Hello, and welcome to the Nostrum Oil & Gas Full Year results for the Year Ending 31st of December 2024 Conference Call, hosted by Arfan Khan, CEO, and Petro Mychalkiw, CFO. Please note this conference is being recorded, and for the duration of the call, your lines will be on listen only. However, you'll have the opportunity to ask questions after the presentation. This can be done by pressing star one on your telephone keypad to register your question. If you require assistance at any point, please press star zero, and you'll be connected to an operator. I will now hand you over to Petro Mychalkiw to begin today's conference. Thank you. Thanks, operator. Good afternoon, everybody. Welcome to this call to present the financial and operating results of Nostrum Oil & Gas Plc for the year ended 31st of December 2024. My name is Petro Mychalkiw. I'm the company's Chief Financial Officer, and I'm joined today on the call by Arfan Khan, our Chief Executive Officer. We will follow the format, as usual, of our full-year results presentation available on the website in the Reports and Presentations section. As usual, through this presentation, we will refer to page numbers that appear on the presentation slide deck. I'll now hand over to Arfan to begin our presentation. Thank you, Petro, and warm welcome to everyone joining this call. Hopefully, everyone can hear us okay. Please refer to the information contained on pages 3-6 of the presentation. Just a quick summary: 2024 has been yet another busy and successful year for the company. We delivered strong operational and financial results. We advanced our mixed asset strategy and solidified our position as a major third-party gas processor in Kazakhstan. On the strategic highlight side, Nostrum achieved significant Stepnoy Leopard project milestones during 2024 and early 2025. In April of 2024, after successfully completing our two-well appraisal program, we took a final investment decision for the initial phase of the field. This was followed by an independent third-party competent persons report in July with an estimated 138 million barrels of gross 2P reserves, yielding an economic value of $220 million after tax and PV, and a 34% real return. In addition to the 2P reserves, the field also contains 67 million barrels of contingent resources, which provide further commercial upside for the opportunity. In April of 2025, we secured approval from the Ministry of Energy of the Republic of Kazakhstan for a phased full-field development plan for the Stepnoy Leopard Field extending until 2044. This phasing allows the company to deploy optimum capital allocation, much meeting its target production startup date between late 2026 and early 2027. On the U O G side, our collaboration with Ural Oil and Gas has led to, obviously, a very successful [audio distortion] project, and we expect this to continue accreting significant value for both parties with further development of the Rozhkovskoye field. In March 2025, as was announced, we entered into a binding agreement with Ural Oil and Gas to extend the processing of the hydrocarbons on new terms until the end of the license expiry, which is May 2031. This agreement extension is value-creative, mutually beneficial for both parties. The new fixed processing fee structure across all products generates sustainable cash flows and supports planned operations, substantially increasing the utilization of Nostrum's world-class processing facilities. This approach helps establish a robust, growth-oriented business plan for the next decade. Operationally, we have focused on delivering operational excellence with 98% processing facilities uptime and continuous operation of the Q3 since restart in September 2023. In 2024, Nostrum saw significant growth in both process volumes and title production. We saw a 48% year-over-year increase in title production volumes, raising our average daily title production to 14,935 barrels of oil equivalent per day. This growth was driven by additional gas and LPG from Ural Oil and Gas Processing, as well as additional production from the limited-scale drilling program and efficient well workover intervention activities. A 94% increase in process volumes, combined with effective cost control, led to a year-over-year 41% reduction in operating expenses per barrel of process volumes from about $10 in 2023 to about $6 per barrel in 2024. To mitigate the natural production decline of our general square fields and meet our license commitments, we have focused on targeted drilling, well intervention, and production optimization. In 2024, we successfully drilled the No. 301 well on time and within budget, and it was put into production in May of 2024, with inflow rates meeting our expectations. We also drilled well No. 41 for an appraisal sidetrack to the upper Devonian gas-condensate horizon. We have already been producing from this horizon, so this was an offset to an existing producer. The targeting of the sidetrack was driven by amplitude, as we did not have any other well control. Unfortunately, the well missed the primary target by a few hundred meters. It did encounter secondary intervals that were hydrocarbon bearing, but they proved to be marginal, so the well