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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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Hello, and welcome to the Nostrum Oil & Gas Q3 2023 Financial Results Call. My name is Laura, and I will be your coordinator for today's event. Please note, this call is being recorded. [Operator Instructions] However, you have the opportunity to ask questions at the end of the call. [Operator Instructions]. Today, we have Arfan Khan, Chief Executive Officer; Petro Mychalkiw, Chief Financial Officer as our presenters. I will now hand you over to your host, Petro Mychalkiw, to begin today's conference. Thank you.
Thank you, and welcome, everyone to this call to present the financial results of Nostrum PLC of the third quarter and 9 months ended 30th September 2023. My name is Petro Mychalkiw, Chief Financial Officer of Nostrum, and I'm joined on the call today by Arfan Khan, our Chief Executive Officer. We will be following the format of our investor presentation that is available on the Reports and Presentations section of our website. At the end, we will open the floor for any questions. I'd like to hand over now to Arfan Khan, our Chief Executive Officer. We will provide updates on our key strategic, financial, operational and HSE and ESG news summarized on Page 3 of our investor presentation.
Thank you, Petro. Great to have you join me here. And of course, welcome to you and to our enterprise. Looking forward to working with you and welcome, everyone, to our Q3 2023 financial results call. Summary of the key strategic financial and operational highlights for the third quarter 2023 are set out on Page 3. Let me just touch on a few strategic topics before getting into the operational side. As announced in early September, we successfully completed the restart of our state-of-the-art GTU3 gas plant with 2.5 billion cubic meter per annum gas processing capacity. The plant employs cutting-edge turboexpander technology, enabling improved efficiency and extraction of LPG and then -- it's called GTU3, is operating as per design and delivering dry gas, LPG and condensate to sales specifications. During this period, we commenced the appraisal campaign at the Stepnoy Leopard fields. The objective of the campaign is to reenter 2 wells in the Teplovskoye reservoir to take representative fluid samples and conduct extended well testing. The data will help us to confirm the commercial potential and support the future decision related to selection of a phased development concept in 2024. As you may know, we also had the approval of our Board to conduct a limited scale drilling program for the Chinarevskoye field executed starting actually later this year and carrying into 2024 which is line with our commitments of the company's subsidiary, Zhaikmunai LLP under the analysis of the Field Development Plan and obligations under PSA for the field. The program will leverage existing wellbores to reduce cost and carries a level of uncertainties and risks as the planned subsidies targets contain multiple exploration appraisal and development objectives. Let me switch to summarizing the financial highlights. So average year-to-date production and sales volumes were over 10,000 barrels of oil equivalent per day and 9,000 barrels of oil equivalent per day, respectively. Q3 revenues were $36 million and year-to-date revenues were $89 million. Q3 EBITDA was $17 million, and year-to-date EBITDA was $33 million at roughly 37% margin. Of course, both revenues and EBITDA are decreasing year-on-year as a result of declining Chinarevskoye field production. And while our largely fixed operating cost remains -- not a significant amount of change there. And with the commodity prices as well declining sort of explains the lower margin. At the end of this period, we had roughly $172 million unrestricted cash balance, which is again a solid base to continue invest into economically favorable strategic objectives. On the HSE sustainability side, we experienced 0 lost time injury and one total recordable instant during operations in 9 months 2023. 3,300 tonnes of air emissions emitted in 9 months '23, against 6,000 tonnes permitted for '23 under the Kazakh environmental code. In October this year as part of our environmental protection plan in support of our ecology improvement objectives, we planted over 400 trees in the Dallas area by our subsidiary, Zhaikmunai. Operationally, and as announced in July, we launched the Gaslift system expansion with the new compressor, which is doubling our compression capacity and helping to offset partially the decline in production. The production gains to date have, in fact, continued to exceed our expectations and are reflected in our Q3 2023 production volume. And as mentioned earlier, the GTU3, the 2.5 bcm gas processing commissioning and restart was completed successfully without any incidents and the plant continues to perform as per the design specifications. And we are, as before, continuing with our well and reservoir management strategy to sweat the assets as much as possible through our workovers and rigless well interventions in 2023, which we intend to continue going forward. The Ural Oil & Gas tieback project is in progress, significant progress has been made, budget for the $5 million of capital expenditures. It will allow for the first ever third-party feedstock to be received for processing in the group's facilities. So we're still expecting production startup soon. I will now hand over to Petro to run through our financial performance.
