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Edited Transcript of NOG.L earnings conference call or presentation 28-Mar-17 1:00pm GMT

Thomson Reuters StreetEvents

Full Year 2016 Nostrum Oil & Gas PLC Earnings Call

Amsterdam Jun 9, 2017 (Thomson StreetEvents) -- Edited Transcript of Nostrum Oil & Gas PLC earnings conference call or presentation Tuesday, March 28, 2017 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 and Executive Director

* Thomas Richardson

Nostrum Oil & Gas Plc - Group CFO and Director

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Conference Call Participants

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* Adam Naughton

RBC Capital Markets, LLC, Research Division - Associate

* Artem V. Konchin

Otkritie Capital International Limited, Research Division - Senior Research Analyst

* David Mirzai

Deutsche Bank AG, Research Division - Research Analyst

* Ksenia Mishankina

UBS Investment Bank, Research Division - Associate Director and CEEMEA Analyst

* Thomas Henry Martin

Numis Securities Ltd., Research Division - 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 Nostrum Oil & Gas Full Year Results 2016 Conference Call. (Operator Instructions) I must advise you that this conference is being recorded today, Tuesday, the 28th of March 2017. And I would now like to hand the conference over to your first speaker today, Tom Richardson. Please go ahead, sir.

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [2]

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Good afternoon, good morning, and thank you for joining the full year 2016 results call from Nostrum & Oil Gas. You're jointed by myself and Kai. For the results call, where we'll apply our usual approach, where I will go through the presentation, which you can find on our website, outlining the highlights of the 2016 financial results. And then we will go to Q&A, where anybody is free to ask any questions.

Just as a matter of housekeeping, to start this call, I just wanted to make sure that everybody was clear in so much that there was a release from Claremont Holdings, a company owned by our Chairman, over a week ago. And from a Nostrum perspective, this is unrelated to Nostrum's chair's assets, licenses, ability to execute business in Kazakhstan. And therefore, in terms of everybody wanting to ask questions on this, we have no further information other than what was disclosed by Nostrum and by Claremont. So I would appreciate that when we get to the Q&A, we don't ask the same question 5 times and have to give the same answer 5 times. So just as a matter of housekeeping, our chairman obviously informed us at the recent board meeting, which approved the financial results. And therefore, so we are, from the company's perspective, we go about our normal course of business. And I want to assure that every bondholder, equity investor and analyst, as I have this morning in the analyst meetings, that, from a Nostrum perspective, we remain exactly as we were 2 weeks ago, trying to deliver all of our strategic initiatives. And this does not impact our ability to do this.

So moving to Slide 2, where we have the highlights of our 2016 results, which I believe are broadly in line with what everybody was expecting, following the operational update we gave at the end of January. I think there were some important aspects here that we would like to bring out. And I think if you remember back at the beginning of 2016, when we had our full year results call for 2015, we spoke about cost reductions and cost savings. And this is always nice words from management, but I believe the 2016 results really demonstrate that we have successfully achieved some reduction in our G&A, operational expenditures and transportation during the year 2016. The impact of this has obviously been that we maintained a healthy EBITDA margin. And also, from a liquidity perspective, we maintained a healthy cash balance of $100 million. In terms of the significance of the savings, if I compare the operating cash flow that we generated in 2015 under a $53 oil price environment, where we had roughly $150 million of operating cash flow, and then I compare this to what we achieved in 2016 under an average oil price of $45, where we generated $200 million of cash flow, that's an increase of $50 million despite a reduction in the oil price of roughly $8. So I believe a large portion of this resulted to the cost savings, which we've been able to realize. In G&A, from a -- let' say in total, we have reduced it by almost $10 million across the year. Similarly, in OpEx, we now have OpEx below $4 a barrel. And also, transportation costs have come down, but I will touch on that when we get to the slides later on in the presentation.

In addition, just in terms of the cash flow, we have received $27 million from our hedge that we have in place, and this has protected us against any falls in the oil price during 2016 below $49. It will continue to protect us from any fall in the oil price below $49 during 2017 as well, all the way up until December 15, 2017. And this remains on 15,000 barrels production hedged each day at a strike price of $49.16. So we continue, on a quarterly basis, to look at the average oil price. And over 2016, we are pleased to receive $27 million. The impact on the company, from a P&L perspective, is slightly different. But this is a noncash item, which I will comment to when we talk about the highlights on the P&L statement.