was put on a temporary suspension. The key data that we acquired, particularly in order to calibrate our seismic amplitude, is yielding quite a significant level of understanding on the reservoir architecture, and this will help and improve our confidence in future well planning. Financial highlights: the main focus is to ensuring that we deliver strong performance and driven by increased third-party processing volumes, efficient management of our upstream and processing operations, as well as effective cost control. We delivered a year-on-year 14.6% increase in revenues to roughly $137 million and a circa 16% increase in EBITDA to roughly $49 million. That's against a mature declining asset. We maintained strong liquidity position with $33 million net positive operating cash flows and unrestricted ending cash and cash equivalents balance of $150 million, which would have been $178 million, excluding one-off cash flow items. On the HSC and ESG side, safety continues to be our foremost priority. In 2024, we reinforced our commitment to a strong safety culture and rigorous operating standards, achieving a record of zero fatalities and no lost-time injury incidences. We maintain a strong ESG performance, ranking the 11th percentile among oil and gas producers in Sustainalytics' ESG Risk Ratings, reflecting our focus on responsible operations. Whilst our greenhouse gas emissions increased primarily due to processing of third-party feedstock from Ural Oil and Gas and increased operating footprint, we improved operational efficiency and reduced emission intensity by 28%. That wraps up my brief summary. Let me please hand it over to Petro to run through our financial performance in more detail. Thank you, Arfan. Thank you for the information in our presentation deck on slides 7 and 8 and 10 through to 12. We achieved significant improvements across the board in our financial KPIs during 2024. Despite $1.60 lower average Brent price in 2024 compared to 2023, we increased revenue by just under 15% to $137.1 million, driven by higher process volumes and higher title production. EBITDA increased by over 16% to $48.9 million, with our EBITDA margin increasing slightly to 35.7%, strictly achieved through our high revenues, effective cost controls, despite inflationary pressures and our operational demand. Our operating expenses per barrel of process volume reduced by 41% year-on-year from $9.80 per barrel to $5.80 per barrel. Similarly, our G&A expenses per barrel of process volume reduced by 49% year-on-year down to under $2 per barrel. These reductions mainly reflect our improved economies of scale. We also recorded on balance sheet an $87 million impairment reversal in our non-current asset carrying value, and this was primarily driven by the accretive value of our growth catalysts, such as Ural Oil and Gas processing and the Stepnoy Leopard Field's development opportunity. Dates to comment on our strong cash performance in 2024, as Arfan has already mentioned, we generated $33.1 million of net operating cash flow before well [audio distortion], which funded most of the turnover through drilling costs and Stepnoy Leopard Field's appraisal expenditures during 2024, as well as the semi-annual bond coupon payments in June and December 2024. As a result, we only drew $11.3 million from our group's unrestricted cash reserves during the year, and we ended the year with an unrestricted cash balance of just over $150 million. Our net debt position at the end of 2024 was $404.2 million, an increase compared to 2023, reflecting the capitalization of $51.8 million of senior unsecured loans at peak interest, and a $47.8 million fair value amortization, and a net $11 million reduction in cash and cash equivalent in BSRA. This concludes our presentation today, and I'll ask the operator now to open the floor for questions. Thank you, sir. As a reminder, if you would like to ask a question, please press star one on your telephone keypad. If you change your mind and want to withdraw your question, please press star two. Please ensure your lines are unmuted locally, as you'll be prompted when to ask your question. As a reminder, star one to ask a question. The first question comes from a line of Dmytro Dyachenko from ICU. Please go ahead. Hi everyone, can you hear me? Yeah, we can hear you. Yeah, yeah, okay, thank you. Arfan, thank you for the presentation. I hear several questions, and the first question is about the CapEx. Could you please provide some guidance for the capital expenditures for this year and for the next year, 2026, and specifically for [audio distortion] Stepnoy Leopard, how it is paid? Thank you. I can take a stab at it, Petro, and certainly anything that you want to add, please feel free to do that. Thanks, Dmytro. Good to hear from you. Outside of the, we're not planning any major capital expenditure in 2025, Dmytro, other than obviously meeting our obligations for [audio distortion] license retention, which means that we would probably still be looking at a couple of low-cost sidetracks. I believe it'll be in the $10 million-15 million range that we'll be looking at for that statutory requirements for the sidetrack and drilling operations. Beyond that, I think the level