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Edited Transcript of NOG.L earnings conference call or presentation 19-Nov-19 2:00pm GMT

Nine Months 2019 Nostrum Oil & Gas PLC Earnings Call

Amsterdam Dec 11, 2019 (Thomson StreetEvents) -- Edited Transcript of Nostrum Oil & Gas PLC earnings conference call or presentation Tuesday, November 19, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Kai-Uwe Kessel

Nostrum Oil & Gas PLC - CEO & Executive Director

* Thomas Richardson

Nostrum Oil & Gas PLC - CFO & Director

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Conference Call Participants

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* Anton Rozanov;Argentem Creek Partners;Analyst

* Colin Saville Smith

Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst

* Janna Anikina

* Konstantin Chinarov

Aptior Capital - Credit Product Analyst

* Matias Castagnino

BCP Securities, LLC, Research Division - Research Analyst

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Presentation

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Operator [1]

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Ladies and gentlemen, thank you for standing by, and welcome to the 9 months 2019 financial results. (Operator Instructions) I must advise you that this conference is being recorded today, Tuesday, the 19th of November 2019.

I would now like to turn the conference over to your speaker today, Tom Richardson. Please go ahead.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [2]

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Hi. Good afternoon, everybody, and welcome to Nostrum's 9 Months 2019 Financial Results Presentation. It's Tom Richardson, CFO; and Kai-Uwe Kessel, CEO. The usual format will be applied. So I'd ask everybody to turn to the presentation, which has been uploaded onto the Nostrum website and to turn to Page 2 of the presentation, which goes over the highlights of the first 9 months 2019 financial results.

As everybody will have seen this morning, we announced revenue of $250 million and EBITDA of $158 million with our closing cash balance at $91.3 million, with a net debt of just over $1 billion. This, I believe, was broadly in line with expectations, given that we have already provided forecasted revenue figures and production and sales volume figures as well as the closing cash figure. So these numbers were in line with all of the guidance that we had previously given at the beginning of the month.

One point to note is that the closing cash of $91.3 million is clearly below our target for the year-end of $100 million. However, this is as a result of the fact that we pay our coupons, which is roughly $43 million in Q1 and $43 million in Q3. So therefore, during both Q2 and Q4, we're typically accumulating cash, where we don't have to pay a coupon.

So we would anticipate over the course of Q4, being able to build on that $91.3 million to ensure that we can end the year with over $100 million of cash on our balance sheet, which was our target at the beginning of the year, and I will come to that more when we get to the liquidity bridge slide.

From an operational perspective, we had an average sales volumes of 27,515 barrels of oil equivalent per day. This was clearly below the expectations set at the beginning of the year as we had to revise down guidance at the operational update for the 9 months of the year by 1,000 BOEs per day for sales volumes. A lot of analysts have pointed out in research notes that in order to hit our guidance for the full year, the revised guidance of $27,000 that we therefore need to have an improved Q4 on Q3 in terms of sales volumes.

I point to the fact that from an inventory perspective and when we are selling our products, this is not always smooth quarter-on-quarter. So while sales volumes have declined in Q3 disproportionately to what people had expected, and we have noted that we have seen higher-than-expected decline levels in our wells at field site, I would still say that this does not mean or people should not anticipate that we are bringing on new wells in Q4. We do not expect to do this.

The average for the year is based on the existing wells that we have on production, the factor of less downtime from the existing wells due to the fact that GTU3 is now commissioned, so we do not see any further downtime as a result of commissioning and putting our existing wells through GTU3 to test it, which we saw in Q3. And additionally, we've had some workover done on various wells, which have come online during the beginning of Q4. Although, it's not adding material amounts, but it remains the case that we have seen higher-than-expected decline rates versus what we had anticipated at the beginning of the year.

We are clearly monitoring this, and we are digesting the reports from PM Lucas and Schlumberger in relation to the reservoirs where we have seen decline. And once we've digested those reports, we'll be coming back to the market with our views from them.