From a production perspective, you will see as we go through the presentation, this is broadly in line with 2015. We increased production when our 3 production wells came online at the end of Q3, beginning of Q4, bringing production up above the average for the year of 40,000 BOEs per day. Similarly, as I just mentioned our drilling program. We had a reduced drilling program to take into account the significantly lower oil price environment that we saw, especially in Q1 and Q2 of last year. And we reduced the drilling program accordingly to just 3 wells to ensure that we could maintain a healthy liquidity position. We completed these wells on budget, and we look forward now to the 2017 drilling program of 7 wells.

From a reserve perspective, again, here, we're only drilling 3 production wells. We're very pleased to announce that we almost recovered all of our production, increased through the proven reserves. So 97% reserves replacement ratio, which is a pleasing result, given that 2 of the wells that we drilled during 2016 had slightly better results than we were expecting, as we had mentioned on our previous call. The GTU3 remains on track to be delivered during 2017, and will allow us to then double our production capacity or more than double our production capacity in 2018.

If I move to Slide 3, where we go into a little bit more detail, you can see here finally the split of OpEx per barrel and the net operating cash flows. I would like to address a couple of points on this slide. Firstly, on OpEx per barrel, we were pleased to bring this below $4 a barrel. And this remains our objective for 2017, to keep the operational cost on a BOE basis below $4 a barrel. You'll appreciate that, last year, we only drilled 3 wells, where all of our work over expenses are coming finally through the OpEx line. So as we increase our drilling and have some appraisal wells in there, which will not add directly to production during 2017, we still aim that despite the increase in drilling OpEx that we will still keep this OpEx per barrel below $4. Furthermore, the chart on the bottom left shows the increase in operating cash flow during 2016 relative to 2015 with the corresponding oil prices. And here there's -- roughly 2/3 of this is from the savings of I say real operational cost-cutting through G&A and OpEx, and then the remainder is through the reduction in tax as a function of the lower oil price. In the bottom right, you'll see that our leverage, if I look at the gross debt to EBITDA, is at 4.9x. If we see oil prices above $50 for the remainder of this year, then I would expect that we have probably peaked from a leverage perspective, i.e. that I don't expect that the gross debt to increase because we just have 2 bonds outstanding. So they're not facilities that we can just draw down on to increase debt. And I don't see that EBITDA will fall below the 2016 level, '15 -- sorry, '16 levels. It all remains above $50. So I would expect that the gross debt to EBITDA figure should be peaking as of full year 2016, and we obviously look forward to refinancing all or part of our debt during 2017 and potentially in 2018. In terms of the questions from analysts this morning that we have had this clearly a larger focus on this refinancing, and we are looking at all the different options available to us. Clearly, we have a track record in the bond market. We like the bond market and the operational flexibility it gives the company to really focus on the core strategic initiatives we have in front of us, which is completing our gas plant and ramping up production. Therefore, we are, throughout 2017, keen to remove all or part of the refinancing obligation that we have coming due in 2019 on $960 million of our debt.

If I turn to Slide 4, this again highlights the cash that we still have on our balance sheet. Many people remember the slides that we have shown throughout the whole of 2016 and even the end of 2015 showing a minimum cash balance at all times of $50 million. We are pleased that we have always or pretty much always maintained through 2016 a cash balance in excess of $100 million. And in Q3, we dipped a little bit below that. But based off the increasing production and increasing oil price in Q4, we are pleased to be back above $100 million of cash on our balance sheet. The hedge I have mentioned from the cash that it's delivered to the business during 2016, what I haven't, let's say, touched on is that this has also a negative impact as a result -- through the P&L statement as a result of the rising oil price during 2016. We effectively purchased this hedge in December of 2015 using the value in our old hedge of $96 million. Therefore, from an accounting perspective, as the oil price has risen above the strike price, and as the time to maturity on that hedge shortens, therefore, you see a loss through the change in fair value of the hedge instrument. This comes directly through to our P&L statement. And therefore, you see a loss of $63 million on our income statement, which is really driving then the majority of the loss for the year of $82 million. So a significant portion of the loss for the year is a result of a noncash item that is a function of the valuations implied through IFRS for these derivative instruments at a single point in time.

Also to highlight is the CapEx flexibility that we showed during 2016. We had originally budgeted to spend over $250 million. And through reduction in project spending, we were able to reduce this to in total roughly $204 million of cash spent during 2016. This was not simply a function of just further cutting the drilling program because we stayed with 3 wells being drilled, but really doing an internal exercise of ensuring that any cash that we were spending was really being spent in order to deliver good value to the company, such as the pipeline that is connecting into the Transnet pipeline, which, from a Nostrum perspective, we have now finished, and we are waiting on KTO to be able to link up the pipeline into the main trunk pipeline. So from that perspective, we have really internally not only looked to addressing the cost on G&A and OpEx, but also at trying to ensure that, where possible, any of our capital expenditures, whether that be on the cost of drilling wells, on the cost of infrastructure or on just maintenance, we are really making sure that we are trying to ensure that the cash we spend is really only spent when it's absolutely needed.

