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Edited Transcript of NOG.L earnings conference call or presentation 20-Aug-19 1:00pm GMT

Half Year 2019 Nostrum Oil & Gas PLC Earnings Call

Amsterdam Aug 26, 2019 (Thomson StreetEvents) -- Edited Transcript of Nostrum Oil & Gas PLC earnings conference call or presentation Tuesday, August 20, 2019 at 1:00:00pm 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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* Alexander Martynenko

Investment Capital Ukraine LLC, Research Division - Head of Corporate Research

* Anton Rozanov;Argentem Creek Partners;Analyst

* Colin Saville Smith

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

* Dmitry Sentchoukov;Wellington Management International Ltd.;Analyst

* Ian McCall;First Geneva Capital Partners;Managing Partner

* Nikolay Menteshashvili

Insight Investment Management Limited - Credit Analyst

* Oleg Chistyukhin

Renaissance Capital, Research Division - Research Analyst

* Rumen Ivanov

ICE Canyon LLC - Analyst

* Zafar Nazim

JP Morgan Chase & Co, Research Division - Senior Credit Analyst

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Presentation

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Operator [1]

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Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to today's H1 2019 financial results conference call. (Operator Instructions) I must advise you that this conference is being recorded today, Tuesday, the 20th of August 2019.

I would now like to hand the conference over to our speaker today, Tom Richardson. Please go ahead, sir.

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

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Thank you, and welcome to Nostrum's First Half 2019 Financial Results Call. We will use the usual format. I will go through the slides that you can find on our website to give an overview of the first half of 2019, and then it will be followed by a Q&A. You have also Kai-Uwe Kessel, our CEO, also on the line joining me. My name is Tom Richardson, CFO of Nostrum Oil and Gas plc. And if I can ask you to turn to Slide 2 of the presentation, I will take you through the first slides, and then we will move on to Q&A.

So first half 2019, from a financial perspective, was a strong quarter -- or sorry, first half. And then we have revenue of $174 million, EBITDA of $110 million, and we got our closing cash up to -- or just over $120 million. And this was a result of an unwind of a receivable balance, which we had at the end of Q1, which increased the cash position of the company back above our target of $100 million up to over $120 million as of the end of Q2. So from a financial perspective, we now have cash back on our balance sheet over $100 million, strong operating cash flow during the first half, and we enjoy the benefit of higher oil prices, which are averaging around $66 over the first half of the year.

This financial performance is obviously based on a sales volumes of the business of 29,210 BOEs per day. And as we had highlighted at the beginning of the year, we were drilling 2 wells in the northern area, and we've given guidance which excluded any new wells coming on in the first half of 2019. So you've seen just the steady decline of our existing wells from year-end of 2018 through the first half of 2019, and this is average sales volumes of 29,210 with an unwind of a majority of net receivable balance of Q1 and also inventory coming down from Q1. As of the end of the first half, we have relatively small inventories compared to the end of Q1.

We've also made -- from an operational perspective on GTU3, we've now moved into the hot commissioning phase and full commissioning remains on target for the end of Q3 2019. We've had a small increase in costs. You'll see that have we still roughly $20 million remaining on GTU3 to get this through to full commissioning. This is a result of the initial timetable expected to be completed in April of this year. This has obviously now moved to Q3, end of Q3, so September 2019, and this has resulted in further costs in relation to people on the ground that we need for the full commissioning process. But we look (inaudible) commissioning completed and for the commissioning of the plant.

Two key other operational items we have been addressing during H1 has been the drilling of the 2 northern wells, wells 41 and 42. Well 42 was completed first. We had tested -- as we announced in our operational update, we had tested 2 horizons, which Kai will speak to later, which confirmed gas saturation but no commercial flow. We have the Frasnian section remaining to test, and we have started to test it. Thus far, the testing is ongoing. On 41, we have also tested the Frasnian section. We started testing it. We have seen some hydrocarbons, but we need more time to clean the well before we can confirm whether this is commercial flow or not. And Kai can speak to this later in the presentation.

From a strategic perspective, we have the proposed (inaudible) Leopard license, where we are looking to acquire Positive Invest. We are working towards bringing this to shareholders to vote on and remain on the view that this is strategically a very important step for the company and an exciting step to be able to secure further hydrocarbons in Northwest in Kazakhstan, which we can then develop infrastructure, which will have completed by the end of Q3 2019.

In addition, we believe that with the portfolio opportunities, including Stepnoy Leopard, Ural Oil & Gas offtake, the development of the potential Trident fields and also the remaining areas of the Chinarevskoye fields, we see that there are a number of strategic options that Nostrum has for its future and for developing the future value of the business. And therefore, we have conducted a strategic review of all these options, which is ongoing today.

We move to Slide 3, which first gives a snapshot of production and sales volumes. Here, you can see that the sales volumes that I mentioned earlier were 29,000, and production after treatment was at 31,000, difference being the internal consumption that we are using in order to power facilities at site and also to power the drilling rigs at site. So there is an internal consumption of dry gas, which is really resulting in the difference between production after treatment and the sales volumes. You can see here that it's been averaging around, sales volumes for H1 2018 -- H2 2018 and H1 2019 [29,000] on average with production after treatment above 30,000. You'll see some small swings here depending on the difference between what has been produced and then the inventory that's actually been sold. So these numbers will deviate slightly as you go quarter-by-quarter or half-by-half.

The full year 2019 guidance, we remain guiding towards an average for the full year of 28,000 BOEs per day of sales volumes and production after treatment of 30,000 BOEs per day. This is based off us completing and commissioning GTU3 and then seeing the increase in LPG production coming in to bring our sales volumes to an average of 28,000 BOEs per day for the full year of 2019.

