fund. ]

Sorry, it's not Sundaram Mutual Funds, it's Sundaram Family Investments, just a correction. So my follow-up question was on the Deccan Trap formation, which you had mentioned in B-80. So are we at a stage to quantify it? Or is it still only at a lead stage, sir?

See, we drilled the wells, we got a gas source and the gas has been seen in the mudlog, it is about -- and further, we did some lock and evaluations. There is a proven -- there are resources absolutely available there, which is 7 to 10 meters. Now it needs to be delineated to the aerial extent of that. So we don't want to come and jump the conclusion on it based on that lead as such it is a great discovery. We will be drilling a couple of wells in the next say formation as this current development program is good. At that time, we will be deepening those wells, and we will certainly prove that, and after that, we'll come back to you saying that this is an additional volume added into the block. That is the right way to do that. So we'll be holding in that manner.

The next question is from the line of [ Sharat Sharma ] from -- an individual investor.

I'll touch on briefly again -- sir, the clarification on $2.39 pricing. That doesn't include the pricing of Jan, February, March from the global markets, correct? The weak pricing of Jan, Feb, March will come in the October APM that needs to be notified. Is that correct, sir?

That's correct. Correct.

Got it. So I mean -- and that pricing which comes notified in October 1 will be effective till 30th September, '21. Correct, sir? No, it's probably 6 months.

It's 6 months, yes, 6 months.

Yes, yes. But APM you'll have a follow-through. Got it. Got it. Okay, sir. And sir, very briefly, sir, you've a great chart that you invest in multiple or something. Just clarify my understanding, sir. So wherever you have a cost recovery of, let's say, 80%, right, and up on you have a 80% limit. After that, that's the government share in the table below? Or what is that?

See, there is a cost recovery limit has been put on to it. That is the limit per se is worth for the annual thing. Absolute cost recovery limit is 100%. You can entitle to recover 100%, but the annual limit put it on 80% of your revenue.

Got it. And then the government...

This is the strengthening of well life.

Got it. And those percentages are the government share then. On that, you pay a royalty, correct?

Exactly. Royalty is on the production as per the current guidelines.

Okay. Got it. But then what are those percentages, sir? Is that the multiples, let's say, 1.5 to 2, it's 25% up on...

What is happening is, it is basically your total revenue divided by your exploration development cost that is considered to be the capital investment. Your capital investment, the net return for you is revenue minus all your taxes minus your operating cost, that would be the investment earned there. And if the cumulative investment earned by your cumulative capital is more than 1, there is a percentage. If it is going more than 1.5, there is a percentage. If it is more than 2, it is a percentage. Like that, that is what is called the investment multiple.

Perfect, sir. But that percentage, what does that signify? Is that government...

That is called revenue share or project share.

Okay. So that is not part of our revenue at all, that will go to the government totally?

Correct. Correct, and that's related to revenues share.

Got it, sir. And just for Dirok and all, we are currently in under 1 multiple as of now, still, I'm assuming?

It is less than 1.5 at the moment. And so we will be getting into the profit share next year.

Okay. Got it. So I mean, a 10% decrease in revenue that goes to the revenue and then 25% and all, right?

That's right.

The next question is from the line of Vaibhav Badjatya from HNI Investment.

My call was dropped off earlier. So just -- I think you've briefly highlighted that our crude oil profit would be around INR 100 crore at $4 of gas price, around $35 to $40 of oil. So given the current oil and gas mix in our portfolio, at what level our PBT would be breakeven? This is as per current oil and gas mix? And also, what would be -- what those prices be after B-80 comes online?

Can you repeat, Vaibhav, please, the question?

Yes, I wanted to know that at what level currently, based on the mix between oil and gas currently, what would be the breakeven prices of oil and gas at -- so that our PBT is breakeven, basically practically 0?

See, I think if we wanted to make a 20-plus post-tax return for the oil, I should have -- including all my CapEx, everything, total recovery, and my investment wants a return of 20% post-tax return, I need an oil price of $35. For gas, for making the 20% return, I should need a gas price of $2.25.

$2.25. Okay. And this is 20% return, you mean to say, 20% IRR, right? That's what you meant?

Of course, it's IRR, post-tax IRR.

The next question is from the line of [ Tejas Shah ], individual investor.

