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

Ladies and gentlemen, good day, and welcome to the Q1 FY '21 Earnings Conference Call of Hindustan Oil Exploration Company Limited. [Operator Instructions] Please note that this conference is being recorded. I now hand the conference over to Mr. Anuj Sonpal from Valorem Advisors. Thank you, and over to you, sir.

Thank you, Stephen. Good morning, everyone, and a 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 ended of financial year 2021. Before we begin, I would like to mention a short cautionary statement. 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 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. I would now like to introduce you to the management of HOEC Limited participating with us in today's con call. We have with us Mr. P. Elango, Managing Director; and Mr. R. Jeevanandam, Whole-Time Director and Chief Financial Officer. 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, and a very warm welcome to our call on quarterly results of Q1 FY '21. Hope all of you are safe. I have with me our CFO and Executive Director, Mr. Jeevanandam; and Valorem Advisors, our Investor Relations advisers. I hope you all have received our updated earnings presentation. We've also uploaded that on our website. For the last couple of weeks, the company has been in the news for wrong reasons. The issues raised about the liabilities of the company are important to all stakeholders and naturally so. We believe that this earning call is the right forum rather than media to state the facts, clarify specific issues and address any remaining concerns. And we will spend as much time as required to do so. But first, please allow me to update you with highlights of Q1 FY '21. Our Dirok field in Assam continues to set new benchmarks on safe operations. The field is producing at its full capacity safely, amidst raising COVID cases in the region. From producing around half of its capacity in April 2020, Dirok production has increased gradually reaching full capacity in June 2020. Average daily Dirok gas sales during Q1 was 28.3 MMSCFD. Increasing demand from consumers in the region for additional gas gives us confidence to achieve consistent long-term performance in Dirok asset. However, further investment to expand the capacity will have to await policy reforms on free market gas pricing. Industry has represented to the government to do so before gas prices for the next 6 months effective October 1, 2020 are announced. In PY-1 in South there had been prolonged customer shutdowns and inconsistent offtake, which have impacted performance of our wells, which needs some workover. This situation continues with the COVID-related lockdowns that resulted in reduced demand for power. Gas-based power plants continue to ramp low in the power purchase merit order in Tamil Nadu. During Q1, we had to temporarily suspend the operation for 10 days as a safety measure. Overall, PY-1 average gas offtake during Q1 was 1.5 MMSCFD. To enhance production, workover of existing offshore wells and new wells will be required. Geological studies are ongoing to plan the next drilling campaign in this unique fractured basement reservoir. Applications for environmental clearance have been filed and under process. Plan is to commence drilling in PY-1 after first oil from B-80. In B-80, Mumbai offshore, our project planning is gearing up to mobilize men and material when the monsoon window opens in November 2020. We are currently in the market to source flexible oil and gas export pipelines and the CALM buoy mooring system. The Mobile Offshore Processing Unit called MOPU, is ready to sail from Lamprell shipyard in Sharjah. Floating storage and offloading tanker, Prem Pride, is in Sri Lanka and will undergo drydocking soon. Considering the prevailing uncertain operating and business environment, our 100% focus is to complete the ongoing project works, install and commission all the facilities during the November, April weather window to deliver first oil from B-80 as soon as possible. Let me now turn to a few important issues raised in public domain about HOEC. First, did the company delay in disclosing about the interim order of the honorable High Court of Gujarat? Answer is no. We received the order by mail only on 25th August 2020 and promptly made the disclosure. Second, what is the amount quantified in arbitration award? Was it INR 27 crores? Answer is, again, no. Estimated amount of award involving HOEC share is USD 1.65 million. The award amount included certain ancillary items subject to reconciliation among all parties in regard to cash costs, payments and other credits between parties. If this reconciliation effort fails, the matter needs to be referred back to the arbitrators for determination. So far, no reconciliation effort has commenced. Third, when ONGC could reach a settlement on the award with Hardy, why did HOEC choose to appeal? The award by majority was in favor of claims made by Hardy against the 3 nonoperators, namely ONGC, HOEC and TPL. TPL and Hardy are controlled now by the same group. ONGC and HOEC were to jointly appeal, but then Hardy made an exclusive settlement offer to ONGC, waiving claims of more than half of the award sum. Details of the settlement have not been shared with us as yet. We will seek them in the appropriate JV forum. HOEC, based on legal opinion, believes that there are multiple grounds to challenge the award and has already filed the appeal in the High Court of Malaysia. Fourth, where did this INR 720 crores liability figure cropped up? And what are the current liability numbers? Section 9 of the Arbitration Act allows a successful claimant to secure an award if it has reasons to believe that responder would be unable to play -- pay the award sum if and when the award becomes enforceable at the