From a cost perspective, on the bottom half of the Slide 3, operating costs have steadily reduced from H1 -- H2 down to H1 2019. And you've seen here that from a U.S. dollar per BOE basis, obviously, the number of barrels has slightly reduced if you're looking at 2018, where we had 29,900. We're now at 29,200. But here, you can see that we are bringing the costs down. We have focused on G&A and OpEx. These are the 2 that are really within our control. And G&A, going back all the way to 2016, we had roughly $14 million more G&A back in 2016 than we do today. So we've taken out $14 million on an annual basis if you compare that. But if you think that also during 2017 and '18, we have seen those reductions come through, so it's been over $35 million of reductions out of G&A since the end of 2016.

Similarly, on the operational side, we are -- we continue to seek to reduce costs where possible. We have a low-cost onshore business, but obviously, we're also trying to commission GTU3. There will be some increase in operational costs that we see during Q3 as a result of running GTU1 and 2 and GTU3 at the same time for a brief period of time. Therefore, we will then put effectively GTU1 and 2 onto care and maintenance and just be running GTU3 where we will recognize the operational efficiencies and the higher LPG production that we can get from GTU3. So this then will result hopefully in a further decrease in our operational costs. Once we get through 2019 and we've commissioned our GTU3, we'll be able to then focus again on trying to really bring the cost base of the business down to its -- to a level that is reflective an onshore business such as ours.

We continue to generate strong cash flow from existing production. You can see that in H1 2019, operating cash flow was $116.8 million and that has increased half-by-half, even in the old price on average in H1 2019 with $66, whereas for H1 2018, it was roughly $70. And then in H2 2018, it was also above $70, around $72 per BOE. So we've increased operating cash flow as we've seen slightly lower average oil prices. This has been a function of the cost reductions that we're seeing. This is also a function of the fact that we've spent less from some slightly lower sales volumes, but also we've seen a reduction in some small transportation costs on LPG and also some better netbacks on some of our liquid products.

If I move to Slide 4. Capital discipline, as I just mentioned, is both on the cost side but also the costs related to preservation of cash. We have $120.8 million of cash sitting on our balance sheet (inaudible). We are well aware of the importance of this cash position and the target of keeping to $100 million plus at the end of the year. We are, therefore, as I mentioned from a cost perspective, looking to try to reduce costs where possible but also on netbacks where we can try to optimize netbacks, especially on the products where we are selling, such as LPG, to different locations. We try to always optimize the pricing we can get on all of our products, especially those that are within our control. We're continually looking at the different options we have available to us. And you will recall, we built a pipeline that connects our crude oil pipeline into the KTO pipeline, which allows us to now sell our crude oil through the KTO pipeline and get better netbacks than before when we were rail tank carrying it all the way to Finland Neste Oil's refinery. So we're constantly looking at ways of optimizing our cash and reducing costs and getting as much cash for the products that we sell, therefore, trying to build a stronger [cash] balance sheet as possible.

We have just 2 bonds outstanding. So this has not changed. Our debt position has not changed since we refinanced in 2018, and we continue to have the same amount of debt that we have. No desire to increase that level of debt currently.

[Hedge] that we had in place in 2018 has rolled off. We currently have no hedges in place, and we are continually assessing the market. However, we feel that with GTU3 expenditures coming to the end and therefore without that committed CapEx investment that we (inaudible) the last 4, 5 years, we don't see the need currently to have a hedge in place unless we see really attractive pricing in the market. With oil prices currently hovering around $60 per barrel, we believe this is not the time to be putting on a hedge. And we will wait to see if there is a more prudent opportunity from a pricing perspective, but also once we have a better view on what [we see are] capital investments we have for the coming years in front of us.

From a cash flow generation perspective, I've mentioned that operating cash flow has increased half-on-half going back all the way to H1 2018. We've now broken through $100 million for the half, and we've also seen the EBITDA margin increase as we've further cut costs.

On [drill side], we focused the first half of the year on drilling in the northern area of the Chinarevskoye field following the successful well 40 discovery that we made, and we are looking to conclude the testing of wells 41 and 42. We've also started drilling well 361, which is also in the northern area, targeting the Vorobyovski horizon, which Kai can talk to if people have questions later.

If I now move to Slide 5, which is showing the cash bridge. There's been a lot of focus historically on Nostrum's liquidity position. And I would like to reemphasize that, again, we are focusing on bringing the costs to the lowest possible level but also trying to generate as much cash as possible from our existing sales volumes. This will result in a forecast operating cash flow for the second half of the year of around $100 million. We have our coupon payment to make at $43 million, and we have the remaining costs to full commissioning of GTU3 of roughly $20 million. This would leave available, should we wish to deploy it, up to $59 million of cash on drilling, and that would still leave us with $100 million of cash on the balance sheet. Before we deploy any of that cash though, we want to see how the results from this northern area testing are concluded. And then we will look to decide on what the best way forward for a drilling program is in the remainder of 2019 and through 2020 and further on. But it shows in my mind on Slide 5 that Nostrum is in, from a financial perspective, 2019, we're in a healthy position cash-wise, and we have the ability to end the year in line with our guidance of over $100 million of cash at current oil prices.

Moving on to Slide 6. This, I hope, gives an illustration of the different licenses, which we both own and also how they sit in conjunction with the Stepnoy Leopard license (inaudible), one of which we have [struck a tolling] agreement, offtake agreement with -- which is the Ural Oil & Gas, which you can see is extremely close to the Chinarevskoye field. It is owned by MOL, Sinopec and KMG and is called the Rozhkovskoye license. And then you can see the Stepnoy Leopard fields, which are highlighted to the west of Chinarevskoye and close to the Rostoshinskoye fields that we currently already have owned since 2013.

