Hindustan Oil Exploration Company Limited (500186) Earnings Call Transcript

Ladies and gentlemen, good day, and welcome to the Hindustan Oil Exploration Company Limited Q3 FY '20 Earning Conference Call. [Operator Instructions] I would now like to hand the conference over to Mr. P. Elango, Managing Director of Hindustan Oil Exploration Company Limited. Thank you, and over to you, sir.

Thank you. Good morning, everyone, and a warm welcome to our call for Q3 FY '20. I'm joined by our CFO, Mr. Jeevanandam; and Stellar IR Advisors, our Investor Relations advisors. A short while ago, we uploaded the investor presentation on our website and circulated. In Q3, gas offtake in Assam was adversely affected due to local strike and unrest. All major gas consumers had to reduce or stop receiving gas, forcing partial and full shutdown of our plant as well for few days. While the local situation is improving gradually, a major safety incident in one of the plants of Brahmaputra Valley Fertilizer Corporation, BVFCL, forced Oil India, who is our buyer, to reduce the offtake from Dirok. Due to these factors, average gas offtake from Dirok during Q3 FY '20 was 29.5 MMSCFD, while we had the production capacity to deliver 36 MMSCFD. We view this as purely a short-term issue as all our major consumers are public sector units. The Northeast gas sector development, got a big boost with over INR 5,000 crore of viability gap funding for the Northeast gas pipeline to connect to the national gas grid. In addition, Oil India has also planned to lay a 60-kilometer pipeline from Kumchai near Kharsang to connect it with Duliajan. We're also progressing with our Margarita gas pipeline to bring Dirok Gas to Duliajan, which is the marketing hub for Northeast gas. Overall, we firmly believe in our strategic focus on Northeast, where we hold 5 blocks with potential resources. I can assure you that we will carefully monitor the gas infrastructure development, gas offtake consistency and allocate capital to our portfolio of blocks prudently. Similarly at PY-1, while the Tamil Nadu Power Generation Corporation's plan came back online towards the far end of Q3, we are yet to get assurance on consistent offtake. To move away from the dependence on power sector, we have executed a conditional MOU with a private end consumer to sell 1.2 MMSCFD of gas on fall back basis at a premium over our current gas price. This is subject to the consumer executing a gas transportation agreement with GAIL. The idea is to step up our direct marketing engagement with the end consumers to discover market prices in the Cauvery region. On B-80, the primary focus for HOEC's next phase of growth, we are happy to inform that we have drilled the first well to the target depth of 2,730 meters safely and successfully. We expect to conduct the well test for flow in the next couple of days. We will update the results through a release as soon as we have them. In parallel, the conversion of jack-up rig to a mobile offshore processing unit, MOPU, is now nearing completion on schedule at Lamprell shipyard. The MOPU will be ready to sail out of Dubai in March 20, on target. It will be available on time for completion of second well for [indiscernible]. On the export system, we have now sourced a floating storage and offshore unit, FSO unit, with large oil storage capacity. This FSO will require dry docking and a CALM buoy mooring system cleared to deployment in B-80. This system would offer more flexibility to market the produced crude oil to any refinery along the Indian coast, securing market-determining premium prices. Natural gas from B-80 will be taken to the Gujarat market through ONGC's Hazira plant. We will construct the gas pipeline from B-80 MOPU to ONGC's gas pipeline post monsoon 2020. We are continuing the discussions with potential gas consumers in Gujarat gas market. As gas to be produced from B-80 enjoys full gas marketing and pricing freedom, we expect to realize a premium gas price. Jeeva will explain the B-80 development costs and funding arrangements made to maximize and retain the value of B-80 within the group companies of HOEC. In another major development, the production-sharing contracts for PY-1, PY-3, Kharsang and Asjol field have been extended for another 10 years. This allows for redevelopment of these fields over the long term. While the execution of PSC for R2 area in Cambay has been further delayed, we were the highest bidder for the 4 Pre-NELP marginal onshore fields in Gujarat auctioned by GSPC. As required under the PSC, GSPC has offered the participating interest in the 4 blocks to JV partners, GNRL, for first right of refusal. We are in discussion with GNRL to foment this joint operatorship for 50% participating interest in each of the 4 blocks. Our immediate focus will be to complete the testing of the first well and move the rig safe to drill the second well in B-80 safely and successfully. In parallel, we will mobilize MOPU in time for hookup of both wells, complete the dry dock of FSO for class and will endeavor to install the oil export facilities. If weather permits, our endeavor will still be to commission all the facilities other than the gas export system, pre-monsoon. That is by mid-May 2020. If not, installation of export system and commissioning can be done only post-monsoon to commence first production by December 2020. With this, I request Jeeva to take you all through the financials.