end of an appeal process. It is a matter of public record that HOEC has a group balance sheet strength of over INR 1,000 crores, net worth of INR 665 crores and cash balance of INR 171 crores as on March 31, 2020. And the amount being claimed by Hardy was only INR 27 crores without any details. The claimant can request court to order appropriate security to secure the award as sum. Instead, Hardy chose to file an affidavit clubbing all current liabilities, noncurrent liabilities, contingent liabilities, claims not admitted by the company as sums payable to arrive at INR 720 crores. These items are not homogeneous. Apples and oranges can't be clubbed and counted in 1 category. Company has made a detailed disclosure, providing breakup of current, noncurrent and contingent liability. The sums under these various heads can't become payable together at any single point in time. Let me explain the largest single item in the basket of contingent liabilities so that you all can understand and appreciate the probability of its occurrence. Demand for service tax were received by operators of unincorporated joint ventures by wrongly treating operators such as HOEC as contractors who provide services to government and JV partners. Demand notices running to several hundred crores were slapped on multiple operators to pay service tax on work programs executed by operators on behalf of JV, cash costs issued to partners and royalty and profit petroleum paid to government. Industry made series of representation and Ministry of Petroleum supported the stand of the industry and wrote to finance ministry to issue clarifications that operators as co-owners with participating interest cannot be treated as contractors rendering service to companies. Operators would not provide services to government either. Including interest, the demand on this account is INR 173 crores and it is appearing as a contingent liability. Also, part of this sum pertains to joint venture are not this company alone. On merits, the companies have a strong case and hence all avenues, including legal remedies, if required, will be pursued in due course of time. On all such liabilities that are contingent in nature, the management will continue to make its judgment, explain the rationale to its auditors and classify them appropriately following standard accounting and industry practices and never ever will seek to hide anything from any of its stakeholders. I wish we had the time to get into details on each item. We don't. So I would make 2 broader points, and we will address specific questions in the Q&A session. Ever since the opening of upstream sector for private players in mid-'90s, there have been 3 policy regimes: pre-NELP, NELP regime under production sharing contracts and now HELP regime under revenue sharing contracts. Under PSC model, 2 legacy issues are: #1, penalty for unfinished minimum work programs; and #2, disputes on calculation on eligible cost petroleum to determine cost recovery and profit petroleum. Under revenue sharing contract model, there is no cost recovery involved and liquidated damages for unfinished work program is quantified as $1 million for onshore wells, $3 million for offshore wells. Since in PSC, liquidated damages have not been provided, almost every operator in the country has several ongoing legacy issues on this account. And many representations had been made to government and government has made several process improvements to govern future blocks under HELP. But unfortunately, legacy issues of pre-NELP and NELP blocks linger on. It will take long time to bring these issues to closure. Methods of calculating cost petroleum, profit petroleum, statutory levies such as royalty and cess and service tax computations are complex and their details give rise to claims and counterclaims. On such common issues, the company works with the industry to seek policy relief from the government. The company is actively involved in these industry matters. We realized that we cannot let these legacy issues linger on forever. We'll have to -- we will have these matters legally examined and seek resolution of issues, including through dispute resolution committees constituted by the government. This will be a time-bound and cost-effective way of resolving the long outstanding issues that add up as contingent liabilities. Finally, I would like to recall that when we began this turnaround journey of this company in 2015, with INR 36 crores cash balance without raising new capital or borrowing, team HOEC has developed feeds and acquired companies to grow the gross operator production from 750 barrels of oil equivalent per day to 7,500 barrels of equivalent per day and set to double that once B-80 is on production mode. In B-80, our G&G team has been diligently working even during the lockdown on interpreting a large volume of critical new data that we acquired by drilling 2 new wells with 5 existing wells' data. These internal interpretations have now been completed, and the results meet more than our expectations. These are right now being reviewed in London by Gaffney, Cline & Associates, GCA, a globally reputed firm that carries out independent assessment of reserves and resources. We expect this to be completed over the next few weeks and would present it for review by DGH and share the results publicly. Overall, the company is managed by professionals who value integrity more than anything else in life. We have an eminent board to guide the management. We assure you that the company has sufficient cash and revenue streams to meet all its liabilities, present and future. We will continue to focus on our operations, bring B-80 to production while following best practices in our accounting, reporting and communication. I now invite our CFO, Jeeva, to take you through the financials. Thank you.