Lastly, in the bottom right-hand corner, it talks about the scalable drilling program we have. As we saw during 2016, we had initially planned a more significant drilling program, which was then scaled down to just 3 production wells. We will continue, during 2017, to monitor the oil price. At the moment, our base case is to drill 7 wells. And with oil where it is, we don't see this changing. However, obviously, if oil prices increase, we still have the ability to bring new rigs or more rigs to the field sites. However, for this call, we are set and guiding on a 7-well program, but that remains obviously scalable. And we have not committed to any significant long-term programs yet, and we will wait until we are mid or at least 3 quarters of the way through the year before committing any cash on longer-term drilling programs for the ramp-up in production, as we have always put a significant importance on having liquidity in the company. But at this stage, with oil prices between $50 and $60, we feel very comfortable with our drilling program. And we also look forward, and I will talk to it on our future slides, that we can fund both this year's drilling program and future years' ramp-up in production, all from operating cash flow at oil prices below the current levels.

If I move to Slide 5, this is the typical cash bridge that we have shown over time. And you will see here that we have a $130 million cash essentially to balance between drilling and having just liquidity at the end of the year sitting on our balance sheet. As mentioned, we plan to drill 7 wells. And therefore, we will not be using anywhere near $130 million on our drilling program. It will be closer to anywhere between $70 million and $80 million for this year, therefore, giving us again at least $50 million of cash on our balance sheet. And please, if you look below the operating cash flow figure, this is based on the assumption of a $45 oil price for the year. Therefore, any oil prices above $50 obviously would lead to an increase in operating cash flow. Also important to note in this liquidity slide, that this is predicated on a production of just 44,000 BOEs per day during 2017, and it's not assuming any new gas from -- or any new production through our GTU3. This is simply saying and assuming that the first gas for commercial sales and increase and ramp-up in production is coming finally on the first of January 2018. Thus, the assumptions that are driving the operating cash flow for the year is a $45 oil price and a 44,000 BOE per day production for the year.

If I move to Slide 6, which I'm sure you'll have questions on in the Q&A, but here we are -- as touched upon in the highlights, we are pleased to have achieved a 97% reserve replacement. And also, we have -- for the first time since 2014, we've decided also to make sure that the market is aware, investors and analysts are aware of our contingent resources, which we have 221 million barrels in our field. The split between the Chinarevskoye field and our Trident licenses is roughly $170 million -- sorry, 170 million barrels in the Chinarevskoye field, and then the remaining 50 million barrels is in the Trident field. You will remember this time last year, we moved 70 million roughly barrels of 2P reserves from 2P into contingent resources as a result of the falling oil price. And any questions on this can be addressed with Kai in the Q&A later in the call.

Moving to Slide 7, we have updated this slide based off the new and updated Ryder Scott reserve reports as of 31st December 2016. This finally shows the estimated production levels for the year, and with the top end being the Ryder Scott figures of 80,000 and 100,000 barrels per day in 2018 and 2019 and the lower end being the targets, which we believe that Nostrum will be able to achieve irrespective of oil price movements. The reason for the deviation or the wide range is because, clearly, we have seen, and this time last year we were in an oil price environment of $28. Therefore, we are hesitant to commit to the precise drilling programs that Ryder Scott is assuming in 2018 and '19 until we get closer to the end of this year, and we can see finally how the oil price environment is looking. Therefore, we have a range for our drilling programs still in 2018 and 2019, which therefore results in a potential range in production estimates. The one point to note is that if you look below this bar chart, you will see that the oil price that is required in order to fund the drilling, which is the drilling program as stated by Ryder Scott, so i.e. meeting the top ends of those production figures, if we were to fund fully that drilling program all out of operating cash flow, then we need on oil price of approximately $40 in order to fund it all from the operating cash of the business and not requiring any additional cash. So this is to show that the drilling costs from -- if I look at this slide, the similar slide back in 2016 and '15, we were requiring $44 a barrel. The fact that the drilling costs have come down slightly has resulted in a slightly lower breakeven oil price that we require across these years in order to fund this out of operating cash flow.