This gives you an idea of where our infrastructure is sitting on the (inaudible) you can see on the map, ranging from: Karachaganak, which is the well-known, very significant large field, which has been producing for many, many years; you have the Rozhkovskoye fields, which is being appraised by MOL, Sinopec and KMG; you have the 3 Trident fields, which we currently own; and then the Stepnoy Leopard fields, which have had over 100 wells drilled and that we are in the process of bringing to shareholders to acquire. It demonstrates that within the region, all of, let's say, the discovered oil and gas resources, many of them are now within the ability of Nostrum to process the gas within those licenses, and we would like to conclude by acquiring the Stepnoy Leopard fields, conclude the ability to bring in all of the gas in the western area that has been discovered in the Soviet times or afterwards.

The idea of the different networks we have in order to distribute our products. You can see here that Chinarevskoye field is sitting right next to a major gas export pipeline. We've also got our own crude oil pipeline, which links into now the oil export pipeline that is run by KTO. So you can see also then the rail network that allows our LPG exports via rail to all sorts of different destinations, ranging from China all the way to the Black Sea, so all the way from east or west depending on where we see the pricing is best. So from a logistics and infrastructure perspective, we believe that we're sitting in an advantageous location with excellent export routes to all of our different products.

That concludes the short presentation, and I would now ask that we move 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 Zafar Nazim from JPMorgan.

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Zafar Nazim, JP Morgan Chase & Co, Research Division - Senior Credit Analyst [2]

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I had a couple of questions, one on the production guidance for the year. You're expecting 30,000 for the year, which kind of -- you can extrapolate that to 29,000 in the back half of the year. And in the first half of the year, we've seen a production decline of roughly 10%, so between 1Q and 2Q. I think 2Q was averaging around 29,500. So given this decline, I just wanted to get some granularity into why you feel that you will be able to maintain production of 29,000 in the back half of the year.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [3]

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There are maybe 2 major reasons for it. First of all, as you mentioned, we have currently gas production of about 41, 42. We're expecting one of these 2 wells coming into the commercial production, which will help us, let's say, to increase the production by roundabout 1,000 BOEs per day.

In addition, we have a program ongoing, workover operations where we are bringing old wells, which have not been in production, into production in different horizons. This program has been approved by the Board in March 2019, and we are currently successfully implementing it. We have completed, out of these 5 wells, 2 wells, reinstalling former gas condensate production wells, like well 213 from gas condensate [to move in] formation into oil producer in the Tournaisian formation. Let's say we have successfully done with well 45, where we installed a new [piece], and we are currently have 3 other wells where we are expecting each well, let's say, to produce roundabout 150 BOEs per day of liquid products. And these altogether give us a very good comfort let's say that we can keep the production at the levels which we have confirmed you. And this doesn't take into account any additional production, as an example, like from the 361, which is currently in drilling.

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Operator [4]

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We will now take our next question, and the question comes from the line of Colin Smith, Panmure Gordon.

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

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Two questions for me. Just a follow-up on the last answer because I also thought the decline was a little higher than I was expecting. And I thought guidance excluded production for many of the wells that are being drilled this year, which would include -- excluding any production from 4 -- wells 41 and 42. So just wanted to recheck that the sort of decline you're seeing is as expected, and there isn't anything else that need to be concerned about.

And then just coming back to the actual performance of wells 41 and 42. You've indicated that you don't think well 42 is going to be commercial in the Frasnian. And I just wondered if you could give a little bit more of an update of what you're seeing in well 41 so far, and overall, just how confident you are that you will be able to get commercial flow that looks something like well 40 as of -- at well 41.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [6]

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Yes, very complex question. Again, just coming back to the guidance. In our original budget, I think that we always guided as well the [announced] too, we are always foreseeing, let's say, roughly a production of 1,000 BOEs per day out of the new wells, being at 41 or 42. Whereby in our original budget, let's say, we're all assuming that this production shall come from the 41.

As of to date, I'm still very comfortable, let's say, that we can obtain that production rate in 41 as we have done [in open hole or in] drills being tested during drilling of this upper Frasnian section, where we had obtained very good inflow of hydrocarbons from this upper clastic section. We then drilled further. We found a second similar section in the same Frasnian reservoir. So we have -- we believe now that we have instead of one reservoir, like in the 40, we have now 2 reservoirs in the 41 in these clastic sandstone section. So one has been, as I said, already successfully been tested during the DST drilling operations. Therefore, on that side, I'm very, very optimistic, let's say, that we can achieve what we have targeted. What is currently said, other wells like 361 or 61, which are currently under drilling, we have not taken into account in our 2019 production forecast.

I was just saying, let's say, that we have 5 that over operations, so they are not called drilling operations where we are reentering old wells which have been drilled in the past, which are currently not in production. And we are seeing here a very good success so far of that operations, workover operations in these old wells. And from the first 2 wells that we had worked on, we could bring both back into production. And we are seeing 3 more wells, which we can then produce.