Thanks, Elango. We report that the company made a revenue of INR 51 crores in the current quarter against INR 62 crores in the previous quarter in the stand-alone accounts. In the consolidated account, it is INR 55 crores against INR 67 crores in the previous quarter. This reduction in revenue is due to poor offtakes by oil in Dirok field and the reduction in gas price. Profit before tax and exceptional is INR 31 crores comparing INR 36 crores in the previous quarter. Profit after tax, including exceptional item, is INR 52 crores against INR 39 crores in the previous quarter. In the consol accounts, the profit after tax for this quarter is INR 53 crores against INR 40 crores in the previous quarter. Other income is increased from INR 5 to INR 6 crores in this quarter, which is mainly from the short-term investment of cash surplus. The exceptional income of INR 22 crores relates to write-back of liability towards [indiscernible] India Limited for the disputed invoices related to the period of 2010 to '14. Operating costs of producing assets stand-alone is INR 6.5 crores comparing INR 6.7 crores in the previous quarter. Operating costs of the company is not linear and is not varying much with the increase and decrease in production. Royalty and process for this quarter is INR 5 crores against INR 7 crores in the previous quarter on a stand-alone basis. Depreciation and depletion INR 6.29 crores comparing INR 6.94 crores in the previous quarter. Royalty, and depreciation and depletion is more linked towards the actual production. Total expenses for this quarter, including depreciation and depletion in the stand-alone account is INR 21 crores comparing INR 27 crores in the previous quarter. In the consolidated accounts, the total expense is INR 24 crores comparing INR 32 crores in the previous quarter. The Taxation Laws Amendment Ordinance 2019 provides substantial relief to HOEC on MAT. Concerning the carryover depreciation and loss, the company may not be subject to any corporate tax till the taxable income exceeds -- substantial amount exceeds above INR 1,000 crores. Operating cash flow stand-alone for this 9-month period is INR 107 crores, comparing INR 124 crores in the previous quarter. Previous period in the consolidated results, the operating cash flow stands at INR 115 crores, comparing INR 135 crores in the previous year. Revenue from Kharsang is INR 4.38 crores and the net cash from operations is INR 1.85 crores. The company stand-alone has a gross working capital of about INR 349 crores with cash and cash equivalent of about INR 149 crores as on 31st December 2019. In the consolidated accounts, the gross working capital is INR 338 crores and cash-on-cash equivalent is INR 176 crores around 30th -- 31st December 2019. In case of B-80 development, support services are record for processing the oil, such as mobile offshore production unit and the storage and offloading through a single-point mooring system when the floating shortage offshore is required. These facilities are normally procured through service companies with long-term contracts. Considering the reasonability of returns, these facilities are resourced through our own subsidiaries with a borrower capital of about INR 80 crores, which levers the subsidiaries around 33%. It facilitates our subsidiaries to embark on oil field services, which would unlock about 20% post-tax return and provide leverage in PAT operations. The initial capital outlay for this is INR 230 crores with a debt capital of INR 80 crores and INR 150 crores through equity. Overall growth of E&P assets in HOEC and its subsidiaries in oil field services would be handled by -- would be funded by internal accruals and asset backed borrowing through subsidiaries. Thanks, Elango.

Thank you. We can now open the floor for questions, please.

[Operator Instructions] We take the first question from the line of Sudhir Bheda from Right Hand Consultancy.