We have -- we are pleased to announce we've commissioned GTU3. The 72-hour test is complete, and we have signed off on the commissioning of the plant, and we can move it now to working oil and gas assets so that it can be depreciated as part of working oil and gas assets during 2019.

Additionally, on the operational side, we've announced that both wells 42 and 41 were tested and without any commercial flow. Well 361 has also been completed from a drilling perspective. Initial testing has shown no commercial flow of hydrocarbons at this stage, (inaudible) further perforations and further frac potentially (inaudible), but at this stage, we don't see any commercial flow.

From a strategic perspective, we remain ongoing work on the strategic review and addition ongoing work in relation to the acquisition, the potential acquisition of Positive Invest. We will update the market as and when we have further information on both the strategic review and any potential acquisition of Positive Invest. I would ask the questions at the end of this call and not trying to push us on further information on these 2, as we are unable to say anything more than what I've just outlined at this stage.

As we notified the market in the operational update, the Schlumberger and PM Lucas reports have been delivered to the company. These were delivered prior to the end of October when we made our operational updates, but they were late in comparison to the planned schedule which was in September. PM Lucas was roughly, I'd say, 20 days behind schedule, and Schlumberger was probably 2 to 3 weeks behind schedule. So therefore, in terms of the company digesting them, having time to discuss them and then building that into our planning for 2020 and beyond, well this is still work in progress (inaudible) on this call, be providing any details in relation to what we initially think because we haven't gotten to that stage yet.

Once we have got to a point where we believe that internally, we have a common view both amongst our technical team and at the board, then we will be communicating this in relation to what it means for drilling in 2020 and beyond.

Our licenses for both Rozhkovskoye Square and Chinarevskoye, in relation to Chinarevskoye, this means that we have now included the northern area where Well 40 is producing from.

That covers the highlights on Page 2. I'd now move to Slide 3, which gives a snapshot to some of the key figures. As I have mentioned from a production and sales volumes perspective, we have revised guidance down on production by 2,000 BOEs per day from 30,000 to 28,000, and on sales volumes by 1,000 from 28,000 down to 27,000 BOEs for the year. This assumes, as we've always outlined, no additional wells coming online during the year of 2019. This is exactly in line with what we forecast at this stage.

From an operational cost perspective, we have continued to focus on trying to bring down costs where possible. We have seen reductions in the operating costs versus our budget throughout the year and also in terms of any CapEx spend, we are trying to ensure that we are really analyzing any dollar that is put into the ground needs to be justified from both an economic, operational and risk perspective such that we are trying to deploy our capital in the most efficient way to generate a return for all of our stakeholders.

We've continued to generate those through the 9 months, stable cash flow from existing production, we have (inaudible) for the first 9 months of the year, which was in line with our forecast at the beginning of the year from a cash flow perspective and liquidity perspective.

If I now move to Slide 4, which looks at the balance sheet. As I mentioned at the start of the call, we have $91.3 million of cash on our balance sheet and cash equivalents. We expect to be able to build this to over $100 million over the course of Q4 as we are building cash through the sales of our products and not having to pay any coupon payment during Q4.

As everybody is aware, on this call, Nostrum has $1.125 billion of debt. This is split into 2 bonds, one, $725 million bond maturing in July of '22. This is the first maturity, the first debt maturity we have. We have no other debt maturing prior to this. And then we have $400 million that comes due in February of 2025 (inaudible) only debt that Nostrum has outstanding. And as I would reiterate, we have until July of 2022 until the $725 million becomes due.

From a hedging perspective, we have not entered into any hedge during 2019. We have assessed the market on an ongoing basis. And in combination, we're looking at what our fixed capital costs are in terms of investment into either infrastructure or into the ground during the year of 2019. As we have come now to the end of the expenditures on GTU3 with roughly $14 million left to spend in Q4, we don't see the need to hedge in relation to our major CapEx project over the last 4 years, being GTU3, so there was no hedge put in place on that.

And in relation to drilling, we're looking to establish what our drilling plans are for 2020 and beyond, and look to build around that (inaudible) our view in relation to whether to hedge or not.