Thank you, Arfan. I'll now be referring to Pages 4 and 5 of the investor presentation pack. As already mentioned, average production volumes for the 9 months at 10,288 barrels of oil equivalent per day with 25% lower year-on-year, reflects an impact of naturally declining production from Chinarevskoye field, partially offset by the positive impact of additional production from our Gaslift expansion program on the GTU3 startup. Our expectation is that our full year average daily production will be at the upper end of our guidance range at approximately 10,000 BOE per day. Our production mix for the 9 months is approximately 0% increase and 42% dry gas. Q3 revenues were similar levels to Q2, due to production and sales volume decreases offset partially by the incremental volumes from Gaslift expansion in GTU3 as well as improved crude oil and condensate product pricing from August '23, although prices overall remained lower than in 2022. The delta between production and sales volumes is mainly represented by [all use] gas required to power the field and processing facilities which has been running at approximately the equivalent of 11% of production for the 9 months period. The timing of our condensate sales shipments is also a factor to explain the difference between production and sales volumes. EBITDA for the 9 months was $33 million with an average EBITDA margin of 37%, a reduction compared to 2022, caused by reduced year-on-year production and revenues and a largely fixed operating cost base. In addition, EBITDA margins [Indiscernible] quarter-by-quarter, depending upon the product sales mix and prevailing sales price between quarters. The group's unrestricted cash balance as of 30th September '23 was $171.7 million. The Q3 quarter reduction in cash was due primarily to the $19.3 million acquisition payment for the company's 80% interest in Positive Invest LLP. The group's restricted cash balance as of 30th September '23 was $24.6 million, mainly representing the debt service reserve account balance of approximately $16 million and the liquidation from balance of approximately [$8 million]. Free cash flow year-to-date of minus $62 million, reflects one-off items, including CIT, VAT and related fines and penalties totaling $25 million settled in Q1 resulting from an extensive tax audit for 2016 to '21. Also one of items totaling $25 million arising from the bond restructuring closed in Q1 '23, and of course, the $19.3 million acquisition payment for the company's 80% acquisition of Positive Invest LLP in Q3. Adjusting for such on-off items, the company remains net free cash flow positive for the 9-month period. It is expected that the company will continue to see decline in revenues from its Chinarevskoye field, subject to of course to product prices. Hence, the company may need to utilize some of its existing cash reserves or investments in respect to new projects and activities such as appraisal and development of Stepnoy Leopard fields and the 2-well drilling program at Chinarevskoye. The benefits from such investments will not be seen until 2024 at the earliest. [Indiscernible] continue focusing on optimal product marketing and cost optimization to maintain its cash reserves as much as possible. Moving forward, [indiscernible] that our Chinarevskoye operations are self-funding, that we optimize costs wherever possible and we preserve our cash balances cash reserves for selective investment opportunities. This concludes our presentation for today. And I will now ask the operator to open the floor for Q&A.
[Operator Instructions] We'll now take our first question from [Indiscernible]. Please go ahead.
On the back of the comments [Indiscernible] the situation in relation to your notes, could you please remind us where the cash is located, what banks and what geography and what kind of investment products the Board is considering currently?
We obviously hold cash in our debt service reserve account and in our liquidation front. Most of our funds are held currently with Citibank. And most of the [Indiscernible] held in U.S. dollars. Majority of those money are held in London based bank accounts.
Right. And what investment products is considered?
Yes, the company obviously has currently substantial cash reserves, all of which are earning interest currently, and the Board is in the process of reviewing alternative investment opportunities for the surplus cash to improve our interest earning capabilities. We will be looking at as always, low-risk liquid investments with high credit rating counterparties.
And would you mind to tell us more about the background for a relatively high cash income tax paid during the year, which amounted to $15 million, I think.
Are you referring to the additional tax payments made in Q1?
Just looking for 9 months reporting, I'm not sure if that was in the third quarter or earlier? Is it just a cash income tax paid, which is on cash flow statement, $15 million, I guess?
Yes. Yes, $15 million. This will be our normal operating income tax, arising from operations under the tax code. But that, of course, will -- due to the timing of tax payments that, of course, will relate to the earnings for 2022, paid in 2023. And of course, we typically pay a small proportion of expected profit towards the end of the current tax year, and then the bulk of the payments will be paid in 2024, for example.