If I move now to Slide 9 to just give a snapshot of the financial results. The main impact here, which I've touched on earlier, and I would like to draw your attention to again, is that whilst the net loss on the surface of $82 million is very significant, the majority of this loss is driven by the change in fair value of our hedge, which is contributing $63.2 million. Clearly, the other impact to the loss is the falling oil price, where we had only $28 of oil prices in Q1 of last year. So clearly, revenue has materially declined if I compare it to 2015. But still, of the loss, the majority here is being driven from the change in fair value of the hedge. Then again, just to reiterate, I believe that the net cash flows from operating activities, this is really a significant cost-saving program that is being run throughout 2016 to result in $50 million more of cash coming on to or coming through the business and being generated.

On Slide 10, I've already covered the OpEx per barrel. But on transport costs per barrel, I just want to make sure that we are clear here that whilst we have recognized a saving on the BOE basis for transportation, the majority of this is driven from the fact that in 2015, we paid for transportation on our dry gas. Whilst in 2016, we have not paid for transportation costs on our dry gas, but we pay rather a marketing fee because we're selling the dry gas at the connection point to KazTransGas. Therefore, this is slightly disproportionate in terms of the savings have not all been recognized as straight-through pass-through to the company. There have been some savings from logistics and transport costs on condensate, and we expect to see future savings as a result of the reduction in the crude oil transportation costs as a result of linking in to the Transnet pipeline system. However, what we have seen in let's say February and March is the potential for increasing cost of transportation in condensate, and we will investigate this further to see whether it is possible to mitigate any of these increases in the condensate transportation costs. These are not particularly significant, but if you take into account the savings of the transportation on crude oil, and then balance it against the potential increase throughout the year on condensate, then you'll see a relatively neutral effect overall to our transportation cost. So I expect that we should be able to keep transport costs around $5 a barrel during 2017. We would also hope to keep our OpEx and G&A costs in check and the OpEx below $4 a barrel. So we hope to maintain the EBITDA margin above 50% during 2017.

Just a quick note on tax. This looks like a very significant saving on a BOE basis. Obviously, with a lower oil price, you will pay significantly less taxes as you generate less cash. But also, we made an overpayment at the end of 2015. So we were receiving credits during 2016, which also slightly skews the significance of the reduction when you see just a $7 or $8 decrease in the average oil price over the years, and you see more than a halving in the per barrel cash paid on tax. So from a tax perspective, this will be largely a function of just the oil price. But we would expect here to be, at the oil prices at $53, then we will be back above $3 a barrel for taxes during 2017.

Moving to Slide 11. As I mentioned earlier, we have $960 million of debt coming due in 2019. This is a key focus for the management to look at the possible options for refinancing. And as you will see in our annual report, which was released this morning, this is one of the key objectives that the company has set itself and myself and Kai for 2017. We did not want to leave the refinancing until the last minute. We want to make sure that we are well prepared. We have looked at all of the options. We have looked at all of the potential different costs, of different types of refinancing. And we want to ultimately choose the one that gives the company the most operational flexibility, but also ideally the lowest cost. As you have seen during 2016, I believe we have been able to focus on delivering cost savings and focus on the operations of the business, whereas I believe sometimes when you have, say, heavy maintenance covenants on your debt, you can spend, as a result of one-off falls in oil price, you can then be spending more time sitting around tables, working out solutions to this rather than focusing on the business. So our priority is try to find a balance of the structure of the refinancing, whereby we still have that operational flexibility. And from a cost perspective, I want to just draw people's memory back to the fact that we first entered the bond market in 2010 when we didn't have a gas plant. We had $100 million of revenue and $50 million of EBITDA, and we were able to do a $450 million bond at 10.5%. Therefore, in terms of, let's say, what we see as potential costs of financing and methods of financing, I believe now we have a fully functioning gas plant. And we're very close to having a third train or a second gas plant, and we are producing over 40,000 BOEs per day. Therefore, we see the cost of any refinancing significantly below where we were able to do this in 2010, irrespective of the fact that the oil price is clearly lower today.

That really concludes the overview of the financial results. We believe, let's say, that these are in line with all of the expectations that we set at the beginning of last year. We will continue to try to keep a lid on our operating costs as the oil price remains low at roughly $51 today, and we continue to believe that Nostrum is in an excellent position to be able to execute all of its strategic initiatives this year. And we will continue to try to build our reserve base around the infrastructure, which we are in the process of completing, and deliver the cash flows from the ramp-up in production over the coming years.

But this concludes finally the financial presentation, and I would like to now hand over to Q&A.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question today comes from the line of Adam Naughton from RBC.