Coming back to your second question, what we are seeing in reality about 41 and 42, let me start with well 42. Well 42, first of all, we tested -- we drilled and deepened the well, significantly deeper than it was originally scheduled. So originally, the well was just scheduled to drill the clastic Frasnian and the underlying carbonate formations. And then we decided to drill and to deepen the well, and we drilled the well down to the Vorobyovski reservoir. And the reason was the [following] that we have at that time scheduled to drill about 361 into the Vorobyovski horizon, which we are seeing as the most promising horizon in this northern area. And as we had not seen any of the main risks, let's say, on this Vorobyovski horizon was the hydrocarbon saturation and the new well properties. So we drilled about -- 42 down to the Vorobyovski, and then we tested the Vorobyovski reservoir. And even having not received commercial rates, we received an inflow of hydrocarbon at significant rate, not commercial, but at significant rate, which proved finally the hydrocarbon [beading] of the Vorobyovski reservoir in this northern part.

So this gives us a much better comfort, let's say, that the well 361, which is currently drilling and has, just as we speak, reached the targeted depths at 5,200 meters where we are now setting the sediment liner. And then opening the Vorobyovski reservoir gives us a much better expectation on this Vorobyovski horizon. So we are expecting that we are -- 361 now within the next 2 to 3 weeks, we'll penetrate the Vorobyovski horizon. Then we hope to get the expected results in this Vorobyovski horizon.

Indeed, not that I expected, we saw the Frasnian clastic sections and the top of part of well 42, just the thickness of 1 to 2 meters, so significantly shallower than in well 40. And therefore, we don't expect that [cat] operations after ongoing cleanup of the well is ongoing. We see some pressure increase in the well periodically. We are cleaning the well out, but we currently don't expect that we can see here commercial rates due to the fact that we are in the very same reservoir section, the area where well 42 has penetrated that Frasnian section. So the overall understanding of the geological models in this northern part on the other side, this well 42, was very, very much important for us.

Coming back to well 41. 41, we have a principle, repeated the same like in well 42. During drilling, as I have mentioned, we decided then to make a drill stream (sic) [stem] test in this upper Frasnian sandstone section, where we had a commercial inflow. And then we decided, of course, to drill the wells further because we were trying to drill through the carbonate section as well in well 41. We then -- we are seeing this clastic section or the thickness of the clastic sections in well 41 being much particular than in well 40. As an example, we are seeing an overall section of more likely 65 meters. And then 30 meters or 40 meters below the horizon, there be -- the drill this -- or we tested -- drill stem test this upper Frasnian section, we found a second sand valley with very good gas shows and -- so we are now here assuming that in well 41, we have 2 layers, this thickness altogether of roughly 5 to 6 meters of very good sandstones. And then we deepened the well as well. We were drilling full of carbonates down again till the Vorobyovski horizon. We then tested the Vorobyovski horizon, like in well 42. And during this test operations, we [bought] again an inflow of hydrocarbons in well 41.

We had a technical issue during the clean out operation. Most likely this is our current rotation. Some there sliding sleeve and/or the [pipping], which we set inside the liner has -- becoming leaking. As we got in a well-integrated problem, we had almost 1-month technical discussions how best to overcome the situation. In the meantime, we released the rig and we are currently -- have decided to not to test all the carbonate sections because it takes too much time at the moment. We have -- there we had seen very good gas shows during drilling, but we have decided to go -- we test operations to the upper 2 Frasnian sandstone sections. They are both behind 1 [bulk] hectare. So we are perforating both intervals, and we are just starting the temp operations in the 41. But I have -- still hear a very good expectation following, let's say, the drill stem test which we have done during drilling that you will see here the commercial inflow of hydrocarbons. Yes.

The rates, I can't just speculate. I will not give you a figure now. But it -- taking the reasons from the DST, tests which we have done in the upper section, the overall rate shall be a small event in the 40. On the other side, we see here 2 sections, and therefore, we have then to see the result once they are coming to production out of those sections. I hope this answers your question.

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

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Okay. I mean if can just summarize my understanding, and you can correct me if I got it wrong. So on well 42, you've got very encouraging flow from the Vorobyovski, although not commercial, but that makes you more confident about the results of well 361, which you're drilling at the moment. And the Frasnian section in that well was less well-developed or shallower, thinner, excuse me, than in well 40 because of the location relative to the well 40 well. So that well is not going to be commercial in itself but was encouraging for the Vorobyovski.

And then in well 41, you've actually started testing the Frasnian, but you're actually expecting, given what you've seen, 2 sand bodies rather than one, which you have in well 40, a result on testing that is probably on a par with the kind of performance that you're getting out of well 40, obviously subject to actually testing it.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [8]

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Correct. Exactly. That's exactly what we said.

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

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And just in terms of the length of time to get that test result on well 41, just roughly what's the schedule for that?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [10]

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I would assume roughly 2 weeks.

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

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2 weeks from now.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [12]

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Yes.

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

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Okay. That's very helpful. And I'm sorry, if I may follow up. Can you just give us some idea of the schedule on completion of the reservoir studies that are underway and when you might be able to tell us a bit more about what they show for the northeastern part of the field?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [14]

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It's -- again, the reservoir studies are -- as we have mentioned before, we have 2 reservoir studies are ongoing. One is a company called PM Lucas. The second one is Schlumberger, both covering our 3 major areas where we have resource reported as of 31st of December 2018. Of course, the first, our northeastern Devonian gas condensate formations, the Biski-Afoninski reservoir; secondly, the northeastern Tournaisian formation, where we are producing oil out of it, and thirdly the Biski-Afoninski (inaudible) area where we have drilled a couple of (inaudible) over the past 5 years.

So we are more or less on track. We are expecting to have both studies prepared by end of September. This is the target date. We had already 3 [workshops] with both companies. So each 2 [months] is finally -- had a major breakthrough. We had one in January, one in March, one in May. And I'm seeing us on track, let's say, to have these studies in our hand end of September so in due time, let's say, to make the necessary decisions for 2020 production as well as the budgets.