And very theoretical question. Assuming Chinarevskoye field is fully depleted and you only operate as midstream business purchasing Ural Gas from Ural Oil & Gas. What would be your cash fixed cost in that case, I suspect, general administrative expenses should largely remain unchanged, right? But what would be your cash cost -- cost of sales and selling and transportation expenses in that case?
Yes. I don't think we're at the stage, obviously, any forward guidance on numbers for 2024 onwards. I prefer to keep comments to results for the current year if possible.
But maybe let me put it differently, what is the typical gross margin for the kind of -- for this kind of [Indiscernible] business? I mean, for condensate processing for which you will get $8 per barrel as a fee. What is the typical gross margin for this kind of businesses? Is it possible to quantify now?
I think this is something that the company is still evaluating and looking at in the context of contracts that it has [Indiscernible] and I don't think we can disclose that information right now.
Okay. Okay. And with this tie-up project with Ural Oil & Gas, do you still expect it to be completed by the end of the year or closer to the end of December or may be even earlier?
I don't know if Arfan is possibly better...
Yes, I can. Yes, thanks, [Nikita], for your question. Look, as far as we are -- the operator, of UOG, they haven't informed us of any change other than the fourth quarter start-up. So I mean, we understand that its stretch target for this quarter to start up, but we have not received any official notification from the operator that they will not be able to start up in the fourth quarter.
We'll now take our next question from Charlie Sharp at Canaccord. Please go ahead.
Just a question really on Chinarevskoye. And I'm wondering if with the 2 wells that you're reentering and sidetracking and the various workovers that you talk about. Plus, I think you indicated in the presentation, optimization of product marketing. Is there anything that you can see with that operational program that might be able to increase the oil and condensate volumes relative to where they are at the moment from Chinarevskoye.
Yes. Thanks, Charlie. Good question. I mean we are producing everything we can. We have what we call integrated production system capacity and which represents the full potential that the field can operate at without any -- taking into consideration, any constraints. And so our targets or daily effort is to try and deliver as close to full potential as possible.
So we're not trying to be clever with holding back production relative to product pricing or any other matter we produce to the limit, everything that we can. And then, of course, we manage the other end on the marketing side to try and maximize or improve our netbacks across each product line.
Okay. That's good. And just a follow-up on Stepnoy Leopard, if I may. The 2 wells that you're appraising now can you give us some idea on what sort of results you would be happy with in order to push ahead with let's say, a Phase 1 development -- pilot development program. What sort of perhaps flow rates indicative and maybe hydrocarbon mix would satisfy you?
Yes. I think the -- yes, there's -- again, different product lines come in at different valuations. We don't think that -- I think it's really confirming that our base case scenario around a phase scheme is validated. We already have a working model and technical evaluation that gives us a reasonable sense of what we need in order to achieve economic viability of a Phase 1, let's say, scenario. And I think our data gathering campaign is really targeting to ensure that we will get an appropriate level of calibration and validation of that plant. So it's sufficiently derisked strategy that we're pursuing, and we'll be taking, of course, gas samples, determining the condensate yield, determining the fluid contacts, the producibility of the wells and all of those things come into play when you're trying to develop a field. So I think the simple answer is that we need the full suite of data across -- both in terms of the fluid composition, the fluid levels and the producibility.
That's great. And then just to remind me, have there in the past been any wells tested on that group of fields? Or is this the first testing?
No, there has been tested. Yes, a lot of the wells -- there've been over 100 wells drills. So there's quite a few wells that have been tested. But we want to reconfirm, again, this is fairly old vintage data subject to interpretation in the accuracy when it comes to the specialty accuracy of the data. So we are -- now we're carrying out a very selective data gathering campaign with intention to achieve a high degree of accuracy with our data. So the results are reliable and would reduce uncertainty in terms of going forward with our resource base.
I don't see any more questions in the queue. [Operator Instructions]. We'll take our next question from [Sergey] at Stifel.
Congratulations on the strong results. So I just have a couple of questions. If you can confirm that utilization rate of GTUs 1, 2 and 3 last quarter? That's the first question. And the second question is on the [Indiscernible]. If you can just maybe elaborate a little bit on the use of funds in case the consent solicitation is successful. And if you can also summarize the threshold levels, including the quorum that you need in order to pass the consent solicitation, a little bit confused in the way it's awarded in the press release.