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Adam Naughton, RBC Capital Markets, LLC, Research Division - Associate [2]

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Just one question for me. On the 2017 drilling, how many of the wells are turnkey in production? On the appraisal well that you're drilling, can you give us an idea of how much in terms of resources and reserves you're targeting to move from 2C to 2P and from 2P to 1P?

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

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Yes. The exact result of costs will be known once we have drilled and tested the wells. The target is as follows. As it has been said, let's say, that we have started the drilling program in 2017. We are currently drilling one appraisal and one production well. We have 2 rigs under operations. The third rig is under preparation and mobilization, and we're expecting that the third rig will start with doing operations somewhere in the month of June 2017. On -- so these are off a base site. I think you can always assume that for wells, which we are drilling within our gas condensate, or Devonian formations being at either Biski-Afoninski or Mullinsky reservoir, we are targeting that each well, let's say, roughly 20 million barrels of oil equivalent, to be transferred from mainly now probable into a proven category of reserves.

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Operator [4]

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Our next question comes from the line of Ksenia Mishankina.

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Ksenia Mishankina, UBS Investment Bank, Research Division - Associate Director and CEEMEA Analyst [5]

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This is Ksenia Mishankina from UBS. I have a question on your refinancing. As you do come to the debt capital market, do you plan to use the proceeds to do a bond buyback of your outstanding debt?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [6]

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Thank you for your question. I think we are looking at all various options in terms of refinancing. And at this stage, we don't have any single route that we have selected. We're exploring them all. So you'll appreciate that in terms of those kind of details, we don't have answers for them yet. How and when we do have a specific answer to the intended cost of refinancing, then we will communicate this with the whole market.

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Ksenia Mishankina, UBS Investment Bank, Research Division - Associate Director and CEEMEA Analyst [7]

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The question more about the use of proceeds rather than the actual instrument for refinancing. How do you plan to use the proceeds?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [8]

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For repaying existing debt, i.e. for refinancing.

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Ksenia Mishankina, UBS Investment Bank, Research Division - Associate Director and CEEMEA Analyst [9]

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So you wouldn't be doing buybacks prior to that?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [10]

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No. We will look to -- we have $960 million of debt today. And we will be looking to, if we did, let's say, raise any sort of financing, whether that be bonds, banks, whatever the source, then that would be used to repay existing debt, i.e. we will be looking for debt with a longer maturity than our existing debt, i.e. beyond 2019.

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Operator [11]

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The next question comes from the line of Artem Konchin.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [12]

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My first question is about your export duty. If you could help me figure out -- it declined quite a bit relative to the oil price move and your production being rather flat. Is that a function of the full repayments in taxes you were mentioning? Or is it -- am I just modeling it wrong because it seems that it shouldn't have been that low?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [13]

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Well, the -- sorry, Kai. You go first.

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

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Well, just the -- on the expert duty, let's say the export duty is at first just applicable for crude oil and not for condensate. Secondly, the export duty is set by the Ministry of Energy and mines, of oil and energy in Kazakhstan based on the formula which they have published, where the export duty is linked to the actual oil price. So if oil price was going upwards, most likely, we shall expect an increase as well in the export duty. If oil price is staying at the current level, we are currently paying roughly USD 40 per ton of an export duty.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [15]

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Okay. So it's oil only maybe? That's why it's become -- you produced less oil, I guess, in '16. The other question was about your short-term liability. On Page 172, you have, within the next 12 months, roughly $66 million due. What is this, the nature of this liability? Could you explain, please?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [16]

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Yes. So this is -- I think you are looking at the deferred income tax liability that we have on our balance sheet. And this is not a liability that is coming due in -- let's say, in total this year. This is a liability that has been building over time. So it's a function of the fact...

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [17]

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If I may stop you here, it's actually in the borrowings line, on less than 3 months and 3 to 12 months...

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [18]

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Okay. This is just the interest on our bonds.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [19]

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Okay. So it's interest, right? It's not the borrowings and stuff. So okay, great. And then the final question, if you could help me out figure out the difference in drilling cost for your wet gas wells versus oil wells, so that I could model it more precisely, your maintenance versus growth CapEx, how much more expensive the gas wells are, if it's possible. That will be all for me.

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [20]

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Roughly, to give you an indication, let's say, the belt in the gas condensate reservoirs, which are the deepest reservoirs in our license, as I said, it's -- are the so-called Mullinsky and Biski-Afoninski reservoirs are roughly between, I would say, 35% and 50% more expensive than the wells which we're drilling for oil.