Thanks, Elango. We report that the company made a revenue of INR 27 crores in the current quarter against INR 35 crores in the previous quarter. In the consolidated account, it is INR 29 crores against INR 40 crores in the previous quarter. This reduction in revenue is mainly due to reduction in the gas price realization from $3.57 per MMBtu to $2.64 in the current quarter. Though there is a little -- the production was almost stabilized, and this is -- the price is an impact for this reduction. This quarter, profit on stand-alone is INR 13 crores against INR 19 crores in the previous quarter. In the consol account, it remains the same level. Total expenses of stand-alone is INR 14 crores, comparing INR 17 crores in the previous quarter. Statutory levies such as royalties ad valorem and some other costs are optimized results in the reduction for this quarter. For this quarter, the total expenses, including depreciation and depletion in the consolidated account, is INR 18 crores comparing INR 30 crores in the previous quarter. Operating cash flow stand-alone for this quarter, including interest income, is INR 18 crores comparing INR 20 crores in the previous quarter. In the consolidated results it remains the same. The company stand-alone cash and cash equivalents of about INR 128 crores as on June 30, 2020. In case of B-80 development, Mobile Offshore Processing Unit is ready to move from yard, and we will be settling all their liabilities there on. Similarly, associated -- floating storage offshore, Prem Pride, is to be drydocked in Sri Lanka, and we will be able to meet their obligations to make the vessel ready to receive the oil in the field. These facilities are resourced through our own subsidiaries with borrowed capital of about INR 85 crores, which levers around 33%. These assets such as MOPU and FSO are mobile assets, and there is a value uptick and -- when it is put to use in the field. This will enable us to operate the B-80 fleet with a marginal cost, which ensures most recovery from the field. We submit our current liability and the consolidated accounts as on June 30 is INR 221 crores and the noncurrent liabilities such as provision for site restoration INR 143 crores. And we still has a site restoration deposit with the State Bank of India for INR 66 crores. Our contingent liabilities as on March 2020, which is widely being discussed, it's mainly on service tax demand on the cost petroleum of INR 59 crores and cash cost from the JV partner is INR 28 crores, which makes a total of INR 87 crores, and the equivalent amount as penalty, which makes a total of INR 174 crores for the period from 2010/'11 to 2014 and '15. We submit this is an industry issue. You are aware that service tax is subsumed with GST, but no GST on this as on date. Department needs a clarification on this issue from the Ministry of Finance, and it is recommended by MoPNG that it is not leviable on cost petroleum on cash call receipts. August 5, 2019, MoPNG sent a letter to Ministry of Finance stating that circular number February 12, 2018, cost petroleum is not a consideration for service, therefore, no service tax should be leviable. It has been taken as a contingent liability and disclosed as demand exist in form, but in substance, it would not just allow as a liability as all inputs, which construe the costs are already subject to service tax, which was duly paid. Hardy arbitration, contingent liability already exists for INR 16 crores. And for ongoing arbitration by Hardy and Aban, yes, we were a -- we are a partner there with 21%, an amount of INR 15 crores is also considered as a contingent liability. Hardy already -- as Elango rightly said, Hardy already challenged it in the court of Malaysia. PY-1 royalty demand was INR 13 crores. As per the PSC, as per the subsequent surplus, it should be on the wallet price, not on the realized price. This issue is hovering around since the commencement of the production in 2009, and our claim for refund of excess paid is INR 15 crores. This issue starts from 2009 and '10. In case of CBOS1, immediately before surveying the block, ONGC carried out a soil survey and made a claim along with G&A cost for INR 12.45 crores, which was disputed, and the matter is before the tribunal with a counterclaim of INR 65 crores. In Arunachal Pradesh, the block called Jairampur, that's called AAO1-2003-2. Geopetrol even after considering the drilling pad could not drill the well as the foundation collapsed being a hilly area. The estimated liability thereon is $4 million and $2.23 million has already been paid. And in the books, we still carry a liability of $1.64 million. The demand in addition to $1.64 million is not tenable, and is also shown in the books as a contingent liability to the tune of INR 12.36 crore. This makes a total contingent liability of INR 244 crores. It is also some news item appeared in Kharsang block, a demand letter was issued on June 4, 2020 for USD 18.6 million as a principal and $6.2 million towards the interest on a disputed related to the cost recovery limit and it is to state that cost recovery limit and enhancement for 85 months government delay and fixing the base year as '92/'93 and not as '95/'96, is a 2-year -- 2-decade old dispute. This was immediately refuted by the operator on June 10, 2020, itself saying that the demand has no basis. Immediately thereafter, NMC was called by the DGH on June 15 and agreed to consider about 5.6 years as delayed by government of India and agreed for the indexation of the cost recovery limit. The computation of the liability is yet to be worked out by DGH and we are awaiting for it. As per the operators estimation for the share of Geopetrol is less than INR 2 crores payable and the dispute through DRP is about INR 8 crores. In case of block RJ-1 was surrendered under the policy with no cost for minimum work program not completed because there was a delay in government clearance for more than 3 years. In RJ-2 block, OIL is the operator and as per the estimated liability created as per the operators for our share is INR 6.7 crores, which has been duly accounted in the books of accounts. We are confident that we'll meet all our obligations with overall growth of E&P assets in HOEC and its subsidiaries in oil field services. This could be met by cash in hand, internal accruals and asset-backed borrowing through its subsidiaries. Thanks, Elango.

