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Good afternoon, ladies and gentlemen, and thank you for standing by. Welcome to today's Q1 2019 financial results conference call. [Operator Instructions] I must advise you that this conference is being recorded today on Tuesday, the 21st of May 2019.I would now like to hand the conference over to opening speaker for today, Mr. Tom Richardson. Please go ahead, sir.
Thank you. Good afternoon, everybody, or good morning to Nostrum's Q1 2019 financial results. The format will be the same as usual, where I will run through the presentation which you can find on our website on the results, presentation link, and then we will move on to Q&A, and I'm joined by Kai who will answer any questions that you might have following the presentation.So moving to Slide 2 of the presentation. This is a quick run through of the summary high-level financial and operational points over Q1 of 2019. As we had published in our operational update, we had revenue of $95 million, and we had sales volumes of 31,621 BOEs per day. The main points that I would like to state here is that from a sales volumes perspective, we have again shown that we have stabilized the production levels and stabilized the sales volumes levels in comparison to Q3 and Q4 of 2018. And also if you look quarter-on-quarter versus 2018 Q1, we are again showing a significant increase versus the Q1 2018 number of 30,874. So overall, our message here that we want to convey is that production is stable and we are in line to meet our target guidance of 28,000 sales volumes and 30,000 production of the treatment volumes on the basis that this is all wells that were online as of the 31st of December 2018, just naturally declining and producing throughout the year of 2019. So nothing has changed here from what we have guided back in November. This is all in line with expectations. And based off the increasing oil price during the quarter, we were able to realize a revenue of $95.4 million, broadly in line with where we were in Q1 of 2018. But demonstrating of 31,600 of sales volumes, we can generate close to $100 million of revenue at current oil prices.As a result of that revenue and also a strong quarter in terms of further cost reductions in comparison to Q1 of 2018, we've remained with a healthy EBITDA margin of 61.5% and EBITDA itself of $58.7 million. So the company has generated again good amount of operating cash flow and maintaining a strong EBITDA margin with costs coming down, which I will address later in the presentation.The cash position of $75.7 million was lower than some people may have expected if you're modeling a steady state from an inventory and receivables perspective. However, we have sold -- or just to give you some background, in January, we were unable to sell any condensate cargo due to bad weather in the Port of Taman, which prevented us from any cargoes being picked up at the port. As a result, the -- in March, we sold 2 cargoes. However, we have not received the cash from either of those cargoes of condensate. That's roughly speaking just over $30 million worth of receivables therefore on our balance sheet that had not hit our cash accounts but are obviously coming through in revenue.In addition, we have 2 cargoes, for want of a better word, of dry gas. So 2 months' worth of supply of dry gas into the pipeline, which we had made, which had not been paid as of the end of March. Both of these items, both the condensate cargoes and the dry gas payments, have all been unwound. So that's, roughly speaking, in total, about over $40 million of receivable balance, which has been -- that can be unwound. And as of today, we're sitting with over $110 million worth of cash. So this is something that has happened. If you look through 2018, due to the fact that we are selling on average around 1 cargo of condensate per month. If you start off from bad weather at the Port of Taman and the boat can't come in to pick it up, then inevitably, it rolls into the next month. And if this happens to be at month end, it has an impact on whether you can book revenue if we haven't been able to sell it and it also have an impact in terms of when the cash is then coming in. If it's right after month end that we are selling it, it's unlikely we receive the cash in the 1 or 2 days prior to the end of the quarter. So please, on this point, just note that the condensate is typically the one that is varying or leading to the increase and decrease of our cash position relative to forecast. But from a pure business perspective, sales volumes and production, this is all in line with our expectations and revenue included all of the sales of the condensate and dry gas. On the Schlumberger analysis, which has been well covered, this is an ongoing analysis that continued to work, and we expect their findings to come in Q3 of 2019, which will just help us to be able to then determine the drilling program for 2020. On GTU3, we have mechanical completion that we announced in December of 2018, and we also expect first fuel gas into the plant during Q2. And any questions on -- more detailed questions on commissioning, please address those to Kai during the Q&A. In addition, as is well documented by a number of our analysts, we have 2 Northern wells which are now nearing completion: one which is at the