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Operator [21]

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Our next question comes from the line of [ Alexander Ayoub ]

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Unidentified Analyst, [22]

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I have 3 questions. First one, just on the CapEx. You referred to assume to around $150 million for 2017, so about half for drilling, half for the GTU3. For hedging, do you plan any hedging for 2018? And then finally, on the bond, which on the debt repayment, just wanted to clarify a few points. The first one, do you expect to -- or you're planning to repay this year. Is that correct? Or you're planning to focus on the repayment plans this year, so it's just a small nuance there? Second question there is, we saw, importantly, some people talking about -- you mentioned that you're contemplating all various options, but do you also contemplate restructuring options, where you ask the bondholders to extend the maturity of the bonds? Is that something you're also contemplating? And finally, again, on the bond side, is the issue -- there were some headlines, I think last week or a few weeks ago, around BTA claims on one of Nostrum's shareholders, preventing them from passing any border -- key board resolutions. Is that potentially an issue, which could delay, for example, the issuance of a new bond or your refinancing plans?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [23]

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Kai, do you want to do the first 2, and then I'll do the last one on the refinancing?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [24]

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Yes, but I have not completely understood the first one. Was it related to CapEx? But can you repeat the question, please?

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Unidentified Analyst, [25]

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Yes, CapEx. Just 2017 CapEx guidance. You referred to assume $150 million, about half of it for drilling, half of it for GTU3?

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

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No. I would rather say it's 2/3 for surface and 1/3 for drilling.

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Unidentified Analyst, [27]

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2/3 for surface? And the $150 million, of that share goes where?

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

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Including GTU3 because there are other CapEx, smaller CapEx investment as well in the field to connect new wells to maintain the existing gas treatment unit. So 2/3 of this amount roughly goes for surface investment and our CapEx expenses and 1/3 for drilling.

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Unidentified Analyst, [29]

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I hear you. But then should we expect $210 million of CapEx for 2017? Because you're on like $70 million to $80 million of drilling CapEx, and you're saying this is only 1/3 of the CapEx. Just want to clarify, what's the total CapEx you expect for 2017 total for surface and drilling?

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [30]

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Yes. If you look at Slide 5, [ Alexander ], then you can see $120 million is net spend for GTU3. And then as you say, roughly $70 million for the 7 wells for drilling. So about $190 million to $200 million of total CapEx for the year. I think -- sorry, there was, [ Alex ], 2 other questions, which we're unanswered. One is on hedging. So just we do plan to look at hedging in 2018. Firstly, we want to look at the total drilling program that we want to commit to in 2018. Once we have analyzed the total CapEx essentially that we are committing to in 2018, as well as any other, for example, interest costs or other costs that we wish to cover, then we will build a hedging program to cover that. But at this stage, it's too early to state what the structure of that program will be. But clearly, historically, we have preferred to not pay cash for any of our hedges that we've put in place. Therefore, you can assume that we will try to balance, for sure, any cash-out against potential structures, where we could give away a coal spread or some upside in the oil price in order to pay for protection on the downside. Today, we don't have any specific answers on that, but we are certainly considering it. And I believe that, today, it's absolutely our plan to ensure that any significant drilling programs that we enter into, which we need to in order to ramp up production, we will look to cover through hedging. So I think that was your second question, [ Alexander ]. Then your third question, in relation to the refinancing, as I mentioned at the beginning of the call, the claims in relation to BTA and the involvement of Claremont, a company that is owned by our Mr. Monstrey, our Executive Chairman, this is not related to Nostrum, and this will not impact Nostrum's timing or strategy on its refinancing. We are looking at all the different options, and we continue to do so. And this is an issue in relation to one of our shareholders and not Nostrum's business itself. In terms of the actual plans that we have for refinancing, we're looking at all the various options, but I think I would like to avoid using the word, restructuring, because I don't believe that we will be doing a restructuring. I believe we are very capable of executing just a refinancing, i.e. where we may look at raising financing, whether that's from bond investors or banks or other third parties willing to provide debt financing to the business. And then we will look to repay our existing bonds. Now if we were to look at doing the bonds, then any new bond we'd potentially look to refinance an existing bond, just with a longer maturity. So we are -- the exercise that we are looking to enter into is to move the significant maturities we have all coming due in 2019 to a longer-dated maturity, and let's say beyond 2019. And the form in which that is done and the structure through which that is done, we don't have the answers to yet. But we are working on it. And it's something that we will, as soon as we have made any decisions internally, we will come back to you on.

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Operator [31]

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Our next question comes from the line of Thomas Martin.