Sir, I just wanted to know the investor presence for the next year. You have given the net production, 7,500 of -- which is rising from 4,500 in current year BOPD. So this entirely will come from B-80? That is the question number one. Whatever increase you have mentioned in the next year will come from B-80? And the next question is whether those problem in the clients which you faced in Q3, it gets forward or you are looking for alternate plant for the oil field. And what kind of level you are contemplating for the next year from Dirok, whether it will operate in a full capacity.

Okay. The next year revenue would -- increase would really come from B-80, depending on when we start the first production. But for the -- any increase in net revenue would essentially come from B-80. On Dirok, as we said, we see this as only a short-term reduction in offtake. We expect to see the customer coming back to consuming the full volume over the next quarter or so. We expect the change to occur maybe from March, April onwards.

So that means, sir, entire revenue uptick will happen only from B-80 and there won't be any increase in the production from the existing field for the next year, isn't it?

For the next financial year, there will be no increase from production from the existing field. All incremental would come only from B-80.

[Operator Instructions] Next question is from the line of Raj Mahadevan, individual investor.

Mr. Elango and Mr. Jeeva, question regarding the top line. When I look at top line of INR 55 crores at a consol level for Q3 versus INR 77 crores for the same quarter previous year, can you explain the INR 22 crore negative differential in top line and break it up into sort of price impact and volume impact of this PY-1 plus Dirok volumes?

See, that -- if you could look at the numbers, gas price has been reduced from $4 to $3.5 in the Assam. So the volume produced is about 1.2 Bcf of gas, has reduced 0.9 Bcf. So in effect, it has reduced the total revenue by about INR 22 crores -- sorry, 22% comparing the previous quarter. Then come to PY-1. PY-1, if you compare, there is a revenue of INR 35 crores in the previous year. And that has been just come down to just INR 10 crores. So PY-1 has substantially contributed much less comparing to anything else. So these 2 reductions, PY-1, the price remains constant, but the revenue has an impact. That's the reason it has reduced overall about INR 22 crores in the third quarter ending.

Sorry. So just to summarize across our field, how much is coming from price and how much is coming from volume?

See, the price volume reduction is more comparing the price reduction. Exactly, you wanted me to quantify, it's about 1 Bcf, 0.3 Bcf, 0.3 Bcf x 50 is about -- so you can say roughly around 60% is the volume reduction and 40% is from the price reduction.

Right, okay. And price reduction, obviously, is not entirely in our hands. And it's a function of government pricing and oil prices. But 50% impact, which is volume, we are saying should start to normalize in Q4 and certainly going into Q1 of the new financial year?

But that also, again, you have to factor in what the price the government was going to give on the...

That's on a like-for-like price basis.

Second one is employee benefits expense line, Mr. Jeeva, there's a lot of volatility around this expense line over the last 3 quarters. I'm just trying to get a sense and also our 9-month employee cost base is up almost 60% over 9 months of the previous year. Just trying to get a sense of what's happening there.

Yes, can I explain to you, Ram? If you look at the 30th September, there is -- an one-time bonus was given for about INR 3 crores to the executives. That is the substantial jump. But for that, you look at that cost is varying from INR 75 lakhs to INR 80 lakhs, which is the amount we charge to the -- it depends on how much is amount we can charge to the joint venture partners. If the number of blocks are getting increased, then the cost to the company on employee benefit expenses stand reduced because substantial time rating will take place. So otherwise, if you look at the 9 months period ended, on December 2018, it was -- it's about INR 3 crores. December 2019 is about of INR 4.3 crores. If you knock out that, INR 3 crores, it is INR 1.63 crores. In this INR 1.63 crores versus INR 2.93 crores, there is INR 1.3 crore reduction, this reduction is mainly charging of the expenditure to various blocks. So effective utilization of that management time and other things, rather than a limited allocation could be made with the number of blocks being less.

So if I understand you correctly, you said, this was a onetime bonus of INR 3 crores, so it's not...

That's right. [indiscernible]

It is absolutely one-time?

Yes, absolutely one-time.

Okay. So our actual employee costs on an annual basis subject to plus or minus of charging to JV partner is actually under sort of INR 2 crores.