The cash flow generation, I have mentioned, we have $160.2 million of cash flow generated during the first 9 months, and we have maintained a healthy EBITDA margin of over 60% through each quarter on a stand-alone basis.

From the drilling program, I've mentioned the results on Wells 42, 41 and 361. And as stated at the beginning, the guidance for 2020 will be provided once we have internally analyzed the PM Lucas and the Schlumberger reports, but this should be concluded before year-end.

And in addition, one note in terms of timing, we would also look to have concluded or be able to provide some update on the strategic review by year-end.

Moving to Slide 5, which is the cash bridge. This shows our closing cash of $91 million at the end of Q3. We have or we expect to generate operating cash flow of roughly $40 million during the fourth quarter. We have roughly (inaudible) of payments remaining on GTU3 during Q4.

And then you'll see a box with capital available to invest of $16 million. This is the amount that we have available to us should we wish to invest further into drilling or infrastructure or other initiatives in order to allow us to remain above $100 million for the closing cash for the (inaudible).

I do not anticipate at this stage that we will be spending anywhere near to the $16 million. We are -- as pointed out, we are in the final stages of testing Well 361. And until we have then digested the PM Lucas and Schlumberger reports, we would not be committing the company to any further drilling CapEx in 2019. Therefore, we are pending the internal review of these reports before we spend more on drilling. Therefore, I would expect the capital available to invest would be purely focused on ongoing small engineering or QHSE projects that we would have at field site. That's why I would not expect us to spend that full $16 million during Q4 of 2019.

Moving to the final Slide 6. This is just to reiterate, in our view, the unique location of Nostrum's infrastructure in relation to the raw gas fields in Northwestern Kazakhstan. And just pointing out that we sit effectively between the Karachaganak fields to our east, and the fields owned by [Positive Invest], Stepnoy Leopard, to the west. And in between that, we have our own fields, which are Rostoshinskoye, Darjinkskoye, and Chinarevskoye. And in addition, then just to the south of the Chinarevskoye field is the Rozhkovskoye field, which is owned by MOL, KMG and Sinopec, with which we have entered into an agreement to both purchase that (inaudible) their raw gas and condensate.

And as you can see also you have from an export route perspective, we have both railways and both gas pipelines and oil pipelines running (inaudible) to our infrastructure at the Chinarevskoye fields, providing us with a unique infrastructure setup in Northwestern Kazakhstan. That concludes the overview of the 9 months financial results for 2019.

I would now like to pass it over to Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Your first question comes from the line of Anton Rozanov from Argentem Creek Partners.

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Anton Rozanov;Argentem Creek Partners;Analyst, [2]

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Tom, you said a couple of things about the guidance for the full year in terms of the production and sales, but guidance is still unclear. What is it that you meant to say? Did you mean to say that Q3 decline was worse than it should have been, and it was affected by some workovers? Or some downtime? Or some inventory? And still not clear how to think about the guidance that implies that the production sales in Q4 will be sequentially up in Q4?

And the other question is, I noticed there's some unusual distribution of sales amounts between the domestic and export. For some reason, domestic sales were sequentially up, right, because -- and I think prices and volumes are generally down. So I wasn't sure, but what is the unusual distribution between the 2 segments? What was it driven by?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [3]

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Yes. Okay. Maybe if I can just, from a statistical perspective, I can answer that on the sales volumes, and then the -- in the financial report, the way that we've reported domestic and export revenue.

So firstly, just in relation to the statistics of the each quarter, and I appreciate everybody here has got their calculators out (inaudible) volumes for Q4 in order to meet the revised target of 27,000. And I think everybody is calculating at the moment that we were around 25,000 in Q3. So therefore, we need to be increasing that in order to hit the average of 27,000.

So what I'm referring to there is 3 main items. Firstly, is the fact that we had one condensate cargo that was not sold in Q3, and it was sold right at the beginning of October. So right at the beginning of Q4. So from a sales volume perspective that hurts in Q3 and will increase in Q4 because we had reduced, obviously, all the way through Q3, we had that target sitting there, but the timing of the actual delivery and sale of that shifted into Q4.