Thank you, Jeeva, and we can open up the forum for questions, please.

[Operator Instructions] The first question is from the line of Riddhesh Gandhi from Discovery Capital.

Just a couple of questions. On actually B-80, can you just actually run us through the time lines for -- actually, when we expect to start production [Foreign Language] of actually first oil? And how good a ramp-up schedule would you look at? And how long it would be for us to be at 100% actually the production levels?

Yes. Thank you, Riddhesh. On -- in B-80, as we said earlier, there are 3 modules to the project. The first module is the Mobile Offshore Process Unit, which is completed. And right now undergoing some minor modification in Sharjah, Lamprell yard and will be mobilized once the weather window opens in November. Second module is actual drilling of the wells, which have been completed, tested and varletries have been installed. The third module, which is to be installed, is really related to export system, which is the gas pipeline will have to be connected to the existing ONGC pipeline system and the oil pipeline will be connected to the FSO Prem Pride along with the CALM buoy mooring system. All this works we expect to take about 45 to 60 days and can only be done during a fair weather window, which typically in Western offshore, commences sometime in November and goes on till end of April. So we already are in touch with the major installation contractors who have contracts with ONGC and would be mobilizing the spread to fit a right schedule to complete this installation. So our endeavor would be to do all of them before March 31 of this financial year so that the production can commence from April 1. We do not expect any much ramp-up time to achieve the target production rate of 5,000 barrels of oil and 50 million cubic feet of gas. The ramp-up would be fairly quick but the work on installation is fairly complex and will be done following the right processes.

Mr. Gandhi, you have any more questions?

Yes. And how much is our current cost of actually the extraction for the oil and gas in B-80, incremental power start -- production start?

This is having 2 element of cost. One is development cost. The development cost to us is about $55 million. And out of $55 million, if you look at the volume we are estimating is about, say, assume it should be more or less, we will be waiting for the GCA results. If you assume it is a 10 million barrel, it is in a nonaverage, without giving a time line of money, it is $5 -- $5.5 development. And the operating cost would be around $60. If we produce around, say, 6,000 barrels, it is $10. If you produce 8,000 barrels it will be around $8 to $9. So total cost basis would be on -- without giving time line, it should be around $14 to $15.

Got it. Sir, and the last question which I had was in the lines of this service tax liability and the claim for operators. I mean, effectively, this would be a claim on -- which would be on all operators and for others, for example, Reliance and all this number would be extremely large. So -- and is that accurate in terms of is this a claim on all operators effectively or only us? Or how should we look at it?

It is on most of the operators, but these demands are issued by different regions. And for us, we understand that such a demand has been made on several other players. I don't want to name them all. But ONGC is clearly one of them. And all the major operators have received the demand.

Got it. Got it. And -- but our -- actually the view is that there isn't any like -- there's -- it's an extremely like a low likelihood that we're going to have to pay this?

Yes. That is our view.

The next question is from the line of [ Sushil Agarwal ], an individual investor. As there is no reply from the current participant, we move to the next question from the line of Sunil Bhalotia (sic) [ Sumit Bhalotia ] from MK Ventures.

Yes. First part of the question, you already responded in terms of time line of B-80. Secondly, I wanted to get some more color on the quality of output and quality of crude oil that will be -- that we're expecting from B-80 in terms of whether any processing is needed for loading and AP and sulfur content. One is that. And secondly, on the realization front, the number that you had shared in the last quarter, I think they were based on assumption of oil being at $30, $35. So assuming $45 realization of crude oil, how does the government sharing change? And what could be the possible numbers from B-80?

See, first of all, on the quality of oil, it's sweet waxy crude oil, there is no sulfur content. It's light. We have send the samples for detailed analysis. And once the results come, we will share it with the refineries to determine the pricing on the quality of oil. As far as the cost, as Jeeva explained, we are looking at a netback of about $20 to $25 per barrel in the $40, $45 regime.

The government sharing would be the same?

As sharing with the revenue. Revenue sharing with the government is on a percentage basis, which is if the daily revenue, which we expect average to be in the range of about 23%, 24%, average over is life of the field. It starts with the lower end of 12% and goes to 56%. When the revenue per day is more than $1 million, it is 56%. And the revenue -- gross revenue per day is less than $10,000, it is 12%. So average, you can take about 24%.

Okay. Okay. Sir, 1 more question on the cash numbers, and maybe I missed out or misread the numbers. The cash equivalent that we have as of March end was around INR 170 crore, INR 171 crore. And I think you mentioned that cash equivalent as of June end is around INR 128 crore. Is that right?

Correct. It is on stand-alone accounts. And in consol accounts, it is a little more than -- it is about 1 -- just a minute, I'll just tell the numbers. In consol account, we have got about INR 167 crores -- INR 166 crores we have got.