It's around -- see roughly around total -- would be around maximum INR 3 crores, not more than that. It is at the similar level of the previous year, even with an increase to the employees cost, if any.

My last question is, and then I'll get back in the queue, is regarding depreciation and amortization. They are also seeing a very interesting trend where the D&A is coming down meaningfully over the last 3 quarters as shown in your financials, from INR 12 crores to INR 8 crores to INR 7.6 crores. So just trying to understand what's happening there. And what is the likely steady state D&A not accounting for obviously any major capacity expansion, such as B-80 which will come online and, obviously, push D&A up.

Now if you look at the main reason for the DD&A, what is the volume of resources -- sorry, resource we are carrying in the books? Resource we carry in the books were: Assam is about 220 Bcf of gas and a bit about oil. So accordingly, the rate of production -- I mean, unit rate of depletion would get changed year by year. Every year, we will recost at the year-end based on the reserve report generated by the third parties and in-house reserve reports. Based on the reserve reports, we arrive the unit of depletion rate. In the unit of depletion rate, Assam is less as well as PY-1 is less. PY-1, if you remember that we have charged off most of the assets. We have very small only, virtually about the abandonment provision only in the books of accounts. And the investment we made in the last year, these are the 2 things are there, but for that, no other investment is there. So though we have incurred a total expenditure of about more than $350 million in the block. So considering that, the depletion -- the unit of production rate will come down. If we drill a well, as such, that has increased the reserve base of the company. Then that year that unit rate of production will come down. That's why we expect the depletion rate is not a constant if we are continuously working on the block.

Right, okay, okay. So that is going to be a little complex to predict.

I think on our next presentation, we will give you how we get the unit of production rate for each year.

Okay. And just last question regarding you mentioned that you signed an alternative contract for PY-1 and you said Dirok should normalize for Q -- starting Q1 onwards. So for Q4, are we expecting any sort of normalization between Dirok and PY-1?

I don't think so because we would be at the same revenue base, actually, of this quarter.

Right, this is for Q4?

Yes, where we are already a month over on that. So I don't...

We take the next question from the line of Sunil Jain from Nirmal Bang.

Yes. Congratulations for good development on the B-80. Sir, my questions relate to B-80 only. If I take this oilfield development, how long this can continue with the current 2 wells?

So overall, we are looking at a field life of about 5 to 7 years. This would involve drilling additional wells in the future depending on the results of these 2 wells.

Okay. And thereafter, it will get completed in that period or can it still continue with more drilling?

It really depends on the -- how much resource you are able to establish. On that basis only further developments will take place.

Okay. But what is the probability? Means is there any probability of further this thing or this is worth...

So this is a marginal field, and what we expect is 5 to 7 years. So basically, they are going with all facilities, keeping in mind the 7-year period.

Okay. And second thing about -- Jeeva sir has said about some management with the subsidiary. Can you explain a bit more? I was not able to get it properly.

See there are -- virtually, there are 3 facilities are required to process, store and offload. And this is normally being outsourced to a service companies. The service companies typically charge around $60,000 to $70,000 a day. Now we have a subsidiary company sitting with us called the Hindage Oilfield Services. And when we looked at the economics, it is thought prudent to use this subsidiary and resources within the company rather than outsource to a contractor. And now this MOPU is the one that is a jack-up unit. It is a mobile unit, sailable unit. And it is -- it can be used anywhere else also, not necessarily at the B-80. We thought it is prudent to resource it. So the investment goes around say, $15 million. $15 million means roughly around say, INR 100 crores, INR 105 crores. Similarly, we have to look for an SBM, which is also a removable structure. And then we're looking for a floating storage offshore. This floating storage offshore is a vessel, it is an Aframax tanker. This is having -- it can fly as a vessel carrying oil or chemicals there onto it. It's basically an oil tanker and it is having built in with oil facility. This is not necessarily can be deployed only at B-80, it can be deployed elsewhere also. The total expenditure of the FSO, SBM and MOPU put together, it costs us around some INR 230 crores. So we thought this INR 230 crores, we can lever to an asset-backed financing, which is about some INR 80 crores. INR 150 crore we put on in-house funding there on to it. It gives us a post-tax return in order of say, 20%. So this 20% return on this current period is good for us, and it's providing a captive usage of this facility for 5 to 7 years. And that would facilitate these companies to embark on an oil field services in the longer-term period. Because there is no substitute company available in India, so these companies can get on to its own lake and providing oil field services after 7 years -- after 5 years. It's depending on how the field performs in the B-80. And second thing, this is being a resource to -- you got an ability to work on a marginal cost basis for the B-80 field, that will enhance the B-80 field life also. I hope this clarifies.