Secondly, we had 2 tests of the GTU3. During Q3, we had a 48-hour test, and we had a 72-hour test. During the 48-hour test in order to, let's say, make sure that, that was all safe and to test the flare stack, you're having to then flare some of the gas. So as a result, you're losing production that you are effectively producing out of your wells is not being sold. So therefore, there was more downtime during the testing and the moving of the wells from GTU1 and 2 to GTU3 in order to complete the 48-hour test and the 72-hour test.

So we had, let's say, more downtime than you would expect. Typically, when you're looking at these numbers. Then fourthly, also we had a well, an oil well, and this is not so significant but we had an ESP pump that was being replaced during workover. It was online during Q1. It was not online during Q2 and Q3, and it's back online during Q4.

So if you take all of those factors into account. And you take -- you're always going to have some downtime compressor replacements in ad hoc field downtime that we had in Q3, which was higher-than-expected through the first half of the year. This has led to the fact that we would expect, at this stage, to be able to hit the sales volumes, the revised sales volumes target that we have given to the market. But I don't want to cover over the main point, which we're trying to make in the release, which is irrespective of the, let's say, these reasons for the deviation maybe between Q3 being lower than Q4 or vice versa. We're not trying to get away from the fact that the decline was higher or faster than expected than we had forecast at the beginning of the year.

So the main point being is we need to analyze this. We need to understand why that decline was faster. And clearly, in relation to the reports done by PM Lucas and Schlumberger, we need to consider it in light of those reports. So that -- the overriding focus for us is to look at the reasons for the decline being faster. That's the real reason why we have not hit the 28,000 sales volumes that we had anticipated at the beginning of the year.

Then in relation to your question on the revenue, this is always -- at this stage, it's somewhat of a moving -- yes, it moves a little bit, the proportion. Look, these are 2 factors. One is that you're not always delivering in a completely uniform way your domestic sales quota for both crude oil and LPG. And then, secondly, from an accounting perspective, we are increasingly selling more LPG to FCA Uralsk. And depending on who the actual (inaudible) local entity, then that gets considered as a domestic sale.

So it doesn't necessarily mean that we are selling more at domestic prices, it means that the customers that we're selling to, may well become our clients who are then distributing into other regions on our behalf, that we get the best price from them relative to us doing all the transportation to an end customer in the Ukraine or in Bulgaria or the at Black Sea in Russia.

So I would look more at the netback per BOE rather than the split of revenue that is in domestic versus export revenue.

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Operator [4]

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Your next question comes from the line of Colin Smith from Panmure Gordon.

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [5]

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I've got a few questions, if I may, Tom. First one, just on GTU3. Can you confirm that all well fluids are now being processed through GTU3, which I think was the plan? Secondly, can you just confirm what its current carrying cost on the balance sheet is? And third, can you advise what sort of impact it's likely to make on the depreciation charge for next year? And over what period you're depreciating it, given when the license technically expires?

And then I've got some follow-ups on different subjects.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [6]

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Yes. No problem. So let me take those one at a time. So GTU3, currently, we're not putting any of the wells through GTU3. This is due to the fact that we have completed the 72-hour test, as we had announced. But then you have to wait, obviously, for all of the documentation in order to be able to get it signed off by the authorities.

In addition, we want to do an internal cost analysis of -- as I've mentioned, say, during Q3, we've had a lot of downtime when we move wells from GTU1 and 2 to GTU3. We want to do a cost-benefit analysis of what will the savings be or the increased potential revenue be for putting it through GTU3 versus what is the increase in potential OpEx. And what does it mean in terms of the various different technical areas, which I'm not a specialist on, but in relation to, for instance, the inlet pressure? And what is the minimum volume required to make GTU3 really operationally as efficient as possible?