Consol INR 167 crores. Okay. Okay. So the movement in cash balance on stand-alone from March to June would be how much?

The movement is -- the reduced movement, I can tell you. That's about some -- it's with INR 140 crores, it becomes INR 128 crores. There is about INR 13 crore reduction. And after adjusting the INR 18 crore cash inflow, it's about INR 31 crores as such.

Okay. And this has been used for the expansion?

For the -- about INR 20 crores we spent on the B-80 development.

Okay. In this quarter?

Yes.

The next question is from the line of Varatharajan from Systematix Group.

Look at the expenses for the quarter, other expenses and employee expenses seem to be down quite sharply and as you mentioned there...

Varatha, can you be a little louder? Your voice is breaking, please.

Yes. Is it better now, sir?

Yes, Varatha. Yes.

Yes. The employee expense as well as other expenditure for the quarter seem to be down quite sharply. So any reason why that is so?

So it's not very sharp. INR 17 crore, we have reduced about INR 14 crores. We are trying to optimize all the possible costs during the shutdown period, and that has reduced about INR 3 crores, roughly about INR 1 crore per month.

So should we take this as a run rate from here on?

I think, see, it all gets momentum, then you'll have some travel and other expenses will come. So we can say that INR 17 crore is our -- is the basis. And the 3 months because no movement at all, the offices stand closed and however we are maintaining our fields operations as far as...

Sure. The second part was on the production rate at both North East as well as like PY-1. North East is your claiming it is almost back to normal. Should we take it as sustainable from here on note period to that production?

Yes, Varatha, it is right.

Okay. As far as PY-1 is concerned, that plant offtake issue remains. But you had created a contingency, some other player who could potentially take it. Any update on that, sir?

Varatha, there is a -- in the current situation, there is no other really willing player as such. So we will have to wait for our job to increase production in PY-1 at the end of [Technical Difficulty] in their alternative arrangements. Right now, no.

These guys don't seem to be coming back online anytime soon?

No.

The next question is from the line of [ Sunil Joshi ] from Sapient Wealth Advisors. [Operator Instructions] The next question is from the line of Ashwin Reddy from Samatva Investments.

I have a question on the Dirok gas field. Can you clarify if the scale-up to 55 units, which we had planned, is that linked to the freeing up of the gas pricing?

Yes. What we have done, Ashwin, is we are continuing with the project, but we are focusing on the critical part items like getting the forest clearance and also focusing on laying the pipeline along that route as such. So we have ordered the -- for the pipes and pipes have arrived. So we have commenced the project, but further investment, which is to take it to 55, we will wait for -- by this month end, what kind of policy decisions government makes on the gas pricing side. We -- there are 2 elements to the project. One is laying the pipeline, which we have started now because that is a long lead item. The other part is investing to expand the processing facilities which we have not made the commitment. But we have completed the engineering work. We know the contractor will be the same company, Expro, because it's a modular concept and which we should be able to do that in 9 months. So 2 things we want to watch out for one is a consistency in offtake, which we are seeing now. In fact, as we speak, the volumes have further increased. And then the second part is what is the government finally decides on the pricing front.

Okay. Okay. Understood. And the offtake, which has come back, is it back to the same fertilizer clients, which used to take it before? Or have we found any new clientele? And that's how it's come back to the higher level now?

Yes. Now these are the same consumers like BCPL, fertilizer and power plants. And so there are no new consumer. But the old -- these consumers are taking and partly driven by the fact that you must have heard about the oil blowout in Baghjan field. Therefore, the Oil India is unable to supply the full volume, so that is helping us to supply more as such.

Okay. Understood. Helpful. And finally, sir, in terms of the Dirok field revenue sharing, which has changed from July 1, 2020. Can you explain in detail about the impact on the P&L and the cash flow statement -- on the cash flow from this field based on the new terms from July 1?

This will impact us about -- say about 7% to 8% of the revenue, and gas price impact also would be around some 12% to 13% we estimate. Total, there would be an impact of 20% of the revenue. But that has now been offsetted by the increase in volume. So overall, the top line would be a reduction of about 4 to 5 million -- INR 4 crores, INR 5 crores, and the bottom line would be about INR 2 crores. That's what we expect.

So because this happened from July 1, right? So you're saying as compared to June to July, June to September quarter is what you're saying, right, in terms of the revenue?

Yes.

Next question is from the line of [ Tejas Shah from Unique Stockbroking ].

Yes. On the Dirok field, I think the fleet out to the normally what, 33 MMbtu or 40, where I said, I think, a peak price in last year?

Correct. The full production capacity of the -- along modular plant is about 36 million cubic feet, which is equivalent to 1 million cubic meters per day.

So any -- will it reach to that level? Or you are saying 29 is fixed out?