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Operator [15]

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And your next question comes from the line of N. Menteshashvili from Insight Investment.

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Nikolay Menteshashvili, Insight Investment Management Limited - Credit Analyst [16]

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Just a couple of questions. First of all, regarding the northern part. Could you remind me, did you -- did the license been extended to the northern part already and basically the production from wells 41 and 42 still dependent on getting then that license extended from the government?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [17]

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Yes. We are under the extension of the model license, as I had reported already in the last call. We have obtained the mining permit for the northern area, so entire northern area. In order to start and report production, we need the license or we need this extended mining allotment incorporated into our production sharing agreement for the entire Chinarevskoye license. This has been approved by all authorities and commissions within the Ministry of Energy over the past weeks and months. The last month, we are working on the legal wording of the supplemental agreement. This has now been signed off. And since 1 week, this last supplemental agreement is on the table of the Minister, and we are expecting the signature as soon as possible.

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Nikolay Menteshashvili, Insight Investment Management Limited - Credit Analyst [18]

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And after that, you'll be able to basically...

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [19]

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And after that, we will be able to produce, to operate and to drill more wells in the northern part, yes.

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Nikolay Menteshashvili, Insight Investment Management Limited - Credit Analyst [20]

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Great. And does production guidance include the expected production from well 40 already?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [21]

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Yes.

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Nikolay Menteshashvili, Insight Investment Management Limited - Credit Analyst [22]

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Well 40 -- yes, okay. And the second question regarding the acquisition of Stepnoy Leopard. Obviously, the first 50% didn't have a significant financial effect on the company, but acquisition of the rest will have. What's the expectation on the funding of the acquisition of further 50% of potential development of the field?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [23]

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Yes. Just remind you, Mr. Richardson can answer in more detail. But in general, this is exactly one of the major objectives of the strategic review because we have to exactly organize the inventory resources of the company in a way to, on one side, being capable to develop the reserves, which we have acquired or which we are in the process of acquiring on one hand and, on the other hand, our obligations to repay our bonds starting from the year 2022 onwards. To bring both things together, we have initiated a strategic review process where we are considering all possibilities in order to ensure that we can do both things, not becoming in breach with our, one, covenants, the repayment of the bonds; and secondly, having sufficient enough cash flow available to develop as an example (inaudible). I don't know Tom if you want to add something there?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [24]

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No. No. No. that's exactly what I -- I'd also just point out that with the liquidity slide that we show in the presentation, that we'll be ending with over $100 million cash at year-end, obviously that the acquisition price of $3 million would be a significant portion of that, but it doesn't mean that we will immediately having suspend them further hundreds of millions of dollars. This is a field that has had multiple wells drilled in historically. It's been very well appraised. Therefore, there's lots of data for us to analyze. And we would also look (inaudible) appraisal program and prior to any development of that field.

So in terms of the cash outlay, over and above the purchase price, we're obviously cognizant of our cash position. We are running a strategic review process to look at all the different options we have in front of us. But it's not something that is going to put the company in a position in 2020 that we will have insufficient cash to be able to maintain this license. So I think you need to look at it in the context of the strategic review, but also in the context of the fact that there's a lot of data out there. And we can do -- the wells that we would need to drill on this field would be far cheaper than those on the Chinarevskoye field and therefore to carry out an appraisal program (inaudible) extremely expensive.

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Nikolay Menteshashvili, Insight Investment Management Limited - Credit Analyst [25]

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And just to clarify. Is there any time line by when you expect to finalize the strategic review?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [26]

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Nothing that is guided at the moment. This is open ended. We are looking to -- as I mentioned, there are a number of different options we've outlined that we're considering within the strategic review, and therefore, we want to keep this open until we have looked at each of those different options. And then we will come back and inform the market.

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Operator [27]

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And your next question comes from the line of Oleg Chistyukhin from Renaissance Capital.

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Oleg Chistyukhin, Renaissance Capital, Research Division - Research Analyst [28]

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Yes. I just have maybe one question, just one question. Can you slice the production plans for this year because I have [otherwise] confusing that well 41 is also included in your production guidance? So to reach your production guidance and what is included? Are there all of the residual wells that you're producing previously? In addition, it's well 40. Now it's well 41 and also the reactivation of these 4 wells that will bring each something like 150 BOE per day. Am I correct? Or I'm missing something.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [29]

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Kai, maybe I can just from a -- from the budget at the beginning of the year perspective, the guidance that we gave. So -- just so that everybody is clear, what we gave at the beginning of the year was a guidance based off all of the wells that were on production as of 31st of December 2018. And then in addition, obviously, there was the workover program that was -- that is always ongoing in the field site. So the production guidance is based off oil-producing wells at the end of the year of 2018 plus then ongoing workover programs.

So you take -- for instance, we had a well 45, where we had a pump in it. We had to replace that pumps. You'll always going to have ongoing throughout the year. There'll be various different workover programs that are looking to optimize existing production, maybe opening up different horizons, always challenging reservoir engineers to try to produce as much as possible throughout the year. But essentially, we take the wells at the end of [2018] a guidance from that for the average that we guided the market for 2019.

The northern wells, both 41 and 42, were excluded from our initial guidance. But obviously, today, we're able to provide, let's say, updates on 42, which is -- as Kai mentioned, which we don't expect to be commercial, that we don't expect to be adding. And on 41, as Kai said, he doesn't want to give a figure on that yet. But we -- he sees that there is a potential for some commercial flows.