of CapEx required to mature to actually go into a construction phase of the Stepnoy project is still being sort of defined and optimized, so I don't really have any hard figures to give you on that. Directionally, I mean, we obviously are trying our best to back and lower the sort of spending capital requirements to reach the startup of the field, which we still target for end of 2026-2027 timeframe. Our goal would be to try and minimize as much as possible the upfront capital outlays. Okay, thank you. The next question relates to UOG. The presentation mentioned that agreement was extended last month, yeah? Under new terms, would you please elaborate on what these new terms are? I mean, I'm happy to, I think we provide some clarity that we've moved into purely a tolling fee arrangement across the three primary products, the gas, the LPG, and condensate. There is a fixed tolling fee that they will be paying. That's the fee arrangement that we have entered into. Previously, if you recall, we took title to gas and LPG, whereas in this update, we've decided to move to a fixed fee structure and not deal with any of the other risks and uncertainties, the uncertainties of pricing and whatnot. For us, it provides a reasonable level of security and sustainable predictability of our cash flows. I think that's about as much as I can give you. The commercial terms themselves, unfortunately, we are not able to provide that to the public at this point. Okay, thank you. And besides the UOG, is there any progress with other third-party suppliers, like Karachaganak, for example? I mean, look, the door on the Karachaganak is never closed. I think in the end, the KPO field, the shareholders of Karachaganak, the major companies, and the Republic of Kazakhstan will need to reach a decision about the way forward. There is a gas plant to be built, and it is our understanding that the country is moving towards, and the shareholders are moving towards building their own standalone plant, which we do not know when that is going to happen. There has been no firm decision yet taken on a project sanction, but I think directionally, that is where they are headed. That does not mean that our opportunity is fully closed because in the end, the country is going to need every processing capacity that they can get their hands on, given the rapidly rising demand for domestic gas. We are keeping our options open and certainly the door open as well to the Karachaganak option. Thanks. One more question about shipments or feedstock from UOG. If I understand, the volumes will be close to the volumes in the last quarter of last year, like this 1.5 million cubic meters per day, yeah? You mean for the foreseeable future or for the rest of the decade? What I intend to hear is some guidance for volumes for the UOG feedstock for this year and for the next year, for example. Oh, I see. Look, as far as we are waiting to hear from UOG, what their volumes will be, I mean, obviously, I cannot put volumes out there for what UOG intends to supply unless that information is already out in the public domain. You appreciate that because it's not our field, so we cannot be speaking on behalf of UOG in providing you with any forecast about the production from the Rozhkovskoye field. UOG has to provide that information, release that information first before we can sort of reiterate or summarize, you see. What we can say is that the long term, I believe this information is already in the press, Petro, in terms of what the long-term peak target that the field is expected to reach. Do you remember if it is one bcma or something? I mean. Please go ahead. KNG, yeah, hi. KNG disclosed that they expect to produce a total of 0.53 billion cubic meters of oil gas during 2025. That is the only public disclosure they made around plant volumes for 2025. Okay. I have two questions, two more questions. The first question is about EBITDA margin. I'm asking because the margin averaged around 35% in 2023-2024, but reached almost 30% in the final quarter of the year. Should we expect that 30% level to continue this year? Some guidance, for example, for expected margin because we actually don't know volumes from UOG shipments. We don't know new terms, at least some margin expectations for the entire business. Yeah, I mean, we haven't provided, as you say, we haven't provided margin guidance for the year 2025. You know what I can say is that obviously the margins of Q1 and Q4 reflect the throughput volume, the economies of scale driven by throughput volumes from UOG. We have a very large, we have a substantial fixed cost base in our operations, over 50% of staff costs, which is predominantly fixed. We have over the remaining 50%, you know we have a significant portion of that that is also fixed. Volume is very much an entirety of the factors that really determine the primary factors that really determine margin. Right, I can't give you guidance on that right now, obviously. The current fixed structure for UOG, of course, stabilizes some of our income, but it's still subject to UOG volume. I can't give you a very simple answer to predict margin through 2025, but hopefully you'll understand that there's a lot of guidance factors behind the margin