Sure. I'll take the first one, Petro, if you don't mind, handling the second one, is that okay? Yes, so utilization, look, across the -- if you're looking at the full 4.2 bcma capacity, our utilization is well below 10%. And whether -- we can generally use [indiscernible] to handle all of our production. And as we explained, what we had done with GTU3 start-up, which is 2.5 bcma, we put the other GTUs on sort of warm standby, and that's how we operate. So we don't -- we try and of course, that's for us to optimize the cost. So we don't have to run all 3 units because it's much more costly. So we look for that. But overall, as a percentage of the total capacity, we are well below 10% utilization.
Great. My apologies. Could you just quickly repeat the second and third questions, please.
Yes. Sure. So you guys have announced the consent solicitation this morning. So 2 questions with respect to this consent solicitation. The first question is what will be the use of perceives if that consent solicitation goes through? And the second question, if you can just summarize what percentage of approvals you need from, I guess, from bondholders and what quorum you need in order for that consent solicitation to the products. I appreciate that some of this information is in the press release, but I will very much appreciate if you can summarize it -- [Indiscernible] manner.
No problem, thanks for repeating the question. Yes, so the purpose of the of the announcement of consent solicitation is indeed to obtain consent from the note holders, which we are required to do under the terms of the trust deed that was signed in early this year, February, it took effect in February 2023. Currently, we are not allowed to -- there are very restricted uses of the money that the company holds in the blocked account, which is a pledged account under the terms [Indiscernible] which is a pledge account secured under terms of the trust deed. We would like to earn more interest on our surplus funds. Most of those funds actually sit at any point in time in our blocked account. But under the current terms of trust deed, we are not permitted to use those funds -- invest those funds effectively. And we wish to earn more interest on those funds. The market rates today are higher than the rates we are running currently. So that is the main purpose of the consent solicitation process to enable the company to invest moneys from a blocked account to improve the interest earning capacity of the company.
So the plan is not to increase your CapEx spend or to maybe engage in another acquisition?
No, that is not the purpose. I mean, one of the permitted uses of the blocked account, subject to the approval of note holders and the Board is, of course, to invest in approved capital expenditures. But we are not currently committed to invest those funds in higher interest-earning investments. So that is the main purpose of the change, no other terms -- no other principal terms of the trust deed or debenture will be affected. And then in terms of the process, we launched the process, as you say, this morning. It could be a 21-day notice period to convene the meetings. This means that the first meeting, I think, will be on the 12th of December. And there'll be 2 meetings, that will be a meeting of the same secured note holders and a separate meeting on the same day of the senior unsecured noteholders. The quorum requirements for the first meeting would be 75% of all the noteholders that would represent a quorum. If we don't achieve that threshold at the first meeting on the 12th of December, then we would move to a second meeting with an additional 7 days’ notice. The quorum at the second meeting drops to 33% instead of 75% of noteholders in both groups, obviously. The voting threshold that either of the 2 meetings, either the first or if we need it, the second the voting threshold would be the threshold for reserve matter. This will be a reserve matter of trust deed, and that voting threshold is 75% of noteholders present and voting. I don't know if that...
We will now move on to our next question from Dmitry Ivanov at Jefferies.
Thank you for the presentation and for the update. I have 2 quick questions, if I may. The first one, could you please remind us about your oil -- crude oil offtake agreement, when does it expire? And how do you see pricing -- oil pricing in this context for the next year in terms of the benchmark, in terms of the discounts because if I remember correctly that you are facing certain discounts to Brent. I mean, like if you can provide any color on your expectations on the renewal -- on this offtake agreement and any price expectations, it would be very helpful for us.
And the second question, if I may, on Ural Oil & Gas [Indiscernible] field. I think you mentioned that the latest update on the greater that the first gas is expected by year-end -- this year-end. I'm just curious how do you see gas volumes going into Nostrum GTU? So what's the expectation for the first gas processing because I think you are still -- you have it ongoing project. I'm just trying to understand when do we -- should we expect the first gas process that [Indiscernible] in terms of the timing, in terms of the ramp-up and the potential like benefits on the EBITDA free cash flows. So any color would be helpful.
Let me try that, Petro and then certainly we'll need your help to answer fully. So thanks for your question. I think directionally on, our offtake will -- contract will end, end of this year, and we'll be updating the offtake contract for next year. We are out in the market, talking to the off takers. As you know, this year, we have done extremely well with our netbacks compared to 2022, and these improvement because we were in 2022 exposed to the very heavy Ural discount, which was on all over $30-plus per barrel and which we were able to get away from. And in '23, I think we've done very well, and that improved netback has helped us tremendously cushion the impact of the declining production.