So that work is ongoing at this stage. We are -- we've got all of the documentation from the ability to be able to move it to working oil and gas assets. But that obviously took some time after the 72-hour test, and we didn't want to have -- that's a bit like getting a license extension, you don't -- you're not fully in control of the time it will take in order to get all of the right permits and documentation. So therefore, rather than just sitting and not producing anything, we moved everything back to GTU1 and 2.

So as we stand today, everything is going through GTU1 and 2. I believe, and I don't want to speak out of turn here, but we've got everything from an accounting perspective to move GTU3 to working oil and gas assets. But I don't know whether everything from a QHSE, all of the different documentation you need environmental (inaudible) have all finally been delivered and signed off. So I think we'll be cautious to move the gas again in there and then move it back again. So it needs to be looked at in whole was simply the best way forward in terms of the existing feedstock that we have and reduce -- making sure our costs are as low as possible, but obviously maximizing [revenue].

From a carrying cost perspective and the depreciation charge, we will start -- on the carrying cost, I will e-mail you the exact number.

I don't have it with me. But on the depreciation, we will start depreciating it in Q4. So during 2019, we will start depreciating GTU3, which will help us to reduce the corporate income tax that we will pay in 2019. And we are investigating from a tax perspective, what is the most efficient way to do this. I expect and the current information I have is that we would look to depreciate this as quickly as possible over a either 2 or 3 period. And the reason for this is to do with the fact that as soon as it gets moved to a working oil and gas asset, in our PSA, all tax accounting is done in tenge. So effectively, you have, and let's call it a $550 million project, would then get immediately translated at the current exchange rate into tenge (technical difficulty) that's done in tenge over the course of a 3-year period, or however long a period you choose to depreciate it over. If therefore, the tenge devalued significantly during that period, and let's assume it was today and it devalued 100% or to 50%, you would find then you're effectively losing in dollar terms, you're not able to recover the dollars that you've spent because you're only depreciating in tenge, of which that value has then devalued the entire value you've got sitting on your tax books. Now the IFRS, you will see it in our financial statements, you will not see that everything is in dollars

(technical difficulty)

tax liability come onto the balance sheet. So therefore, from our perspective, from a tax accounting perspective, we believe it's most prudent. Obviously, we're going to do all the necessary homework before doing this, but we believe at this stage, it's most prudent to be able to depreciate this as quick as possible because of the fact that it gets booked in tenge on our Kazakh tax balance sheet, effectively.

So I hope that answers your questions in relation to GTU3 and depreciation.

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [7]

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Just a follow-up in view of your comments about the pace of depreciation. I mean presumably, that implies potentially pretty substantial losses at the P&L level over the next 2 or 3 years as, let's say, a $550 million or $600 million asset gets depreciated over 3 years?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [8]

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Not under IFRS because under IFRS, we use the unit of production method, which is looking at just the historical costs. Okay. And then looking at the change in the proven reserves and effectively taking a percentage then off the total historical costs. So this is where the deferred tax liability is impacted because you have a different approach under IFRS than you do under our Kazakh tax accounting.

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [9]

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Sorry. So my question was a bit more about what impact is there on the P&L. I mean obviously, tax is part of it. But in terms of the DD&A charge through the P&L?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [10]

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Yes. So yes, so through P&L -- so through IFRS P&L, you're not going to see a significant charge because it's a different depreciation rate. Because your -- so for our IFRS that you'll see that we publish, you're seeing a depreciation rate which is done off the unit of production methodology, which to give you a rough approximation will be 10% over the next 10 years, 7 years. And that will go through our tax accounting perspective, i.e., what do we really care about. When it comes to calculating the profitability of the company under the PSA, you have to look at it from what our Kazakh tax accounting rules are. And here, we don't want to take the FX risks on the balance that we'll have it sitting there in tenge. So therefore, it's optimal to appreciate it as quickly as possible. (inaudible)

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [11]

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Exactly so. But I mean, if you take 10% of -- if you're talking $50 million or $60 million a year of incremental depreciation, I mean that is getting on for a 50% increase in the current DD&A chart.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [12]

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I can come back to you with the exact number that we would expect. Obviously, we need to complete for the percentage on the unit of production methodology, we need to complete the year-end reserve report. And then we'll have the calculation available. But it's -- I can provide you with some guidance on the rough calculations that we're looking at today, but it's -- yes, it will have an increase, but it's not going to be 1/3 of it will not get (inaudible) under IFRS in 2019.