top of the reservoir; and one which we have drilled through the reservoirs and are about to start testing. And we have plans now to drill at least 4 more wells during 2019.Moving to Slide 3. Here, it's just a repetition of the top on the sales volumes. So you can see here how the increase or stabilization in production has occurred. But more importantly, at the bottom part of the slide, there is information in relation to the operating costs and how we have continued to try to bring them under control. You will see here that both G&A and OpEx and transportation are all, on the BOE basis, coming low. And now some of that is driven obviously by the fact that we have higher sales volumes that will on a BOE basis and a steady state of nominal amounts of G&A and OpEx and transport, you therefore have lower barrel amounts. But there have been actual cost savings realized since 2018 through headcount reductions, through a reduction in the number of service contracts at field sites and also through optimization of transport and destinations where we sell our products to. So there has been some real cost savings in the business here over the last 12 months. And we hope that this will be maintained quarter-on-quarter during 2019 to be able to bring both G&A and OpEx slightly lower over the course of the year.This will result in $214 million of operating cash flow during the year 2018. One point to note on the operating cash flow front is that obviously we have had to now start implementing as of Q1 of 2019 IFRS 16. This is meant that there's been roughly $4.7 million increase in financing that you'll see in the cash flow statement. Roughly half of this is in relation to contracts in relation to drilling, and then half of it is in relation to transportation contracts. So that will come in through -- previously coming through in the -- under the operational expenditures. So this, in the event that we haven't had IFRS 16, you would have seen a slight decrease in the operating cash flow figure. But this is a very immaterial amount. We are not a business that has many leases. It's really just our transportation on the railcar side and then drilling rigs with [indiscernible].Moving to Slide 4. I've mentioned from the balance sheet perspective the reason why our cash flows at the end of the quarter's at $75.7 million. And I'd just like to reiterate, this is now back above $100 million. And also please bear in mind that during Q1, we paid $43 million worth of interest approximately; and during Q2, we don't pay any interest. That's both -- because of the way that our coupons come due. They come in both Q1 and in Q3. So again, you see slightly lumpy cash out due to financing costs during Q1 and Q3; and during Q2 and Q4, we should be building cash. So I hope that during the course of Q2, with oil prices where they are, above $70, that we will be able to continue to build that cash position over the next month or with the end of May and during June.On the hedging side, many people have asked why we are not hedging with oil prices where they are. We continue to assess the market. Please bear in mind that we have paid away during 2018 approximately $13 million for the hedge, which we never got any benefit from. We are also an oil and gas company. We -- therefore, we are taking certain risks in relation to the commodities which we sell. And we have a mixture of gas and liquids. So not all of our products are related to the oil price. And if we see the opportunity to do something which we believe makes sense for the company, then we will analyze it. But at this stage, we continue to assess given our view that we don't believe that the cost of hedging in the current market and the prices that we can obtain make good sense for us to enter into one. However, we will continue to look at that on a weekly and monthly basis.From a cash flow generation perspective, we remain with EBITDA margins over 60% after further cost cutting. We will continue to try to keep them at this level. Our target is always to have them above 50%, and for the last, I think, 2 years, we've been able to hold it above 60%. Obviously, if we have to further increase this in, say, a ramp-up in the drilling program and need to deploy more people to field site in order to grow production, then we may have to see some increasing costs. We are doing everything though to keep a lid on our costs during 2019 as we have just the 2 rigs currently operating in the field. But based on the results, once we've been able to test the current wells in the North, we will obviously have to review what the plan is for the remainder of 2019 and looking forward, most importantly, into 2020.So from a drilling perspective, we still have those 2 rigs at field site. We look forward to being able to test both those wells, and we are moving the 2 rigs now to be able to, firstly, address some of the Bashkirian crude oil as well as drill a water injector. And then we make plans to drill one side of the well also in the North with one of the rigs. So we are -- I think one of those rigs has already been moved, and we will look to move another one in the coming weeks once we have completed drilling on one of the Northern wells.Moving then to Slide 5. This is our standard liquidity position slide, which demonstrates that at $60 oil with the budgeted and forecast