And our strategy remains very much aligned with what we achieved this year is to try and make sure that we can continue to improve our netbacks across crude and condensate specifically, and we'll be looking to going to a next round of offtake agreements for 2024 with that in mind. We are definitely not -- we are going to avoid getting into a situation where we're exposed to the full Ural discount situation with now with the Kazakh crude premium blend coming into the picture, I think we remain confident that we'll have good netback performance in 2024. I mean, I really can't give you much more information than that because we're still very much in the state of flux on that whole topic.
Understand.
Yes, go ahead.
No, I just wanted to clarify that if you can like maybe provide any color on the benchmark. Are you looking to Urals benchmark or [Indiscernible] Kazakh KEBCO benchmark in the next year agreement? Just like if you could provide any kind of color on this benchmarking.
Yes. Look, I mean, if we -- I can't tell you exactly where we'll end up, but what I can tell you is that if we are locked into just the Ural-only benchmark, then, of course, that has a very significant downside impact on our netbacks. And that's the whole thing that we're trying to avoid. What may happen and based on which line, of course, you're going down in either the line to [Usluga] or to [Indiscernible] there are a number of other outlets through Druzhba. So it all depends where we end up, which corridor we end up flowing through. But even in the instance where we are exposed to Ural benchmark, we're going to be trying to offset that with the Kazakh crude premium.
So our strategy is that we need to achieve the best netback possible. And if it means we may have a combination of benchmarks coming -- employed to get there, then that's what we'll do. So that's our game plan for the time being. On Ural Oil & Gas, look, I explained that the operator, Ural Oil & Gas is the operator. They have not informed us of any delay beyond the end of this year. And so I mean, I can't technically go out there or obviously go out there and make official comments about any changes in start-up of a third-party tieback unless the operator of that tieback tells us. So for the time being, we continue to operate, we are ready to receive the gas from Ural Oil & Gas. We're totally technically and operationally ready to go.
The ramp-up profile will be -- they have 5 wells to start up, and we're waiting to see how they're going to phase those wells in, in the start-up scheme. So we don't really have clear picture on the exact start-up profile and the ramp-up profile that will be there between now and in 2024. And of course, incrementally providing EBITDA margin and other aspects is information that we have not yet released in the public domain. Was there anything else, Petro? Did you want to add anything else? Or was that...
No. That was great.
Same -- we'll now take our follow-up question from [Nikita] [Indiscernible].
Just 2 quick follow-up questions. Is this 2-well drilling program approved for this year and next year with total cost of $26 million related to [Indiscernible] pricing program?
No. This is the Chinarevskoye program. These are -- we're reentering existing wells, and they are -- yes, they are in the existing Chinarevskoye field, not Stepnoy field.
And with this program, do you want to achieve at least the same level of production you're currently facing?
Oh, no. Not at all. We are -- there are no opportunities that we would say at the Chinarevskoye field that's going to reverse the production decline, if that's what you were talking about [Nikita] because we don't have any such scenario where the production from the Chinarevskoye field could be reversed. It's a mature field with a rapidly rising water cut. And it's -- when we say mature field that most of the low-hanging fruit is gone or has been drilled up and developed. And what we're trying to do is to find infill opportunities that may give us additional production opportunities, which are -- will be economically -- hopefully will be economically viable, but these are -- these opportunities are not risk free.
They can have a significant amount of risk. I mean you can end up in a watered out reservoir or the reservoir quality may be the greater in the area where we are left to sort of drill, short of going into high-risk exploration activities, which, of course, at the moment, we're not contemplating. So they -- these 2 wells will have significant uncertainty, but they should help with some production, but far from reversing the production decline.
And this is basically your CapEx rate [Indiscernible] million?
Sorry, yes, it's around that level for the 2-well program at the Chinarevskoye field.
And what is the idea here because currently, you have an EBITDA of like $35 million probably from this field to spend this $26 million just to...
Yes. I mean, we're not looking at -- this is an investment from , as Petra explained, we use our cash reserves to invest into opportunities for -- in the Chinarevskoye field, there's 2 reasons. One, of course, is we're still pursuing, having done subsurface studies over the last couple of years. We still want to find viable infill targets that could provide some degree of economic return as well as we have to manage our -- and fulfill our license commitments and obligations.