We take the next question from the line of Sreemant Dudhoria from Unifi Capital.

Gentlemen, A couple of questions. Firstly, on the PY-1 field, while you had shared about signing MOU with a private consumer...

Sir, this is the operator. I'm so sorry to interrupt, but your audio is not very audible. Requesting you to please repeat your question.

Can you hear me now?

Yes.

Okay. So the first one is on the PY-1 field. While you had mentioned the -- about signing MOU with a private consumer, with the premium pricing. So just a clarification, this premium pricing is based on the existing fixed price of PY-1 that we have currently or is it on the prevailing government price?

No. The premium would be over and above the existing gas price that we have with GAIL for PY-1.

Okay, okay. Sure. And you also highlighted that the Tamil Nadu power generation unit has actually come onstream. So -- but then you've also said that the production is not fully ramped up. So just wanted to understand a little more of where are the hiccups here? And when could we expect the production ramping up to the full potential in PY-1?

Yes. In PY-1, we are producing some -- essentially 2 wells. The 1 well is the one we drilled recently through a side track. So what has happened? Due to the prolonged shutdown of this power plant, we had to shut down the well. Frequent closing and opening of wells really would affect the reservoir performance in the long run. Therefore, we had asked the consumer, which is represented by GAIL to us, because our contract is only with GAIL, that they must make a firm commitment to lift a certain volume of gas on a consistent basis. That is the one. And it cannot be used as a peak demand producer, because this is being an offshore gas, opening up well frequently or closing it would effect. So that's the -- that is an issue. Still, the plans are not fully come to on full stream as such. That is the issue they're facing. On top of it, you have this CPCL Narimanam refinery, which was one of the major consumers of GAIL, has also been -- has shut down for an expansion plan, and that's a long-term shutdown for almost a couple of years it will take for it to resume. So overall, we thought we should get back to the market directly and start engaging with the customer. We've made a beginning for a small volume with this particular customer. For even that to happen, the customer has to sign a gas transportation agreement with GAIL. But we are discovering the prices, and there is -- we see a momentum in that. So we are -- we would do -- perhaps sign similar contracts with few other customers as long as it's a premium over the current price. And parallelly, we'll insist GAIL to take the gas on a more consistent basis. I think it will take a quarter or more before we see normal offtakes on PY-1.

Sure. So for the field to not get impacted with frequent...

I'm so sorry to interrupt again, requesting you to please speak a bit louder, sir.

Can you hear me now?

Yes, please.

Yes, please.

Okay. So for the PY-1 field, we know to operate at an efficient level without at -- so that the reserves don't go down, what should be the run rate one should expect? Like you highlighted that it should actually produce so much of gas, what should that number be?

Post our last drilling campaign, we're able to produce about 10 million cubic feet of gas per day. So anything above 5 should be comfortable for us, but anything below 5 is a challenge.

Next question is from the line of Varatharajan from Systematix Shares.

All my questions have been answered.

We take the next question from the line of [ Sushil Aggarwal from NPCC. ]

I'm very happy with the progress on B-80 field. I have a few questions on -- firstly, on the delay in signing of PSC agreement for R2 and Kherem field. Can you tell us something on this, sir?