What will be the revenue uptick? I think what we have discussed, what I understand is only after January onwards, our actual sales and everything will go up. So what is the revenue increase and the bottom line increase we are looking forward?

You mean from B-80, isn't it?

Yes, because you're saying your PY-1 is gone as such as only Dirok is working -- functioning properly. So the revenue, what I think we are -- what we got last quarter, I think more or less, it will remain the same up to the December, if I'm not mistaken.

See, the last quarter revenue is about, say, INR 28 crores, INR 30 crores, right? So we will be -- even if the current price is holding on good, we will be having about -- we have a turnout of about, say, INR 200 crores. We'll be reducing only 15% of the reduction in the turnover. Okay? So we -- that will get compensated by the -- substantially, the revenue base comes from B-80 development, which would be adding about, next financial year, minimum of INR 300 crores.

correct. So only the next financial year we'll make more money. And again, after this September, again, the price drop will come for the gas, correct?

That's what I'm telling you, if the price reduction is, say, 15% then I will reduce the 15% volume. So today, this year, you make a total revenue of, say, INR 200 crores, for the 15% reduction, still I'll come back to INR 170 crores. Okay? So correspondingly, there would be a reduction into my royalty as such and DDA as such, and my profit also would reduce only about some 10% then afterwards.

Okay. And another thing, I think you have showed some stocks priorly for some ESOPs. Now since the prices of company has gone down, any plans of buying it back?

Which one? The only thing is personally we don't have so much of money as such.

I think you have sold around INR 90, INR 95, now the price is hovering around INR 52, which has come up from INR 35. I think it will...

It is for the government as taxes. So ESOP, they're killing tax. So we paid the tax to the government full money as such. And our purchase price is equivalent to -- more than the current price.

That is what I'm saying. If you infuse some -- buying from open market, that will infuse the confidence also of the overall investors that, again, the management is buying back at a reasonable price.

[Technical Difficulty] separately to get some finance.

The next question is from the line of Yash Mandawewala from Mandawewala Enterprises.

So sir, the first question is on PY-1. So at the current well productivity level of PY-1 and assuming sort of full offtake, what would be the operating cost per MMBTU?

I'll tell you that [Technical Difficulty] but can you just give me a second. See, the operating cost in this block is more or less fixed as such. It is a very, very low asset. It is an indigenous crew, small crew, and the facility is there on to it and our operating cost per quarter is about only INR 3 crores. It means per month, it is only INR 1 crore. And the revenue is about INR 2 crores.

Okay. And so this is excluding the royalty and the depreciation?

Right.

Okay, okay. Got it. And so sir, if we sort of go back into history a little bit, there have been lots of problems with this particular field with regards to sort of production, and there were a number of write-offs that we have taken sort of 5 or 6 years back. So strategically, sir, I just wanted to get your opinion. Is it still sort of making sense to invest additional capital into this space? How do you think about that?

Now the additional capital which we are talking about is an addition to $400 million, right? So $400 million was the investment made. Now what we are talking about in the $400 million, our additional investment which you are talking about in the order of, say, $10 million, $12 million. So now we look at that addition made to the total cost. The total cost was the sum cost which we have written off in the books most of the things. Now -- but it is having a valuable asset sitting in the offshore with 8 slot platform and a pipeline and an onshore facility, which can process about 50 million cubic feet of gas. So what is happening in this case is that the development cost will be much lower, only what the cost we incur is the drilling cost -- drilling and completing cost. So it is ideally to look into that -- even a very, very marginal reserve can be put it on production in a commercial manner. That's where our G&G team is now looking at into the different pools, which can make a commercial sense out of it. All of them, they will come out in an idea to put one by one into production. Because drilling cost would not be much higher for this because it is about only 1,600, 1,800 meters drilling. And in the current market, we can be able to drill it at a cheaper cost. Then we have now developed an expertise on subsea completion also. With that, we can be able to hook up this well to the platform and can monetize quickly on that.

Got it, sir. Got it. Okay. That's very clear. Sir, next question is on Dirok. So have you seen any decline in well productivity from this field as well?

No, no. It is still producing very well. No.

Great, great. And sir, lastly, just a question on the balance sheet. So sort of year ended balance sheet, there seems to be a big increase in payables and other current liabilities. So can you sort of give some more information with regards to this? And when are we likely to pay this back?