sales volumes for this year of 28,000 along with the unwind of the receivable balance which I just went through, you can see here that we can easily end the year with over $100 million of cash, assuming that we would spend still $75 million on drilling and other items of CapEx at field sites. This also includes the one remaining coupon that gets paid in Q3 of $43 million and the remaining commissioning costs on GTU3 of $23 million. Please bear in mind, this is obviously a $60 oil. If you were to assume then a steady state of $70 oil, then you can assume that we have roughly $15 million more come the end of the year of closing cash, assuming that there is no lumpy receivable balance at the end of 2019. And just on the receivable point, we are -- given that the condensate cargoes are sold to Vitol -- this is a well-known trading company. It's a extremely good credit. So should we wish to put in place lines where we're able to have cash on our balance sheet more quickly, whether that be through LCs or lines of credit, that's something that we have access to should we need to. At this stage, we have no other debt or LCs outstanding, and we just wait to get paid after 30 days. However, it's something that the company has access to and is permitted to be able to raise under our own bond covenants. So it's not something that would be an issue should we have the requirement to go and seek financing to address the 30-day payment period on the condensate cargoes.Moving to Slide 6. This is our standard slide in order to try to explain what is a field with multiple reservoirs and multiple segments and different geographic areas to the fields which we try to group. The area where the 2 drilling rigs have been is in the Northern area, looking at the Frasnian, Vorobyovski and Mullinski reservoirs. I will allow Kai to address this in any Q&A in relation to those wells later on, on the call. Otherwise, we don't have rigs currently deployed in the Biski North East, and there's nothing in the South and nothing currently in the West. So moving to Slide 7. This is just again to reiterate that we have the Chinarevskoye field as well as our 3 Trident licenses. We also have the Ural Oil & Gas agreement, which is ongoing in terms of working on the FEED study and appointing contractors in order to link up roughly a, I think, what is no more than 15 kilometers between the Ural Oil & Gas field and the Chinarevskoye infrastructure. And this we look forward to receiving gas in Q4 of 2020 on terms which are extremely cash generative to Nostrum.In addition, we have obviously our 3 Trident fields. And we have or close to completion now on commissioning of GTU3, which really allows us to be able to [indiscernible] as much of that infrastructure as possible over the coming years.Moving to Slide 8, the key focus areas for 2019. Everything that we are doing today is trying to focus on making sure that we can deliver on our base case production from those wells that are -- that were online as of the 31st of December and then also look to bring on additional appraisal wells during the year of 2019. We're firstly drilling in the Northern area, where we have our successful wells, Well 40 and Well 724. These wells continue to perform extremely well, and therefore, we want to be able to uncover what we believe to be a promising area in the northern part of the field. And therefore -- so the focus on production is really key for Nostrum over the coming quarters and looking forward over the years in order to build production and fully utilize our infrastructure. In addition though, we will not lose sight of the cost base. As you've seen during Q1, costs have come down, and we continue to make sure that we are looking at all areas of the company in order to try to make sure that we are spending our money wisely and carefully. But if we need to increase drilling and then build production, we will not hesitate to do this in order to further deliver production ramp up over the coming years.Lastly, our infrastructure, which is coming close to commissioning of GTU3. It's critical that we also are looking at additional ways of bringing in gas in the same way that we have struck agreements with UOG in order to try to utilize all of the infrastructure we have at field site. And we are constantly looking at all of the different options we have in the region, and we will update the market if we find any similar agreements to UOG. That concludes the presentation on the online. I now suggest we move to Q&A.
[Operator Instructions] We'll now take our first question. Your first question comes from the line of Zafar Nazim from JPMorgan.
Just a couple of questions, if I may. I was wondering if you can give us some further granularity on your drilling program in the Northern area, or perhaps you can tell us what is the next update that you will provide us and when should we expect to get the updates, in particular, with relation -- in relation to Wells 41 and 42? And also I don't know if you have any early results on any of these wells, if there's anything to share. And then a related question on Well #40, can you remind us what the flow rate there is today?
Yes, I can try to answer your question. Tom, can you just check if my -- if everybody can understand me, or is there -- if I'm understandable during this call?
Yes, we can hear you.