No, no. 29 average was for the last -- Q1. In the current quarter, we are doing better than that. It has increased further.

To what level is possible?

Almost full capacity we are doing, which is about 35 -- so kind of ranges average between 30 to 33, 34. And some days, it goes up further. And what we have done, just to explain further, we've also opened up the additional pipeline, the 4-inch pipeline that we had. Some of you would remember, in Phase 1, when we commenced production, we used the old well and supplied the gas through a 4-inch existing line to Oil India facility. Once the new plant got commissioned, we have laid a 12-inch pipeline through which the new plant output is going. Whenever we see a demand, which is beyond the 36 million cubic feet on odd days, we also have the ability to open the 4-inch line so that we are able to deliver on a single day up to 40 million cubic feet also. And that happens occasionally. But all that makes up -- and the idea is to ensure that on an average basis, we are maintaining well above 30 million cubic feet per day, which we are able to do in this quarter.

Okay. Another thing, I think B-80, operational, you are saying it will take around 2 months' time to deploy and function everything, correct? Starting window is around November?

The window for weather starts in November. The work involved, first to bring the Mobile Offshore Unit from Sharjah to Mumbai and position it at the designated site near the well. That is the first activity. Then we will have to lay a pipeline, which is what we call a flexible pipeline between the well and the Mobile Offshore Process Unit that is infield -- similar to an infield pipeline. Then between the MOPU to ONGC's existing gas pipeline. That is basically a pipeline. And thirdly, we will deploy a CALM buoy mooring system and bring the vessel, which is in Sri Lanka, which will undergo drydocking over the next 3 or 4 months period and have the mooring system and have that installed. Finally, the oil pipeline will be connected to that system. So there is -- while the scope of the work per se, because we are talking about 5 kilometer of pipeline total, so it's not a large volume in terms of scope, but the spread that is required is very similar. Suppose if you are laying 100-kilometer pipeline in Bombay High, what's the type of vessel you need? You need a similar type of vessel even for this operation. These are very sophisticated vessel, which can lay that price for us. So what we are doing is to mobilize the spread exclusively for this kind of a small work would be very, very expensive. And remember, we are developing a marginal field in Mumbai High, which ONGC thought is not economical to develop. So obviously, we need to kind of do our own set of innovation. So we are in touch with the contractors who are already mobilizing a spread for ONGC work. We will look for a window of opportunity and get our work done. That will be the cost-effective way. That's why I'm unable to specifically state by which month we will actually finish. But the clock stop date is really April because the weather window ends in that. Our endeavor would be to finish by end of March, which is still doable.

Okay. Another thing is last time you had shared [Foreign Language] B-80 is a prepricing market for that. Okay. And you'll be getting some clients from Gujarat, which will build at $4-plus pricing? So any thought on that?

Yes. The -- it is a free market pricing. There are no pricing controls when it comes to B-80 gas. And the gas will flow through the ONGC pipeline system to reach Gujarat market, specifically the Hazira. A couple of interesting developments since our last call. The gas -- Indian Gas exchange, which is similar to the Power Trading exchange platform, has already been launched. And a small volume of trial trade has been done as well as -- and Hazira is a designated delivery point, which effectively means some of the volume you could trade it in the exchange for physical delivery at Hazira. And there, we have seen prices thereon $4 prices we have seen in the exchange. We have not concluded the pricing discussion. What we thought we will look for what signals government is going to send with any gas pricing reform, which we expect by end of this month, hopefully. And based on that, we will conclude arrangements. But we have established, there is enough demand. The demand has been established, confirmed by GSPL as well as by GAIL and some direct consumers also. But we will be most likely partnering with an aggregator like GSPL or GAIL to ensure our offtake is there. As I was telling, we will commit, let's say, 70%, 80% volume under this model and keep about 20%, 25% model volume for try and do the trading where the trend is now a premium price, whatever is a prevailing market price. At the trading counters, it draws premium, but we will take a call as we come closer.

And lastly -- okay. So I will come again on the end.

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

In your opening -- first on the Hardy issue. In your opening remarks, you mentioned -- as well as in your clarification, the total sum of all the contingent and the reported liabilities adds up to INR 600-odd crores as per your Monday's morning clarification. But if we look at the news articles, they are stating INR 722-odd crores. In your opening remark, you mentioned that this is an apple-to-apple comparison. They have also included the claims. We cannot yet -- management has not yet put a word on it, and that is not getting reported. So I'm just trying to reconcile the differential amount of INR 122-odd crores, which the newspaper articles are suggesting. That is first part of the question. And second is on the contingent liabilities, the counterclaims, if you can put up a separate press release, which Mr. Jeeva has already verbatim pointed out in his opening remarks. If you can put a separate press release citing that these are the claims on the company and these are the counterclaims on the company just to get a more clearer clarity on what company stand that is second part of it?