The guidance we're giving is not based off the 41 or 361. We're simply continuing with the methodology we started at the beginning of the year. If we see -- as somebody else pointed out, that we saw roughly a 10% decline over H1 of 2019. If we saw a similar decline and we missed that target, clearly, we would update the market at the point in time, which we felt that we would -- if we were going to miss it, we would miss it.

But bear in mind, we have GTU3 getting completed. Therefore, we will see also some LPG production coming in or increasing, which is built into the original budget. And bear in mind that, that was considered to come into the budget in April-May time originally. So here we are, obviously, delayed in terms of the impact of that increased LPG production. But I was -- what I would say is that the 41 and 361, Kai is simply giving you the current views he has. We are not committing to any specific numbers on (inaudible) when we get, then we will inform the market as to the production that will come from 41 or 361, if they're successfully tested.

So the -- just to repeat, the guidance we're giving is on the same methodology that we gave at the beginning of the year. And it's the depletion of the existing producing wells plus the ongoing workover, which we are continually doing on all of our wells.

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Oleg Chistyukhin, Renaissance Capital, Research Division - Research Analyst [30]

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And they're really clear. And just maybe a small follow-up question. What's the approximate, I know exactly in March, of the workout wells effect, something like around 1,000 BOEs per day or something like more?

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

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I have to come back to you. I don't know exactly what the impact of the workover is.

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Operator [32]

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And your next question comes from [Konstantin Chenowov].

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Unidentified Analyst, [33]

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I've got one about the liquidity of the company. So you're guiding sort of the cash balance by the year-end at $100 million. The business is not hedging for the oil price exposures. So I guess my question is if you need to access sort of capital markets for liquidity purposes, given where sort of unsecured debt is trading now, it's probably tough to do it in unsecured format. So I guess my question is how much sort of senior secured capacity have you got if you need to raise sort of debt, which is senior to unsecured. And if you have that capacity, to which extent do you see sort of opportunities for hedging that debt?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [34]

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Okay. Kai, shall I'll take this one? So I think the -- what I want to make clear is what -- our bond covenants clearly have the ability for various different structures of secured financing. We are not currently in the market looking at putting in place additional debt.

So what I want to make clear is in answering this question, I'm not in any way implying the company is looking to raise a significant amount of secured financing. However, you will obviously note that within our bond covenants, we have the ability to raise secured financing, whether that be on the back of our products that we're selling or whether that be on the back of infrastructure we want to put in the fields. But at this stage, I want to make it clear the company is not looking to raise significant or any secured financing in order to fund the acquisition of Stepnoy Leopard or any further infrastructure.

First, we have to go step by step. I believe that we are working on bringing our costs down, generating as much cash as we can for (inaudible) products, that we're ending the year with as high a cash balance as possible to give us the most optionality in relation to the different opportunities we have in front of that -- in front of us. In addition, we're running a strategic review process. This is looking at various different options, as was mentioned when we announced the strategic review from farmouts, from looking at our infrastructure, can we do it that to this. There's various different options that we believe we have available to us, and we will explore all of these over the coming months.

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Operator [35]

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And your next question comes from the line of Ian McCall, First Geneva.

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Ian McCall;First Geneva Capital Partners;Managing Partner, [36]

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Very good to hear these developments with well 41. A question pertaining to that. What you have found thus far with Frasnian at well 41, has that affected or shaped your drilling plans that you continue to have scoped to make over the course of the rest of 2019? Has that impacted what you're planning to drill beyond well 361?

And second question, I'm assuming it'll be for Tom. When is the strategic review targeted to be finished?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [37]

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Let me start to answer the second question even if it was addressed to Tom, I think Tom answered that question already, that we have not set a fixed date to close out the strategic review. But Tom can answer later on a more detail again on the question that he'll answer during that call.

Coming back to the wells and the impact of (inaudible) well 41 on our drilling program. As you know, let's say, our entire drilling program 2019 is focused on the northern area with wells 41, 42 (inaudible) well 361 now in drilling operations. We are focusing on the northern area of the license because we are expecting at first, let's say, this revised (inaudible) on our main producing fields being the northeast Biski-Afoninski and the northeast Tournaisian, a little far from which we are getting, as I have mentioned before, the results from the studies which are ongoing, someday at the end of September. And therefore, in my view, the drilling program in the, let's say, existing proven area of reserves will not commence in year 2019. Maybe I will not have it excluded. But most likely, we are focusing on that northern area, and we will continue to focus on the northern area.

Currently, we are trying to evaluate, let's say, the results, the test results from well 41. And as I had mentioned before, well 361 is well very, very close to reach primary target. We are running to [certain first] phasing now on top of the Vorobyovski horizon. So this will take a couple of days. Then we will drill out the Vorobyovski horizon, and we will have, let's say, after a couple of days, at least the first indication how that drill of ours look like, how thick it is, how the gas flows are, what are pressure data. And once we have those results, then we will make the final decision how to continue our drilling program in the northern area in the Chinarevskoye area.

But don't expect that we are coming up, let's say, with wells in the northeastern main production areas. These will be to form what we have received the final studies from PM Lucas and Schlumberger to fill, prepare and start, announce in 2019 is very short term. So therefore, currently, we will continue to focus on the northern area.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [38]

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And Ian, I have nothing to add on top of what Kai said in terms of timing, that we've got a number of options in front of us. We've got well cost infrastructure in Northwestern Kazakhstan with all the export routes there with various different fields that we currently own or have tolling agreements with and fields that we're looking to try to tie up in the coming months.

So for us, the strategic review really needs to be extremely thorough. This infrastructure has a long lifeline, has huge value, which we don't believe is reflected in the current share price. So we need to take our time, look at all the options. And as soon as we have any conclusion to that, we will update the market.