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [13]

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Okay. We can pick that one up. And turning then to the cash bridge that you've got there. Can you just say where the lease expenses, sorry, the lease cost that's coming out in that chart, not lease cost, the actual payments on the leases. Is that operating cash flow?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [14]

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Colin, you broke up there. The line went quiet for a while. Can you repeat the question?

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [15]

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Sorry. Yes, the line has been a bit tricky, I think. Just on your Page 5, your cash bridge. Given the change in treatment on operating leases, where is that actually appearing in that cash bridge?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [16]

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It's all coming through in the operating cash flow predominantly.

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Colin Saville Smith, Panmure Gordon (UK) Limited, Research Division - Oil and Gas Analyst [17]

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Okay. So we'll see that? Okay.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [18]

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So it's -- and to give you an idea, the leases are in relation to transportation, which is coming through. We look at -- forget IFRS, we look at transportation that is coming through as part of the calculation into operating cash flow. Part of it has to do with is one contract we have in relation to the operational activities of the company. So they are coming through again in operating cash through -- cash flow. And then another one is in relation to the existing Saipem rig that we have at our field sites would come through in the $16 million of some of those costs that we have on CapEx. So it's not -- this -- the majority of this is coming through in the operating cash flow.

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Operator [19]

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Your next question comes from the line of [PT Paksarva] of [Telema].

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Unidentified Analyst, [20]

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Thank you for the presentation. Can you hear me?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [21]

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Yes, I can hear you.

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Unidentified Analyst, [22]

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Yes. So I have several questions. One on the line was interrupting. Could you please explain again what you think about the Q4 CapEx? I remember you mentioned that there will be no drilling CapEx. So what should we sort of plan or forecast for the Q4? And the second question is also around GTU3. What would be the maintenance CapEx for GTU3 starting from 2020? And would it depend on your decision to process your hydrocarbons at GTU3 or say to keep them at GTU1 or 2?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [23]

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Maybe I can address the first question and then Kai can talk to the GTU3 maintenance CapEx. So just on the capital available to invest. Obviously, we have rigs at the moment on field site. So there will be some drilling CapEx in Q4. We have payments to make to Saipem in Q4, and we are continuing to test well 361. So there will be some CapEx related to drilling operations and workover operations during Q4. But I -- my point I was making is, I do not expect that to reach the total of $16 million. So therefore, I expect us to have a closing cash balance at the end of Q4 of slightly above $100 million.

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Unidentified Analyst, [24]

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And just one follow-up question. How -- what is the average cost now to drill a producing well, if? I remember, at some point, you mentioned it was something between $10 million to $15 million? Has it changed? Or I am operating on the wrong basis?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [25]

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No, I think that the average cost -- sorry, Kai.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [26]

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No, please. Go ahead, go ahead, go ahead.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [27]

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As you can see, the average cost has come down significantly over the last 2 to 3 years. And today, we would be looking at an average, depending on, again, the type of well. But if you look across the year, on average, I'd say the 3 wells that we drilled in the north, you can roughly speaking use a figure of about $10 million on average for the well. But we've drilled wells historically at as low as $8 million. But it depends on the design of the wells, the type of the well and the target. But on average, this year, it will be around $10 million.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [28]

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Just to continue on the maintenance CapEx. As for the GTU3, there are no major maintenance CapEx for the year 2020 on the GTU3.

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Operator [29]

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Our next question comes from the line of Matias Castagnino from BCP Securities.

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Matias Castagnino, BCP Securities, LLC, Research Division - Research Analyst [30]

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Two questions, if I may. The first one is can you tell us what is your current production as of today? And the second question is just to follow up on the previous question. The $16 million of capital available to invest that you show, should we think that as your maintenance CapEx going forward to keep the current production?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [31]

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Yes, let me...