Okay, fine, excellent. So then let's come back to your questions. Let's say, overall drilling program in the North, as Tom has already summarized, we have made last year 2 discoveries in the Wells 224 and 40. 224 was targeting the Mullinski reservoir. And it's -- since -- that's now more than 1 year in test production for the Mullinski reservoir. And Well 40 has targeted an upper reservoir, which lies just on top of the Mullinski reservoir. We are calling it Frasnian reservoir. You may call it as well, for simplicity, Upper Devonian reservoir. So the current situation on the 40 is we just do the shutdown of the gas treatment units beginning of May. We had a 3.5-day shutdown for compressor maintenance works in GTU1 and 2 in the beginning of May. We closed Well 40 and made the pressure build up. And as the pressure builds up, we make a new estimation of the potential. So first of all, the flow rate is still at extremely high level. Now the well is again almost a year under test production, and we are seeing still a flow rate on the liquid side which is about 150 cubic meters of liquid hydrocarbons per day. And the most important thing is that we have seen a significantly lower than originally expected drop in the pressure since the start-up of production. So therefore, we can now see, let's say, that we have a producible volume linked just to Well 40 in the range of roughly 10 million barrels of oil equivalent. So therefore, this is a very promising result.Now coming back to the 2 wells and we would be capable to announce results. First of all, I must say we have now from a drilling perspective completed both wells, Well 41 and 42. Well 42, already roughly 2 weeks ago. Well 41, just last night. So both wells confirming the discoveries which we have made in Well 40 and 724, very promising results. We have decided finally those wells to deepen till the third target reservoir in the Northern area, which is the Vorobyovski reservoir. I just can say that tonight, let's say, we have started the test of the Vorobyovski reservoir in Well 42, which originally we were not expecting in that area. We've seen now the gas inflow in Well 42. Of course, I have no metering and separators yet. So we are in the phase that we are cleaning out the wells. So I would expect, let's say, that within the next couple of days, we can already have, let's say, reliable data on the flow rates from the Vorobyovski reservoir. But overall, it's a very, very promising result. And it seems to me that in the third reservoir, on top of -- or in this Northern area, it seems to be hydrocarbon bearing.The plan is now, let's say, to test the well, let's say, from the bottom to the top. We will need, let's say, roughly 2 weeks to test the Vorobyovski reservoir. Once this is done, we will move to a higher reservoir, which is the carbonate section of the Frasnian reservoir where we have seen good carbonates and very good cash flows during drilling of more than 30 meters of thickness. And once this is done, we will finally test the upper part, which is our main target horizon for Well 42. This is the transient sandstone which we are currently in production in Well 40. All the information which we have from not logging and the logging after we have completed the drilling operations show that we have the same reservoir as well found in Well 42.Well 41 is roughly 2 weeks behind because it was founded later than Well 42. So we have drilled, first of all, of course, through the same target reservoir like in Well 40 and 42, to hit Upper Frasnian sandstones. We have confirmed in a DST test, or drill stem test on Well 41. On that section, we confirmed that reservoir -- the reservoir pressure is similar to Well 40, so about 700 bars hydrocarbon bearing, we got gas condensate inflow and liquid into the well. And then we decided to deepen the well down to the Vorobyovski reservoir. As I said, this has occurred last night. We have seen heavy gas shows especially in the Vorobyovski reservoir, where we had finally over the last 24 hours increased the mud rate to control the well. So we have very good expectation that the Vorobyovski reservoir is indeed in this entire Northern area gas bearing. And with the next coming well, the Well 361, to which the rig of -- from Well 41 will be moved as soon as we have installed the final completion of Well 41. This has a very good expectation that the entire Vorobyovski reservoir has at first sandstones with good reservoir properties and is filled in with hydrocarbons.Now from a time perspective, I would assume, let's say, that we will need time till end of June to test all the 3 reservoirs in this -- both of those wells and to come up then in my view, let's say, what we are speaking about the operational update on Q1 -- sorry, not on Q1. Q1 and Q2, so the first half year 2019. At that time, we can provide, let's say, more detailed information on the test results of those wells and the underlying results. What we are today estimating, but this is of course before we're having -- finally testing the Well 41 and 42, is that we are seeing now with Well 42 and 40 -- 42, the fourth well in row in the Northern area, which has been drilled successfully, having already seen the hydrocarbons in those wells now flowing on top of Well 40 and Well 724. So we're assuming, let's say, that there's an overall potential in this Northern area for the entire Upper Devonian formation which is somewhere between 50 million and maybe 100 million BOEs. So sufficient enough, different reserves, which would allow us, let's say, in worst case, to replace the Biski reserves in the West in case we will not find any commercial development concept for those reserves in the West.On the drilling program by itself, we are currently considering all options. As I said, we will now complete the tests of Well 41 and 42. And there is indeed, let's say, a possibility that we will recall the third rig, which is on cold stack in the field for Q4 2019 into operations, so to continue drilling program into the North. I think so our activities for the year 2019 for full with the 2 rigs which we have currently under operations after the wells which Tom Richardson has mentioned, which we will now drill for water injection well for the Tournaisian reservoir as well as a sidetrack for Bashkirian oil reservoir to increase short-term production. We will then go back to the Northern area. And then most likely, we will come up with a proposal, where we will propose either 2 or 3 additional wells in the Northern area, which then can be immediately transferred into production wells, as we had in well -- and then I will stop my explanations here, made good progress on the extension of that Northern license area. If you remember from our last call, this was the pending issue. In the meantime, we could get our so-called extended field development or unique field development plan approved by the state committee for approval of development plan in Nursultan. So now all the administrative points have been fully completed to get this Northern part of the license area extended. The well program foresees up to 22 wells to be drilled in that Northern area. And we are now in the administrative process, and I'm expecting here that this will take 3 to 4 weeks to sign the supplementary agreement to the Chinarevskoye field [indiscernible] that then would allow us -- or would include the site expansion of the Northern license area under the [ Kazakh government ].