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Operator [39]

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(Operator Instructions) Your next question comes from Rumen Ivanov, ICE Canyon.

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Rumen Ivanov, ICE Canyon LLC - Analyst [40]

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I wanted to clarify on Slide 5 where you sketched out the liquidity of the company. Has your plan for CapEx for the year changed? If I look at remaining spend on GTU3 plus drilling, you've totaled $80 million, and add that to the $65 million that you spent in the first half of the year, I mean that implies $145 million, significantly bigger amount of CapEx than what you've guided in the beginning of the year. Is that how we should think about CapEx in 2019?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [41]

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No. This is just an illustration. So the capital available to invest in drilling is just showing you what amount -- the maximum amount we could spend and still end at $100 million of closing cash. We do not anticipate to spend $59 million. But as Kai said, we just -- we want to wait firstly for the results from the northern area before we commit to further drilling in the northern area in 2019. So that $59 million is simply an illustration of the maximum amount we can spend in order to still end at $100 million. So I think it'd be fair to say we're unlikely to spent anywhere near that $59 million in the second half 2019 and therefore end with more than $100 million of cash.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [42]

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And just adding this. If you look, let's say, for the current well cost, which we are seeing in well 41, 42 as well as in well 361 today, we have made a significant progress in reducing our well costs. All the wells if we run, let's say, conform to fashion, always looking, let's say, at levels between $12 million and $16 million for such deep wells. We are now, for all the wells below USD 10 million. And therefore, this just underline, let's say, that the $59 million is just an illustration how much money you potentially could spend in order still to reach a cash -- closing cash balance by the end of the year of $100 million. But for sure, we will not spend this $59 million in the remaining months of the year 2019.

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Rumen Ivanov, ICE Canyon LLC - Analyst [43]

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Okay. Getting to this well cost, so if I look at $65 million of CapEx first half of the year, of that $50 million presumably going to GTU3, implies $50 million, $50 million, 5-0, spend on drilling. I mean how do you reconcile that with low drilling costs when only 2 wells have actually been drilled in the first half of the year?

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

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No. So from a CapEx perspective, in order to roughly walk you through the first half of 2019, so you have about $20 million spent on GTU3. You have roughly speaking on all the drilling that we've done, workover, all of the drilling completions, flowlines, everything you need in order to drill and then test the wells, you have roughly speaking just under $30 million. And then we have bought on -- I forget we have completed both on an upgraded self-recovery unit. We've implemented a low-pressure system. There's been some small pieces of engine (inaudible) done at field site. So the remaining balance is related to small items across the field, operational part of the field that makes up the total capital expenditures of the first half of 2019.

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Rumen Ivanov, ICE Canyon LLC - Analyst [45]

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Okay. That's helpful. And final question. I know that selling and transportation costs declined materially in the second quarter versus the first quarter, and that was almost $1.5 per BOE. Is that -- should we think about selling and transportation costs at the same level that we saw in Q2, Tom? Is that how we should think about this going forward? Or is there a one-off effect in that number?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [46]

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Sorry, Kai, you go.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [47]

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No. No. Please go ahead, go ahead, go ahead.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [48]

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I'm just going to say on sales and transportation, you've always got to take into account that on LPG, we are sometimes paying for the transportation ourselves and then sometimes selling FCA routes. In addition, we're also varying the amount of volumes that are sold. It's not completely constant when we're selling domestic crude oil versus for export. So it's -- there, you will see some fluctuations in terms of the sales, so the cost per BOE of sales volume. So I would take a blended rate, if I was you between, Q1 and Q2. So the H1 average, in my mind, is a fair number to take for the second half of the year for sales and transport costs.

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Operator [49]

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And your next question comes from the line of Alexander Martynenko from ICU.

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Alexander Martynenko, Investment Capital Ukraine LLC, Research Division - Head of Corporate Research [50]

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And my question is what are management plans with regards to your bonds maturing in 2022. And are there any plans to consider restructuring in the near future?

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [51]

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Kai, can I take that one?

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

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Please, please, please, yes.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [53]

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So we're obviously well aware that in July of 2022, we have $725 million of bonds maturing, and we're obviously very cognizant of the fact that or where these bonds are currently trading is implying a distress level on the debts of Nostrum. And in addition, obviously, we're aware that one of the rating agencies have us now in CCC territory in terms of the rating. So these points are not lost on us.

But I think the fact that we have the maturity in July of 2022 and we are undergoing a strategic review at the moment and one of the points we stressed in the release when we announced the strategic review was exactly to look at the position, the capital position of Nostrum, and to that, we'll see what's the best way forward in order to create stakeholder value (inaudible) along the way from talking about restructurings. I believe that this company has world-class infrastructure that is extremely valuable in an area that has -- that is rich in hydrocarbons, and we have signed up one tolling agreement with UOG. We have [Stepnoy Leopard] licenses. We have our Chinarevskoye license -- Trident licenses, and there are other options, we believe, in the area.

So when it comes to talking about restructuring and when a maturity is in July of 2022, that's still quite some way off. And whilst I appreciate the market is often speculating about this and has been for the last 2 years in terms of our liquidity position, I believe we've demonstrated each year that we've ended the year with $100 million of cash. And we are going through the strategic review now in order to look at all the options we have in front of us and try to maximize the value of the assets that we own.

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Operator [54]

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And your next question comes from the line of Dmitry Sentchoukov, Wellington Management.