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [32]

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Thomas, have you understood the first question? I couldn't understood the first question correctly.

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Matias Castagnino, BCP Securities, LLC, Research Division - Research Analyst [33]

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The first question is, if you can tell us your production as of today?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [34]

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Okay. Understood. Can you answer the CapEx question, and I will prepare the answer for the daily production.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [35]

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Yes, I will answer the CapEx question. No problem. So on the CapEx, in terms of the $16 million, the $16 million in the cash flow bridge. You shouldn't look at this as maintenance CapEx. As I mentioned, this is going to be partly from the completion, the cost of completing drilling on 361 and then testing of 361. So that's in relation to the completion and testing of a well. Part of it will be in relation to ongoing engineering projects, where we have, for instance, a fourth compressor being delivered for the low-pressure system. We also have various different QHSE projects ongoing in order to enhance, for instance, the (technical difficulty) in terms of piping in terms of making sure everything is secure. So there are various different projects ongoing. And I would say that these are not what I would call just pure maintenance projects. If you take drilling and you take the low-pressure system, these are projects -- these are capital expenditure projects which are looking to invest in the field, which we would not be doing on an annual basis -- on an ongoing annual basis. I'd say on the QHSE, this is something, obviously, we would look to do every year. We have a budget for QHSE. But it's not a significant part of that $16 million. So I would not look at the $16 million as a maintenance CapEx on an annual basis.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [36]

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And average daily production in the month of November so far has been around about 27,000 BOEs per day.

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Operator [37]

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Our next question comes from the line of [Anthony Smoder] from [Atlantic Cominion].

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Unidentified Analyst, [38]

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My question is really as you could explain to me, maybe other people know, but on the balance sheet, and I'm looking at Page 8, I just want to try and understand where the -- you have shareholders' funds of $561 million. Which are the things that could change or which are there for a balance sheet from just a balance sheet perspective? Because clearly, the value of the securities that you have is a lot less than what appears on the balance sheet. So how would that change on a real-time basis? What could go up or could go down?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [39]

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Anthony, thank you for your question. I suggest maybe we -- there's obviously a lot of variables there. I think the -- whether I -- happy to have a call off-line in terms of how we look at the balance sheet.

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Operator [40]

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Your next question comes from the line of Konstantin Chinarov of Aptior Capital.

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Konstantin Chinarov, Aptior Capital - Credit Product Analyst [41]

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So if you hit your guidance for 2019, it looks like that the cash balance in the year-end will be around $100 million. So if I look back, pretty much since 2009, the company has been running on a cash balance as of year-end of more than $100 million. So it feels like, I don't know if you mentioned before, but would be helpful to know that of the minimum cash balance for the business? And then secondly, sort of in line of sort of unhedged exposure to the oil market and, say, $100 million sort of fixed cost -- fixed sort of cash outflow in relation to the financing facilities and another $50 million of sort of CapEx spending to sort of maintain current production levels. What's your thinking in terms of the sort of available financing -- available liquidity that might be needed for the business to sort of to support liquidity? So how do you think about it?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [42]

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Yes, okay. So minimum cash balance that we've historically always targeted to have over $100 million of cash at each year-end, which we've, broadly speaking, achieved. In addition, I believe we've had internal policies to try to maintain at all times during the -- to start each quarter, over $50 million of cash. I think if you're asking, what's the minimum target we need to be able to run the business, so if you look at the working capital swings, you can -- that would be the answer I would give in terms of the biggest working capital swing I think we've seen is around $25 million, roughly speaking. And as production has decreased, those swings will get less and less.

So therefore, the kind of minimum cash balance would reduce. So I think you can run the business very comfortably at the current production levels with over $25 million of cash in your balance sheet. You don't need to have the kind of levels that we've been communicating. But from a prudent financial perspective, we've tried to always ensure that we've had a cushion that we can rely upon in the event that oil prices were to dramatically fall, as we have seen in the past, and we wouldn't be then exposed if we had a very small cash balance to any material fluctuations in our product prices. I think in relation to your question on what is -- what available cash do we see is -- that's on our balance sheet that is available for investing into the business, that's linked somewhat to the question of the strategic review, and what direction are we going to take, what acquisitions, what drilling that we're going to do in 2020.