See that most of the liabilities, particularly for the month of February and March drilling expenses for B-80 has not been paid because February invoices comes in the month of, say, March end, March 10 or March 15. That gives a 30-day credit period that gets into the April, actually. And similarly, March invoice comes in April, which gets paid in the month of May, right? And this is the way that a lot of accruals have been included in the books of accounts. But you could have seen there is enough cash in the company to pay for it.

Got it. So -- but sir, so we have enough cash to pay for this -- for the payables, sir, and the liabilities, but then do we need to take on fresh debt to fund the rest of the $15 million CapEx?

No. Actually, we are not planning for any debt for this -- any development expenditure of Hindustan Oil Exploration Company. And our subsidiary companies will be getting an asset backed financing. That means, we buy an asset where we'll put 2/3 of our money and 1/3 of the money we take it from the bank, that's what we will put those assets with less risk to the bank and no risk to us.

The next question is from the line of Chintan Sheth from Sameeksha Capital.

So following up on the previous participant question. So this INR 90 crore increase in the financial liability is basically dues payable to the contractors for Feb and March?

That's right. Correspondingly, we have to recover some money as a cash call money also to come from the partners thereon.

Okay. Right, right. And sir, on the -- during March, April and -- FM has announced a few of the projects for oil and gas in terms of this coal regasification and all. Are we looking at any opportunity in that front whereas that announcement has already been made?

I've no idea. Elango can explain that.

Chintan, we have no plans. We've got enough on our plate.

Right, right, right. And sir, on the GSPC bid we did for Cambay 4 blocks where we were emerged as L1. Any update on that front as well?

No. The other party has -- which had a right to match our bidder exercise, we were in discussion with them. And we would see in the changed environment, what makes sense to us.

Okay, okay. So we haven't done any -- haven't reached any conclusion.

There has not been further progress on that.

The next question is from the line of Sadanand Shetty from Truequity Advisors.

Yes. This disruption in Baghjan well #5 has an impact on our business?

No, Sadanand, no impact. That is a purely Oil India operated well. There's no impact on our operations.

Okay. Okay. Any incremental update on Hardy Oil?

Not, Sadanand, we have not heard anything of late. And we don't know at the current price levels, how is the -- what are the plans.

Okay. As industry is undergoing under the stress of COVID-19 and oil price, energy prices crash, can you -- you said some your view how the industry is doing, the player who has got the DSF oilfield and OALP. So is it that is a stress or people are not going for the CapEx? You have any insight that you can share with us?

So for us, overall, I think these are challenging time for all the upstream players. There are 2 segments of them. The public sector companies itself are finding it extremely challenging at the current price level, both for oil and gas. And among the private sector players, you have bigger players also struggling. And then you have the small players who came into this but also find it difficult. So all that leads to the question, government will have to do reforms on gas pricing and marketing, and also, some kind of fiscal measures related to cess and royalty. And all the indications are there that Petroleum Ministry is in very much favor of that. For example, if the royalty on DSF field is abolished or removed, we will benefit by 12.5% for our outsource in B-80. A 12.5% benefit is almost like $3, $4 per barrel equivalent. So that's kind of the impact it would have there. And I'd say, definitely, on the onshore side also, any relief in terms of royalty and cess would benefit all the existing players and definitely required for any new investment to take place. Since the government is keen on new investments, we're all hopeful that something should come sooner, if not to protect the private sector, definitely, to protect the public sector.

Yes, Elango, one just a follow-up question. You talked about $3, $4 benefit if that comes through royalty for DSF field. In any of your conversation today, did you factor that benefit?

No, we have not factored that.

So that will be over and above whatever the breakeven point you intend to lower.

Correct.

As there are no further questions, I now hand the conference over to Mr. Elango from Hindustan Oil Exploration Company Limited. Thank you, and over to you, sir.

Thank you. This is a lower-for-longer scenario for oil and gas yet again after 2015. Oil and gas industry in general and the management team of HOEC, in particular, has seen many price cycles over the years. We will adapt, survive and build our capacity to drive accelerated growth once the cycle turns. We plan to do this by focusing on 2 elements that we can control: to control costs and to build capacity. Thank you for participating. I want to assure you all that we are well prepared and well positioned to withstand this low-price scenario with our track record of low-cost operations and fast-track project execution. For any further questions, please reach us or Valorem Advisors. Thank you again for joining this call. Thank you.

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