Excellent. And just, sorry, one question. So can you just give us an -- your average production during the first quarter was 32,646. What's the -- can you give us an updated number for year-to-date production?
For year-to-date, again, I don't like to speculate. Now as you know, let's say, in the figures and then Mr. Richardson has said, our year -- average forecast guidance which we have given to the market is 28,000 BOEs per day. This takes into account that we have not taken any of the new wells which we are currently drilling in this production forecast. I know that we have been heavily criticized, let's say, for not providing guidance for the year 2019 as well as for long term. But you see now with the Wells 41 and 42, that is indeed not so easy. First of all, again, I believe we have -- we will see a great story, a great success out of Well 41 and 42. But we have, let's say, to test those wells for at least 6 weeks I would say. Each of the 3 target reservoirs seems to be hydrocarbon bearing, and we need at least 2 weeks for each of the reservoirs.So there will be always an interim -- intermittent production on it but not a continuous production which you can now already calculate exactly. So therefore, I would like to ask you for your understanding, let's say, that it is my strategy, let's say, to come up with guidance for the year 2019 as well as maybe with some more detailed guidance for the year 2020 during the next call, which will happen a few months from now.Then I have the test results of Wells 41 and 42 available, I will have, let's say, an internal reserve estimation and production forecast made, and we will have then as well decide how our final drilling program for the year 2019 will look like. And then it becomes much, much more reliable, let's say, to provide you with the guidance. So far, please use what has been presented in our presentation.
Okay. Would you be able to share with us what the -- if you ignore the Northern area, can you -- would you be able to share with us what's the current production in the Northeastern area of Biski?
Sorry. I have not completely understood which production you are referring to now.
So I mean, so let's ignore the Northern area wells, the Well #40. But what about the rest of the -- your production from Northeast. What's the production? What's the current production there?
Yes, this is not -- I don't have statistics now here because we have a couple of more wells, which are producing out of the Northeast at least on an interim basis. There are, as an example, 2 wells which we have used, old wells which we drilled in the past in the Western area, the Wells 219 and 703. We have perforated for the Vorobyovski horizon. This is the most shallow horizon where we are seeing hydrocarbons. Those wells have shown, let's say, that the Vorobyovski horizon contains or we have seen net base between 10 and 20 meters net thicknesses of the Vorobyovski reservoir. We are currently producing those wells on relatively small rates but with gas condensate. And so I have just, let's say, a mixed information on Well 40, 724, as well as Wells 219, 703, which are all producing currently through 1 system. And here we have a daily production, which is roughly [ 3,000 ] BOEs and the rest is then for the Tournaisian wells and for the Biski North Eastern wells.
Your next question comes from the line of Alexandra Baksheeva from Segetia Ltd.
I'd like to ask a question why company is not seriously considering to buy back some bonds even partially given that you have cash. Because this way, you would reduce your debt, you would open up to capital markets and pretty much paves the way for the next raise as you definitely need to raise more money to finance any further drilling and production increase that has to happen, say, next year.