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Dmitry Sentchoukov;Wellington Management International Ltd.;Analyst, [55]

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I've got a couple of questions. Your decline in production Q2 was so material, about 10% versus decline of just 1% of Q1. Has anything happened that -- which resulted (inaudible) decline with just one quarter? And also how much hydrocarbon do you produce now?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [56]

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I'll be very open. I think we answered all those questions in detail during the call. So let's not spend too much time to repeat this. Actual production is -- one second. I can -- I need a second to give to you, just to avoid that I am giving you a wrong figure. But actual production is close to the production we had seen end of Q2 2019. There's no significant decline in production over the past 13 weeks.

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

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I would just point out, Kai, that in Q2, we did have the shutdown of GTU1 and 2. So when you're looking at sales volumes and you're all -- I appreciate you trying to calculate all of these things. You have to take into account those roughly 7 days of downtime of GTU1 and 2. So your Q2 figures will all be skewed slightly by this fact.

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Operator [58]

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Your next question comes from the line of [Konstantin Chenowov].

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Unidentified Analyst, [59]

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Just a quick sort of follow-up, guys, if I may. When you think about the capital deployment, so when are you going to consider exploration CapEx versus, say, sort of buying back bonds and committed investments basket and your [Board] allows for that? How do you think about it? Because it feels like given sorts of the bond's trading levels, it might make more sense to kind of deploy capital buying back bonds than being exploration CapEx. Have you thought about it? If you could provide any comments would be helpful.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [60]

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Yes. We are permanently thinking about all opportunities. Therefore, again, we have initiated that strategic review process. And as part of that strategic review process, all the different considerations are getting analyzed. And then as Tom has mentioned, that hopefully once we are coming to a conclusion, we will report this to the market. But today, we are not yet there.

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Operator [61]

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And your next question comes from the line of Anton Rozanov, Argentem Creek Partners.

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Anton Rozanov;Argentem Creek Partners;Analyst, [62]

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Tom, the question to you, I guess. You mentioned that you are working on a low-pressure system. Can you explain in more detail what that is? And to that point, how's the -- what's the profile of the Chinarevskoye, the Biski-Afoninski reservoirs in terms of decline in pressure? And how close is it to bubble-point pressure?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [63]

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Just starting to answer your first question. Low-pressure system, this is something that we initiated already a couple of years ago. And last year, we built and commissioned 3 compressors, different compressors, which are allowing us to reduce the wellhead flowing pressure from 45 -- or 42 to 45 bars down to a level of 15 to 18 bars. So this finally -- I don't know how familiar you are with oil and gas business. Once you are, let's say, capable to lower your wellhead pressure, you're adding a different production or reserves from the wells which are producing.

Our usual system was built up in a way. Let's say that we had the inlet pressure of our gas treatment units is at the 40 atmospheres, 40 bars. And therefore, as I said, the wellhead pressure had to be at the level of 42, 45 bars. So we're taking the pressure loss into account. Some of the wellheads [tilt the] inlet of the gas treatment units, you need such wellhead pressure. By reducing the wellhead pressure, you can produce more, and you can produce the remaining resource asset. But when you require additional compressor capacities to bring the pressure, the wellhead pressure, as an example, from 12 bars back to 40 bars, as an inlet pressure of the gas treatment units, this is what we are calling the low-pressure system. It would allow us to transfer or to increase, let's say, the production of -- or current valves in comparison to how the field development originally was in line.

Our aim for the next years is to permanently look at this. Most likely, we will come up with a budget 2020 of adding 1 or 2 more low-pressure compressors as we would like slowly but permanently to transfer all our wells from the northeastern Biski-Afoninski reservoir under the low-pressure system, so finally reducing the wellhead pressure.

Now I forgot, Anton, your second question. Can you repeat (inaudible) your second question, please?

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Anton Rozanov;Argentem Creek Partners;Analyst, [64]

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The question is how fast is the reservoir pressure drilling?

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [65]

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Yes. To think about pressure decline is as our expectation. There is nothing special happened during the year 2019. We have one well in gas condensate, but this I reported as well during the previous calls, which is our 222, where we are seeing slight but permanent increase in water. All the other wells performing, yes, as it was predicted. As well, 222 was predicted to see this increased water cut over the time. So therefore, as of today, for the past 6 months, we don't see any significant decline and pressure drop. The point is that therefore, of course, figures may always confuse people.

We had a couple of wells, like wells 703, the 219, just perforated tubings in what we are calling as a little skew -- little bar which is just very shallow at a depth of 2,700 meters. Those 2 wells have partly produced in the beginning of Q1 -- or during Q1 2019. Certainly there's no volumes, we are currently analyzing this production data which we have obtained during that period. And hopefully, we'll come up, let's say, with a better plan in the future how we can access that reserves. But of course, in the summary production, you see this as a decline rate. But it would take, let's say, this additional production or test production for those 2 wells out, the real decline rate would have been much, much smaller. So therefore, again, there is no major event which is not -- and so not expected in relation to decline rates or pressure drops. Currently, fortunately, year 2019, everything has developed as it was predicted end of 2018.

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Operator [66]

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Thank you. There are no further questions. Please continue.

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Thomas Richardson, Nostrum Oil & Gas PLC - CFO & Director [67]

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Okay. Well, thank you very much, everybody, for joining Nostrum's First Half 2019 Results Call, and we look forward to speaking with you on the Q3 results call.

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Kai-Uwe Kessel, Nostrum Oil & Gas PLC - CEO & Executive Director [68]

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[Thank you] very much for everybody attending and not getting a single question [on this] Q3. It shows everybody has understood that this is almost done. Thank you very much. All the best. Bye.

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Operator [69]

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