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Thomas Henry Martin, Numis Securities Ltd., Research Division - Analyst [32]

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I was wondering if you could give us an update on -- a bit more detailed really around what stage you're currently at with the GTU3 construction and commissioning, maybe some information around what key items still have to be completed, and both in terms installation hookup and commissioning?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [33]

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It is in the short-term, really let's say current status and of recoveries that we have reached an overall progress of roughly 77% of the overall project completion. So it would impact us all. All equipment is at site. The main part of all the civil works is done. The field structures have been erected. The compressors have been installed. The compressor buildings are erected. And currently, let's say, the works are ongoing to lay all the pipes and the cables. And this is what we are assuming, let's say, as being the main activity, including the assembly of the main equipment during the next 3 to 5 months with a significant increase in manpower provided mainly by our main contractor for the civil and assembly works, which is KSS. And yes, therefore, we are assuming and targeting, let's say, the main completion summer and autumn 2017, and then the (inaudible) gets in before the end of the year 2017.

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Operator [34]

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Our next question comes from the line of [ Ann Kessler ]. The next question comes from the line of [ Ann Kessler ] from [ Sberbank ]. Okay. Due to no response, we'll move on. The next question comes from the line of [ Afghani Stroynov ].

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Unidentified Analyst, [35]

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I have 2 small clarifications, if I may. First is regarding your production guidance. As I remember in the operating update you published about a month ago, you said that you target an exit rate of -- in the range from 50 to 60 by the year-end this year. Do you stick to this guidance? Because I did not find anything about the exit rate in your current presentation. And the second question is about your drilling program. Am I right to assume that you are planning to drill 3 maintenance wells and 4 wells subject to kind of discretionary wells you may drill or may not depending on the oil price?

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

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On your first question, there is, let's say, always -- we always take into account, let's say, the time at which a new production well's coming into reproduction. So therefore, they first need to be drilled. So we are seeing, let's say, currently, from the high production, which we have reached December, of roughly 48,000 BOEs per day -- December 2016, I mean, as no new wells are getting added. We are seeing a slight decline until the middle of the year 2017. Then new production wells, the first 2 ones, will be added. As I mentioned before, we are currently drilling the one exploration appraisal well and have started one production well. And we will start and complete still another production well in the first half-year 2015. So we are seeing then, let's say, from beginning of July, let's say, once the new production well's going onstream, begin an increase in production, and then we will reach finally the amount of 56,000 BOEs per day of our daily production capacities remaining for production wells will get connected during the second-half 2017. So for the exit, let's say, production end of 2017, our target remains, let's say, between 50,000 and 60,000 BOEs per day. But this is not an average production as an example for year 2017. Now this year, you have always to take into account that the average production figure for the entire year is one thing and the exit production figure at the end of the year is a different figure and significantly higher.

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Operator [37]

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Our next question comes from the line of David Mirzai.

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David Mirzai, Deutsche Bank AG, Research Division - Research Analyst [38]

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Gents, question, trying to get a sense of the risk involved in development drilling over the next 2 to 3 years, plans to drill 6 development wells this year, probably double that next year, and then more going forward. But will this development program be down-spacing within an existing well control? Or will you be targeting a new flank or new installs? How should we really kind of look on the risk of your actual drilling program and your ability to build up your production profile, as you wish?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [39]

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Yes. This is already defined, let's say, by the list of categories by itself. So everything that you say, part of the reserve, as you know, and not as the resources is under our current understanding of the geology of the field in a certain category. The -- so there are no new start drills or certain areas, which have not yet been drilled and tested included in any 2P results, which have been 1P or 2P reserves, which have been reported. We are following, let's say, in 2017, of course, a little bit, let's say, a strategy, where we are outstepping the wells. So we are moving, let's say, from the area of proven reserves into the area of 2P reserves, where wells have been tested. But there's, of course, between the wells, the distance between the wells is significantly larger than the distance between wells, which we have adjusted the proven area of reserves. So therefore, again, by definition, let's say, the probable reserves are, from a risk perspective, more risky than proven reserves. But these proved reserves are not 100% granted. This is always a function, just for you to give you a risk estimation, let's say, on the different wells we are drilling. Nevertheless, let's say, our history has shown, let's say, that beside the setbacks, which we had in the year 2014 and '15, where we, from a technical perspective, have not reached, let's say, the production rates which we were assuming, as we had lost a couple of wells due to technical problems in the well, one of the reasons I think that have been explained. We have therefore changed well design. We have made a lot of atomizers about the reasons for that figures. And we now hope that we are well-organized, let's say, in order to make that drilling campaign a success. But just from a pure risk perspective, if you are drilling in an area with 2P reserves, the risk is always higher than ones you're drilling in an area with proved reserves.