Yes. Maybe I can answer it, and Tom, you can add some of your comments. So the main comment is why we are not doing it, we are now preserving our money for heavy drilling programs, not just in the Northern area, let's say, second half of year 2019 and in 2020 and the following years but as well in our main production areas. If you remember, let's say, we are working together with Schlumberger as well as with PM Lucas. So 2 independent reservoir engineers providing for us an update of our dynamic models of our main production reservoirs. We have currently decided not to drill new wells till we are getting from both studies, let's say, a better confirmation of our internal models giving us the information where exactly shall we drill in order to drill them with a high possibility of success. But what we are overall estimating is a significant increase of our drilling activities over the next weeks and months as we speak, and then, we believe, that there's a much better use of our internal cash flow to spend this amount in drilling program in areas where we can have very good expectation on future production and grow our future production than buy our bonds back. This is my general statement, but now maybe Tom can add some thoughts to it.
Nothing really to say on top of that. I think that we consider all options with our cash in our balance sheet, and we're trying to preserve it, as Kai said, in order to be able to deploy it into the field, which will allow us to grow value much more quickly than -- as soon as you launch a bond buyback, often the prices go up anyway, and the amount we could buy back now will be relatively immaterial in the context of our total debt. So we are always looking and discussing various different options with our cash flow, always analyzing those options. But at this stage, it doesn't make sense to deploy the cash that we have on our balance sheet when we have looking forward a larger drilling program to be able to deliver over the coming months and years.
Your next question comes from the line of Alexander Burgansky from Renaissance Capital.
I have 2 questions, if I may. So the first one, did I catch correctly when Kai was answering the previous question, that there was some maintenance in the second quarter? And if that is the case then, will there be an effect on the second quarter production? Or shall we expect that the second quarter also will be totally in line with your full year guidance? So that's question #1. And the second question #2 is on the export duty. Over the last couple of quarters, it was quite difficult to precisely forecast the amount of export duty that you pay. So can you please remind us of where -- when this export duty is charged? And what do you think is the best way to estimate that going forward, maybe some estimate of the volume on which that export duty is acquired.
Yes. I can answer those questions, and maybe Tom can add something on the export duty. Coming back to the maintenance, [indiscernible], we had gas treatment unit 1 and 2 general maintenance and shutdown in the beginning of May. We finally had to close both trains to allow -- one after the next, to allow, let's say, to perform a maintenance of the compressors, which had to undergo the 8,000-hour maintenance work. That was in deep. Let's say, if you take the overall impact for this -- during that maintenance, we, let's say, in brackets, lost production of roughly 25,000 BOEs. So this means, let's say, average over the month of May roughly 1,000 BOE per day less than we had in the previous months. But this is already included in our guidance which we have given for the year 2019, average annual production of 28,000 BOEs. So there's nothing on top which we shall deduct because the impact on the shutdown of the gas treatment unit is already included in this calculation.Export duty is a little bit more complicated. As you know, based on Kazakh law, the export duty depends on the international oil price. So it's linked to Dated Brent. So we have always, let's say, to calculate this export duty in relation to Dated Brent. Currently, we are paying, in my view, average Q1 was roughly USD 60 a tonne of export duty. But Tom, please.
Yes. So the best way here, Alex, to look at it is the payment terms are based off the preceding months' average Brent price. So in order to, in my mind, best model this, if you are calculating the Brent price and then multiplying it, let's say, into tonnes and it's anything below -- I think, it's $65 or $60 a tonne, but now we're averaging towards the end of the quarter and for May above $70, then we're going to be around -- I think we're going to be around $70 a tonne. So we can provide you with the BOE equivalent of our production in oil and gas. And then you can simply multiply that by the average oil prices of the month to be able to calculate then the amounts that we paid in export duty. So we will -- we can send you that calculation to be able to make that an easy one for you going forward.
Is it applied to the -- what percent of your oil there is exported, that is subject to the export duty, is it 100% of it?
85%. No, 85% is exported.
Your next question comes from the line of Stephane Foucaud from GMP.
Two questions from me, should be quite straightforward. The first one, Kai, you mentioned that Well 40, you expect it will recover 10 million barrels over the life of the well? It would be great if you could confirm that, continued 1 well in that to realize we'll need to recover 10 million barrels. And second question for Tom. I was looking at the transportation cost, and I was -- in my model, I was having them a bit lower given the recent quantification with the pipeline and so forth. So I was wondering whether you could comment on why those transportation costs not dropping more. There seems to be an increased marketing component of that, so a bit more color on this would be great.