I'll answer the second part and ask Jeeva to answer the first part. In terms of going public on counterclaims on individual court cases or dispute resolution arbitration will not be a correct thing to do. But on the overall, your first number, Jeeva will start giving.

We have given the full details in the annual report, which I think might have been circulated. You can refer to that. No issues on that. We have stated about each claim, what is the nature of the claim, what is the claim made, what is the counterclaim made by us. It is all there. Now if you wanted to have the reconciliation, the total we have current liabilities, there is an undisputed price. The current liability is INR 214 crores and the noncurrent liability is INR 142 crores. And the INR 244 crores is a contingent liability as on March 31, 2020. The difference of INR 722 crores, if you look at, we have already captured about INR 600 crores. INR 122 crore, I will explain what are those amounts. Royalty demand is -- the royalty is based on the wallet value. But it has been government is demanded on the gross price of the sales going on from 2009 and '10 since the field has been put on production. Now if we made actually, there are an excess payment there on -- we made a counterclaim of around INR 15 crore thereon to it. Now the liability there are, we put it into the books of account as a contingent liability, expected liability is INR 13 crores. For that, this newspaper item which says actually INR 41 crores. There is a INR 22 crores sits there into it, okay? And similarly, when you look at our contingent liability on account of the service tax, we take if the demand notice comes to the company, we don't pass on to the same thing because it is not a -- in substance, there is not a liability thereon. So we want to head our dispute with the department. And we don't pass on that to the -- our JV partners, and take this is only my liability. That is to be a liability, right? If that is the case, my INR 173 crore liability is only INR 123 crores. But in the similar case, Hardy claims, there is about INR 12 crore liability thereon, the service tax thereon on 2010 and '11 when they shut the field down. So that is the liability of -- same liability extent of INR 12 crore there, INR 11.9 crore to be exactly. Then there is a block called RJ-1, which we have 25% participating interest. The block has 4 parties. One Jindal, they walked away from the block from the beginning. Then we carried out the seismic. And after that, there was no clearance from defense ministry for a period of 3 years. By using the policy regime of the government of India, where there is a more than 3 years' delay without submitting any work program, you can surrender the block. Using that policy, we have surrendered the block. That is claiming a INR 16 crore liability thereon. Then RJ-2 block, which is operated by the Oil India, and they have completed 2 wells drilling. After that, they start -- this is not contingent to drill any more wells there in, and they've decided to surrender the block. They've surrendered the block. In that, our participating interest is only 20%. The estimated liability thereon is about INR 6 crore for us -- INR 6.7 crores for us, estimated by the operator. We provided it in the books of accounts. There is no further liability exists thereon. So that is another INR 16 crores. Then come to a block called Mizoram. Mizoram is a block, wherein 4 parties were there, and one of the party has submitted some wrong statements. And the PSC itself is nonlist. There is no claim there. No claim is entertainable by us because the PSC itself has not commenced. So that in the statement they are saying, that it's a INR 10 crore liability in their own estimation, right? Then we are talking about a block in Kharsang. This is a dispute goes back from 1995/'96. The PSC was signed in 1992/'93 with the cost recovery limit stated in that. But when the PSC was signed in '95/'96, that should be the starting point. But when this was submitted, it was '92/'93, right? In that case, it's a government delay of about 86 months. That is virtually about 7 years delay. And the 7 years delay, the cost escalation has to be granted by the ministry. If the cost calculation is granted, then there is no issue at all. And this issue has come up suddenly as a consideration of some $24 million is payable by the consortium, wherein we have got only 25%, and then it has come up here in 4th of June. Immediately, it has been refuted by the operator on June 10 stating that this liability is not tenable. There is no basis for it, and you have never accounted the increase in cost escalations as for the PSC. And you have not determined the effective date as '92/'93. This hovering many issues have been raised on the letter on 10th of June. Then immediately thereafter on 15th of June, a management committee meeting was called. In the management committee, as government has considered, there is an accepted fact by the DGH, there is about 5.6 years delay is admissible. Therefore, the escalation benefit is to be given. And now we rework out the liability and then pass on to the companies as such. In the estimation of the operator, this liability is about less than INR 2 crores towards immediately payable. And in the liability, which will be referred to the dispute is about INR 7 crore to INR 8 crore. So there is no basis exist for INR 55 crores. So the total claim of INR 138 crores has no relevance whatsoever.

Right. Okay. Sure. And lastly, on your annual report, if I look at your reserve or resource data, there is hardly any movement -- noticeable movement in that number from '19 to '20. Does this mean that we have not yet added the B-80 resources in our reserve data? Or is it included?

The B-80 is a probable reserve data. It is included there.

It's in the -- okay.

And what we are doing as such, as soon as the GCA report comes, we've made it public to everyone to know what is the volume of probable -- proven reserves, probable reserves and possible reserves there are, and the lead there on and what is the quantum there on. We will make it open to the entire shareholders, and it will be published in the S-8 itself.