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David Mirzai, Deutsche Bank AG, Research Division - Research Analyst [40]

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Okay. And yes -- but you do have existing well control? You have tested those different areas that's been drilled in?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [41]

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Absolutely. Otherwise, you can't report them as a reserve... yes, otherwise -- sorry for interrupting. Otherwise, you can't report them as a reserve if you are in an area where you have not yet tested wells, you are not reporting reserves.

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David Mirzai, Deutsche Bank AG, Research Division - Research Analyst [42]

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Yes. And just a second question. With regard to the 3 wells that you drilled last year, you announced that they went quite well. They were on time and below budget. You're going to drill 7 new wells this year. What type of learnings did you have last year, which you're going to apply this year? And I suppose, what should we look for from your language this year to assess whether or not you've had a good well or not?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [43]

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Yes. This is always, let's say, quite early to be assessed for our gas condensate wells. We are assuming an original start production rate of the well, with raw gas condensate at the level of roughly 150,000 to 180,000 cubic meters of raw gas condensate per day. This is our average assumption for all the new wells of average we are drilling. So as soon as production shows up to be higher, then it's above our expectation. If the production somewhere lies between 150,000 and 200,000, that is in the range of our expectation, and if production per well is below 150,000 cubic meters per day, then it's below our expectation. Coming now back to the wells, which we drilled in 2016, the 3 wells, which we have mentioned, 2 of them had production rates from more than 400,000 cubic meters per day, and the third well was within our expectations.

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David Mirzai, Deutsche Bank AG, Research Division - Research Analyst [44]

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Perfect. And just one last one for me. In terms of your updated independent reserves report that you have, if I step back and look at your 2010 plan of development and what your reserve auditors expected back then, and then I look at this year's numbers, this year's plans, outside of the change in well design, which was driven by lowering of the oil price, is there any other material differences I'll notice between the 2 development plans or the 2 geological interpretations?

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Kai-Uwe Kessel, Nostrum Oil & Gas Plc - CEO and Executive Director [45]

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No.

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Operator [46]

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We have another question from the line of our Artem Konchin.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [47]

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I just wanted to clarify the answer you gave about the reserves targeting per well. The line wasn't very clear. If you could repeat that number, and just tell me if this is an equivalent of the estimate ultimate recovery that we see like in North America shale wells or something like that, is that number...

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

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You can't compare our wells with American shales.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [49]

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No, I'm not comparing. I'm just saying --- no, no, no. I'm not drawing direct parallels. I'm just saying this is pretty much the way we expect to come out.

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

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It's different technologies, different number -- yes. No, no. It's just let's say, again, it's different from an oil well than for a gas condensate well. If I'm looking, let's say, at the gas condensate, these are wells which are our main target as well for the drilling program in year 2017, as we're trying, let's say, to build up and to prepare ourselves for the ramp-up of the production as soon as the GTU3 is in operations. So yes, usually, let's say, seeing reserves or you are looking, let's say, we use the thesis of the Ryder Scott report as well where you have a single well analyzer. So the entire reserves in the production profile are based, let's say, on an assumption of a certain drilling schedule and allocated reserves, which each well can produce over time. And if you look then at that wells, of course, it depends on the different reservoirs because there's -- we're currently producing out of 5 different reservoirs, hydrocarbons. You will always be -- or you always can allocate, let's say, to a certain well, a number of reserves that you are trying to transfer. And then you have the wells classified in the different categories. There are wells which are classified to the 1P reserves, and you have wells which are classified to the probable reserves. So -- and from that, you can always take, let's say, then an exact amount of reserves, which are targeting with a certain well. And this, of course, is for each well slightly different. But in average, let's say, for the gas condensate, it's in a range, let's say, of roughly 20 million barrels of oil equivalent that we are trying to transfer. Whereby for the oil wells, the amount is lower. It's between 5 million and 10 million barrels, which we're trying to transfer.

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Artem V. Konchin, Otkritie Capital International Limited, Research Division - Senior Research Analyst [51]

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Great. If I may finish, do you plan any trips for investors or analysts to the site this year or perhaps next year?

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

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It depends on the oil price.

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Operator [53]

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We have no further questions at this time. Please continue.

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Thomas Richardson, Nostrum Oil & Gas Plc - Group CFO and Director [54]

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Okay. Well, thank you very much, everybody, for attending, and we look forward to speaking with you again for the Q1 results. Many thanks. Bye.

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

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Okay. Goodbye, everybody.

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Operator [56]

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Thank you. That does conclude our conference call today. Thank you, everyone, for participating. You may now disconnect.