Okay. Let me answer the first question, and Tom then can reply on the second question regarding the transportation cost. On Well 40, what I said was, let's say, that during a pressure build up, you can fairly calculate the volumes which are directly connected to the wells. So in case we'd have unlimited series of finds, you can indeed produce out of those wells roughly 10 million BOEs of hydrocarbons. Will we do so? Most likely not. We will most likely -- let's say, our general argument, let's say, is that we can drill wells, maybe profitable at 60 years with the Brent price scenarios as long as they are, let's say, with an overall production of 1.5 million, 2.5 million barrels. It depends if these are more liquid wells or more gaseous wells. So therefore, I'm today seeing that -- out of Well 40, that we have at least the potential to drill 4 to 5 additional production wells close by the area of Well 40. And this is now proved, let's say, by this long-term cash of Well 40 that we have already today, let's say, connected reserves to that well. So the risk, let's say, of future wells in the vicinity of Well 40 is extremely low.
So to recap, the 10 million barrels of volume connected to well, this is -- we are talking about recoverable volume and that will probably require to produce commercially more than 1 well, probably, what, 2 or 3 something like that?
Yes, that's right. Let's say, we are currently estimating between 1.5 million and 2.5 million barrels per well as the threshold in order to make wells profitable. So therefore, we'll keep it on the exact, let's say, composition of the hydrocarbons, it's more liquid or it's more gaseous. Well 40, as you know, is significantly more liquid than other wells that we had seen before. This is from a liquid composition, the highest content of liquids which we have seen. So therefore, I would rather say on top of Well 40, you can fairly say 4 to 5 additional wells can be drilled in this Northern area to produce that 10 million barrels of reserves, which we have already proved finally with this threshold we had accessed in Well 40, yes.
Yes. And lastly, still on that well. The 10 million connected volume, that will be coming mostly from the shallower only zone or across the 3?
No, no. This is just from the upper -- from the very upper.
Just the upper one, okay.
And then Stephane, on transport cost, it's probably easier that you send me your assumptions, so that I can then update them. I don't know if there's a marketing fees attached to the dry gas sales. But I'm not sure what you're assuming on LPG transportation, crude oil and condensate. So please send us through your assumptions, and we can update them.
Your next question comes from the line [ Katie Panscarver ] from [ Telemach ].
I have 2. The first one is on the sidetrack in the Bashkirian reservoir. It seemed to me that you said that you are not going to drill in the Northeast area until you get the report from Schlumberger. Is it -- is this sidetrack in line with that view? And the second question, I know you already tried to explain the economics of Ural's oil and gas processing, but could you please outline it once again? Just trying to get an idea how should we think about additional EBITDA to be generated from those volumes from, I don't know, 2021 and onwards.
Okay. Let me answer the question on the sidetrack of Bashkirian. Just to come back, let's say, to what we have cited. We have -- as I have said before, we have awarded different figures of our models to 2 independent engineers, one being Schlumberger, the second one being PM Lucas, for 3 reservoirs, our current 3 target reservoirs, which is Tournaisian Northeast, there's Biski North East and there is Biski West reservoir. All the other reservoirs are not scope of this dynamic reservoir simulations which we are performing with Schlumberger and PM Lucas at the moment. Therefore, now coming to your question, in deep well, the sidetrack into the Bashkirian deposit is located in the northeastern part, but it's not in an area where we are waiting, let's say, for the dynamic models as I have now explained it. So the Bashkirian model, the Bashkirian reservoir is not part of that model. The Well 52 is rather, let's say, an exploration/appraisal well. This goes into a reservoir, which so far has been just seen during drilling of Well 52, which was an oil production well for the Tournaisian reservoir. We penetrated this Bashkirian reservoir roughly 600 meters above the Tournaisian reservoir. And during drilling, we have seen there hydrocarbon-bearing formation in the Bashkirian. In the Western part of the field, we have a compartment in the Bashkirian, which we have since several years in production. And here the aim is finally to use this existing well which is currently not in production to drill the sidetrack for a small amount of money into that Bashkirian reservoir where we're then expecting to get a full term oil production, which will help us, let's say, to increase our daily productions and cash flow during the year 2019. So this is a major aim of this Bashkirian project. So it's not linked to the outcome of dynamic reservoir simulations performed by either Schlumberger or by PM Lucas.