Yes. On the R2, all the paperwork is completed. There was a demand for payment of bank guarantee before execution of the production sharing contract whereas the normal practice would be that you sign a PSC and then submit the bank guarantee for the work program within a month or so. So that's a large hitch where we didn't want to just give a bank guarantee before the government actually execute the PSC. So we have represent -- we have made a representation to Petroleum Ministry and DGH that the normal practice of signing PSC first and then demanding bank guarantee should be resorted as such. We hope to get that issue resolved. There's no other issue there. As far as Kherem is concerned, the new rule requires that the petroleum mining lease that is to be signed by the state government of Arunachal Pradesh can be done only after we get the forest clearance. Earlier, the practice was you will get the PEL, that is the petroleum exploration license; or PML, petroleum mining lease, signed first. Then we go for -- based on your development plan, we'll go for the forest clearances. Now they've changed the rule to get that forest clearance first before they can execute the PML. The forest clearance process, we have completed now. I think last month, we got the forest clearance for Kherem. We expect the PML for Kherem also to be executed soon. For Kharsang, which also comes under Arunachal Pradesh, we recently executed the PML.

Yes. Okay. Good progress on this. This other question is about PY-3. Now inventories has taken the share of [ RD ], are there plans to expedite to start the production?

Right now, I think they're resolving the issues with the -- outstanding issues with some of the vendors which was pending. After they do that, they will come back with the proposals.

So it means there is still time, maybe 3 to 6 months to start the production or more?

Can be more.

It would be more, okay.

They have to get the regulatory clearances also. That is half processed here.

Okay. Because this was a very good field, when there was a good production and quite a bit of time has passed already, 8, 9 years. Sir, last question about -- I mean, I have a request for some important developments like deployment of rig or some -- these type of things? At least we can get some news update. And I wrote a mail also in this regard, that for important items or important news updates, if we can get updates in between because we are getting updates in the investor presentation. But in between, also, if some events are happening, it gives a good feedback to the market also, and so I have a request for that.

Okay. Thank you.

Next question is from the line of Abdul Karim from HDFC.

Coming to the plan for the 18 wells in the Phase-1, so what are the developments that have happened so far?

You mean in related to Kharsang, isn't it?

Yes, yes, relating to Kharsang, yes.

Okay, Abdul, what -- one of the major issue, there were 2 outstanding issues in -- related to the Kharsang's next phase of drilling. The first one was related to forest clearance, which had some legacy issues because this field was -- initial wells were drilled by Oil India even before the Forest Act was enacted. So there were lot of legacy issues around the forest clearance part, which after we acquired Geopetrol, we've been working with the operator closely and managed to secure now all the clearances including paying some penalties for the legacy issues. That has been done. The second part was, as it's said earlier, the petroleum mining lease was to be executed for the future period as well, only after the forest clearance is secure. Only last month, the Chief Minister of Arunachal Pradesh had, in a signing ceremony, had executed the petroleum mining lease also. So both the petroleum mining lease as well as the forest clearance have been now resolved. The budget for the next financial year is undergoing the JV approval process. And then the other outstanding issues related to the JEKPL IBC process, where the final approval has been obtained, and then -- once the all the -- now that all clearances have been obtained, so we'll be looking at commencing the drilling program in consultation with the partners.

Okay, and second question coming from the PY-3, see there are ONGC, Hardy Oil and the Tata Petrodyne Limited and also the partner of this project. So may I know that Tata Petrodyne Limited -- what the Tata Petrodyne Limited playing the key role on this project?

No, Tata -- the operator of the field is Hardy Oil. As you know, in a joint venture, key role rests with the operator. He acts on behalf of all the parties. So in this case, Hardy Oil was the operator. And then the field got shut down about 7, 8 years back. Now the Hardy Oil has been acquired by another Indian company. The initial first step was for them to be under the new management, approved as the operator, which the government has done. The second step was to get the production sharing contract period to be extended. All of us unanimously made a request to the government, that has been also approved. Now for the operator to resolve all the outstanding issues, secure all the regulatory approvals including environment clearance and then come with a plan to recommence the production.

We take the next question from the line of Riddhesh Gandhi from Discovery Capital.

Just have a couple of questions. One is, as a steady state after these near-term disruptions end, could you give us an indication of revenue and PBT expectations out of Assam and PY-1?

Yes. One second. So we have given you the projection up to 31st December. The next quarter would be similar to this quarter. And we cannot speak at the moment what would be the total revenue level.