Yes, I mean, you just can't continue without any investments in the field and still maintain your obligations with the regulator. So there's a number of factors that come into play in terms of both ensuring that we can maintain our license to operate, but as well to go into looking at those infill opportunities that provide the appropriate reward to risk proposition.
But what the risk of having this license revoked because...
No, there's no risk. We are in good shape in terms of our license to operate as long as we continue to be responsible both in terms of managing our license as well as ensuring that the investment opportunities that we are able to go forward with, provide a reasonable level of confidence of achieving a return. And that's how that's true with any oil and gas business, yes?
No. I mean, if the ligands revoked, you would need -- no need to invest this CapEx rate.
License is not going to be revoked. We're getting into an area, [Nikita], is not something that we are concerned about at this stage, yes, but we need to still continue to operate as a prudent operator.
And then what -- when this guidance is going to be expired?
Our PSC expiry in 2031.
So does it mean -- does it basically mean that you need to invest tens of millions yet to drill -- to try to get something from this field? Or when you will be able to stop investing in drilling program under this guidance?
I mean, look, no, it's -- I don't think we will be looking at the levels that you are thinking of. I think is part of working with the government to try and understand together what the opportunities are for the investment, and that's what we focus on. And we will fulfill those not only obligations, but ensuring that the opportunities themselves are -- have a reasonable economic return.
Okay. And is the field from Rozhkovskoye is going to become [Indiscernible]?
Well, our goal will be to optimize the product yield. So whether it's GTU3 or 1 or 2, yes, our objective will be to optimize the product yield, yes. make sure that we -- we have the maximum yield available for monetization.
But currently, only GTU1 and 2 is under operation or...
No, we've gone to GTU3 actually entirely, we put 1 and 2 in one stack for the time being.
Okay.
We currently have no questions coming to. [Operator Instructions]. We'll take our next question from Michael Jivkov at Argo Capital Management. Please go ahead.
I just wanted to confirm with regard to the -- your existing field, the mature Chinarevskoye field. You have some kind of undertaking that you have to invest a certain amount in the field annually up until 2031 as part of the production sharing agreement, is that right? And so how much do you have to invest into the field on an annual basis?
Yes. Look, I mean, any field, the work on any field is based on the Field Development Plan that the operator submits to the regulator which defines the level of activity that needs to be carried out on a yearly basis or however the time frame is being established and however the level of activity that's being defined. So it's linked to the Field Development Plan, the FDP that is approved and what we do is the operator then updates that FDP on a regular basis based on new information from subsurface, which is integrated into the studies -- the study work and then help define the development plan going forward.
So if the Development Plan going forward says that the level of activity needs to start winding down, then that essentially work the regulator than approves. So there isn't a disconnect between what is the optimal Development Plan versus regularly just saying that you need to go out there, spend so much money even if it doesn't develop the reserves and it's just to raise the capital.
It's proportionate to the existing volumes and the level of maturity of the field, et cetera, et cetera, there can't be a disproportionality where they say...
Yes, absolutely, your maturity, your level of production all is taken into account in terms of discussing what is the sensible additional activity that should be carried out? And so there isn't some preconceived level that we need to absolutely go out there, spend -- a burn a lot of -- waste a lot of capital. That's not -- that's in nobody's interest. The government doesn't want to do that and cause foreign companies to invest waste capital. So I think the idea is that being a responsible operator and working with the regulator to understand what are the remaining potential opportunities that make economic sense, both for the country as well as for the operator to pursue.
And so from that perspective, that's what we do is continue to annually review and look at what the situation is and where the opportunity is. The 2-well scenario is a classic example of how -- we've gone almost 4 years without any drilling, right? I mean we stopped drilling in 2019, so the 2-well scenario is a classic example of how we look at that together with the regulator and say, okay, here's some remaining opportunities that are worth pursuing and which provides for additional benefit, not only to the state, but as well as the operator has a reasonable chance of achieving economic return.
That was the last question. I will now hand it back to Petro for closing remarks. Thank you.
Thank you very much for [these studies] indeed the last question. Thank you to everybody for attending the call, and wish you all well, and we will catch up again on the next call and goodbye from the Nostrum team.
Thank you all.
Thank you. Ladies and gentlemen, this concludes today's call. Thank you for your participation. Stay safe. You may now disconnect.