And then on UOG, if I can just address the economics on UOG agreements. There are both -- there are 2 things. One is to treat their condensate, where it's very simple, we'll get paid $8 a barrel on that condensate. So they send through the -- through our gas treatment unit starting in Q4 of 2020. And then we will be purchasing a stream of Ural Gas, which is essentially us purchasing the LPG and dry gas from them. And this is done on a formula which is all the small details are confidential. But in order to give you an idea, they have 8 wells that they've drilled, which will come online and should produce, according to Wood Mackenzie, around 15,000 BOEs per day with a similar split of liquids and gas as Nostrum has from its gas condensate reservoirs. If you take those -- if you take that production and you put it through assuming the $8 per barrel of condensate treatment for your processing fee and you then assume our current prices for sales gas and LPG, then you will generate to Nostrum on a per annum basis approximately $50 million of additional free cash flow. So the 8 wells producing 15,000 barrels a day will approximately generate around $50 million of free cash flow per annum to Nostrum.If you want us to, let's say, give you more details on how to model it, then please e-mail Investor Relations, and we can send you more detailed calculations on modeling.
Your next question comes from the line of Thomas Martin from Numis.
Just a quick clarification around Stephane's question on Well 40. The 10 million BOEs that you spoke about, which could warrant 4 to 5 additional production wells, just to be clear, are the 2 wells you're currently drilling 2 of those 4 to 5 additional wells?
Sorry. Can you repeat that, Thomas? Because I think Kai just -- his line got cut off and he's dialing back in.
I'm just back. Sorry.
Okay. I will go again. Just on Well 40, where you've spoken about that 10 million BOEs of potential recoverable hydrocarbons could warrant a further 4 to 5 additional production wells. Just to be clear, are the 2 wells you're currently drilling 2 of those 4 to 5 additional wells?
No. These wells are going for deeper horizons. They are going, let's say, for the discoveries, which we have made in Well 724 in this Mullinski formation. And as I said before, they are even going deeper. So overall, as I have said before, we are seeing a significant potential in all the 3 formations which I'm calling overall, let's say, Upper Devonian formations. And here I see now based on the results, the first results of this well potential, let's say, that we can drill up to 22 wells in the future in this Upper Devonian reservoirs in the North. And if you then take, let's say, 2.5 million BOEs as lower level for each well as a recoverable production into account, you easily can come back to the figure I mentioned before in the call, where I was saying that we are targeting somewhere between 50 million and 100 million BOEs of recoverable reserves in this Northern part. And now, let's say, the currently available reserve of Wells 41 and 42, confirming that all 3 Upper Devonian formations, which we are targeting, seems to be hydrocarbon bearing. As I said, in Well 41, we make and drill stem tested the same reservoir from which we are producing Well 40. And in Well 42, we just, tonight, started to drill the deepest, the Vorobyovski reservoir, as you see here as well an inflow of that condensate. So therefore, we can now assume, let's say, that all 3 reservoirs are hydrocarbon bearing, and they will be now tested at first in the lower reservoir, which is the Vorobyovski reservoir, then we will move into the Mullinski reservoir, and then we will move up to the Frasnian reservoir. From which reservoir finally the 2 wells will be produced, this will depend on the final test results of the 3 reservoirs which I had just mentioned. So they are not yet part of this 4 to 5 wells. They may become part of this 4 to 5 wells. It's not excluded, but it's not the main objective for the well.
Okay. And just to be absolutely clear, the -- so the 50 million to 100 million BOEs, that is then in addition to the 10 million BOEs?
This is normal. The 10 million BOEs are part of this 50 million to 100 million. The 50 million to 100 million is the potential which we are currently seeing in the entire Northern area, covering all 3 formations in this Upper Devonian reservoirs.
Thank you, speakers. There are currently no further questions. Please continue.
Okay. Well, thank you very much, everybody, for attending the Nostrum Q1 2019 Results Call. And we look forward to speaking again at the half yearly results call, and wish you a good rest of the day. Many thanks.
Okay. Goodbye, everybody.
Thank you, ladies and gentlemen. That does conclude our conference for today. Thank you for participating. You may all now disconnect.