And until we've answered those questions internally, it's very difficult to give you a guide as to how much of the cash available would we look to deploy into the business. At this stage, we are -- and I appreciate it's frustrating, but please bear with us whilst we look at the PM Lucas, the Schlumberger reports, the strategic review, the potential acquisition of Positive Invest. Our view is that we need to maintain liquidity as we look at all of these different areas and analyze them. And we need our time to make sure that we try to come up with the best decision-making and the best allocation of capital in order to try to create value for all stakeholders going forward. So I appreciate that doesn't really answer your question in a nominal amount, but please bear with us whilst we work through this strategic review process. And whilst we work through the Schlumberger and PM Lucas reports and consider what we want to be doing in 2020 and beyond.

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Konstantin Chinarov, Aptior Capital - Credit Product Analyst [43]

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And also in light of the Stepnoy Leopard acquisition like the second installment, which could be around sort of $45 million, $50 million. And in light of the minimum cash balance, is it fair to say that -- maybe if you could comment on the sort of like -- are you thinking about the financing of that transaction? Or are you going to use sort of the idea is to use the cash on the balance sheet, obviously subject to the minimum cash balance due to that transaction?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [44]

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As I said, we're in the midst of reviewing all of these different initiatives that we have ongoing, ranging from the strategic review through to Stepnoy through the Positive Invest of the Stepnoy Leopard licenses. At this stage, I don't want to comment because very different work streams. We're looking at PM Lucas and Schlumberger reports. We need to determine what to spend on Chinarevskoye in 2020 and beyond. So therefore, I don't want to answer that question directly because I don't have an answer to it today.

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Operator [45]

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(Operator Instructions) Your next question comes from the line of Janna Anikina from BCP Securities.

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Janna Anikina, [46]

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Could you please -- line cuts in and out, and I couldn't quite hear when you're discussing CapEx. In order to maintain the current level of production of 27,000 BOE per day, what is the minimum CapEx you require?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [47]

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Kai, do you want to take that one?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [48]

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Yes, there are always quite extensive question, it depends, let's say, for which reservoir you're drilling, which wells, as we have different production rates for wells producing from each different reservoirs. If you just take a sales example, the late [12], what we drilled in the Biski reservoir, they came in [honestly], let's say, with an average production of roughly 2,000s BOEs per day. So if you're taking from the current level, a decline rate of 50% per annum. So you have to replace at least 4,000 BOEs per day. So this would mean 2 wells, and that kind of drilling costs $20 million.

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Janna Anikina, [49]

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$20 million?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [50]

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Yes.

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Janna Anikina, [51]

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$20 million for 2 wells per year?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [52]

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Yes, correct.

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Operator [53]

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Your next question comes from the line of Anton Rozanov from Argentem Creek Partners.

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Anton Rozanov;Argentem Creek Partners;Analyst, [54]

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It's me again, just another question about can you expand on the well 361, where it is located? Which reservoir it is targeting? And what the results were exactly? And is this just an initial flow or sort of initial test results? And whether you're still testing it?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [55]

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Yes. Just a short summary, the well 361 was targeting the Vorobyovski reservoir. It's a Devonian reservoir in the northern area of the license. So roughly 2 kilometers, I would say, southwest from the well 40. Located, it goes deeper than the well 40, and we found the Vorobyovski reservoir hydrocarbon [dealing]. All the other information will be announced as soon as we have concluded the test of that well. Currently, the test operations are ongoing.

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Operator [56]

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Thank you. There are no further questions at present.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [57]

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Okay. Well, thank you very much, everybody, for joining the 9 months 2019 financial results call of Nostrum, and we look forward to speaking again for the full year results 2019.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [58]

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Thank you very much. Goodbye.

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Operator [59]

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That does conclude our conference for today. Thank you for participating. You may now all disconnect.