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

Sir, some follow-up on B-80. What is the total CapEx -- fee level CapEx you have done till now? And what is the balance?

See, we have -- this is essentially a block where the 2-well development and this 2-well development. And then it will be connected through the gas export line. MOPU is also through our subsidiary a contracted facility. And SBM and the floating storage offshore also a contracted facility through our subsidiary. If you look at the B-80 stand-alone development, we have built the 2 wells. The cost of these 2 wells is somewhere around less than $40 million. Now we have to put the gas export line. And there are 2 flow lines, 2 umbilicals and 1 export line to this one -- to floating storage offshore to SBM. The total estimated cost to us should be in the order of say, $10 million to $12 million. We are in the process of getting the quotes. It should be around $10 million to $12 million. Total project by any means, it is not exceeding $53 million for the B-80 development.

$53 million. Okay. And how much of it has been incurred, sir, already?

We have incurred probably exactly about $39 million to $40 million. And that is -- our share is only $20 million because other company has 50% stake. They have about $20 million.

Fair enough. So close to -- INR 150 crores CWIP has come in our balance sheet?

Yes. I'll tell you the exact number, investment in properties and there is a stand-alone balance sheet number. Our capital work in progress is about INR 156 crores, INR 156.97 crores. Out of that INR 145 crores goes for the B-80.

INR 145 crores is for B-80. And after incurring this CapEx, we have got net CapEx in the balance sheet. Is that correct? How much is the net cash level?

The net cash level is, I told you no, that is about INR 129 crores existing as at the moment on June. And we have certain internal accruals, which comes in total about INR 5 crores to INR 6 crores per month, which comes on it. So we are slowly building up this actually to meet our -- some of the suppliers, which is pending for payment, which we have to make the payment. And then the additional, I told you about $10 million to $12 million, $6 million, our share comes around INR 35 crores. By -- before March, we should spend that money.

So all of it is done through internal accruals, and then also we have been able to maintain this deleverage status of balance sheet.

And what we are delevering is only with reference to the facilities, which we are using through our subsidiary. For example, FSO, we are taking a loan. That would be deployed for B-80 itself. That is a full year an asset back. Our leverage is only 33% to 40%, max.

Okay. Sir, another -- you've been talking about this changes in gas pricing and some of the forms taking place there. What could be the -- what is anticipated? And what could be the implication for HOEC, particularly for Dirok and B-80?

As far as B-80 is concerned, we have a complete marketing and pricing freedom. So clearly, it is an open market basis. Dirok. Dirok we are selling the gas-based on the 6 monthly pricing announced by the government. Every 6 months, the government announces the pricing based on international cocktail of gas prices and Henry Hub and nationally balancing the market in U.K., Russia, Japanese. It's a cocktail formula as such. So the demand from the industry has been that provide us complete marketing and gas pricing freedom, which the government has given to all the fields, which are to be developed after the field development plan approved effective April 1, 2019. In other words, any FDP that was approved after April 1, 2019 is eligible for free marketing and pricing rights. However, some of the old blocks, which were developed in the previous regime, do not enjoy that freedom. And particularly in North East, we are the only private operator supplying and selling gas. You know North East is a very limited market, where the major players are ONGC and Oil India, and the major customers are essentially central government customers. If the new policy of the government opens up marketing and pricing freedom for ONGC and Oil India fields as well, then the whole market is opened up, and we expect market determined prices. You would recall, at one point in time throughout India, the market price -- the uniform price for all NELP and pre-NELP gas was $4.2 per MMBtu. So I broadly take that, the market in India has accepted a price of about $4 throughout. And therefore, if it opens up, you have to give a discount for the current economic situation. But for that in -- the general trend should be the Indian market should be -- in my view, should be able to comfortably absorb a $4 per MMBtu gas price.

Okay. So, for Dirok definitely, it will have a positive impact. But what about for B-80? Can it result with this free market pricing? Can it translate into lower-than-anticipated realization or will it...

No. It will -- it already enjoys free market pricing. And because the B-80s will be sold in the Gujarat gas market, which is the most premium paying market in the country, where the majority of the imported LNG is being consumed in the Gujarat market and some of the long-term impact imported LNG prices are still high because they are committed on a fixed basis as such. So overall, we expect Gujarat prices to be on any day better than the rest of India prices.

[Operator Instructions] The next question is from the line of Yash Mandawewala from Mandawewala Enterprises.

So my question is actually on the oilfield services business that we're entering into. So what is the arrangement for the pricing at which we will lease the MOPU and the floating storage unit to the B-80 block?

So this being related for the transaction, we would like to go to the market and take the price. And we don't want to charge even a single penny more than on B-80 because we have got a partner therein. So it would be flat and...