calculation. Okay, but as I understand, the margin should be at least close to the levels in previous years, like around 35%, not lower. I mean, pricing is one of the key factors to margin, obviously. Now we're changing to the tolling fee structure, of course. The UOG pricing is in the tolling fee structure, so I'm not sure we're able to disclose that right now. I think it's difficult for you to have a view of my questions going forward, but I'm going to try that as much as we can disclose right now. Thank you. The last question relates to digital healthcare. We have guidance for this year, like on the midpoint 6,000 for equivalent. What is the actual breakdown between products? Because all production and sales are presented on the consolidated basis. What is the actual production volume of oil gas, for example? Because GTU 1, 2, and 3, they need some volumes to be on production, like around 2,000 barrel of oil equivalent. Will the sufficient gas produced in general care meet this need or not? I mean, I can tell you what operationally, Dmytro, we're not operating all three plants. We obviously put one and two on standby, and then we operate GTU 3. That's how we manage. We don't have any issues in terms of having gas available as fuel to run our operations. Certainly, with now more volumes coming through the system, we expect the plant to be fairly robust and stable for many years to come. In terms of the breakdown between the products, don't we put something in the R&S? Yeah, we have a breakdown in the presentation back on page six. We're not able to split gas, LPG, between turn-off screen production and UOG production, unfortunately, because again, of our operational obligations with UOG. But the overall mix for turn-off scale, and we're giving guidance in the R&S of the expected level for 2025, between 5,500 and 6,500 of all equipment, the mix of those products will be similar to 2024. I don't expect, and if you look at FY2023, for example, in the presentation back on page six, for FY2023, of course, we really only have a very, very small amount of feed through UOG. UOG feed only started, I think, on the 21st of December. You know 2023 product mix, I think, is relatively comparable to 2024 for turn-offs only, and it wouldn't be too far off for 2025 either. Okay, it was very useful. Thank you. I don't have any questions now. Thank you guys for your presentation. You're welcome, Dmytro. Thank you. Again, to join the queue for questions, please press star one on your keypads. The next question comes from a line of Charlie Sharp from Canaccord. Please go ahead. Thank you very much, and thanks for taking my question. The last caller actually asked pretty much most of the questions I would have asked. A broader question does come to mind. On UOG, you've extended the new arrangement to the end of the current Production Sharing Agreement, which is, I think, May of 2031. Just thinking about the longer term, most of the UOG reserves and potential resources will be recovered post-2031, and I expect also the same is true for Stepnoy Leopard. Is there any chance that you might be able to extend your license period to be able to make use of those resources and reserves post-2031? Thank you. Thank you, Charlie, for that question. Good to hear from you. Look, I mean, we, of course, see this massive opportunity for us beyond 2031. Indeed, we intend to submit a request for PSA extension. We're already working on it, and we will be engaging with the regulator at the appropriate time. It is very much our intent to progress and pursue the extension of the PSA. We could reasonably assume that that might be extended for 10 years, for example? Oh, I mean, on that one, I think we would expect that the PSA extension will involve negotiations. What the terms and the periods will be, I think it's far premature for me to start drawing a line in the sand on that, Charlie. Okay. That's helpful. Just turning back to UOG, from memory, there was some cost associated and CapEx associated with the initial tying in of the five wells at UOG into the Rozhkovskoye facilities. I'm just thinking, if the partner at UOG decides that they do want to expand production significantly, would there be any further CapEx required on your side? Would there be any additional operating costs associated with those increased volumes? Is there, in any case, a tax associated with the new tariff structure? Look, it's a good question. Of course, part of our process fee structure that we've agreed reflects and incorporates what the future opportunities would be. I can't give you really a breakdown on all of that. The additional CapEx, from a CapEx standpoint, it'll be minimal on our side. The bulk of the CapEx will be on the UOG side, given that they will likely need to drill additional wells and so on and so forth. From a cost standpoint, I think, again, there will be, of course, impact on cost due to treatment and whatnot and logistics aspects. Of course, we take all that into account in arriving at an appropriate fee structure. That's already been accounted for, in my opinion, Charlie. Okay. Just on the tax issue, will effectively the revenue be rolled through the Rozhkovskoye fiscal terms, or will it be treated separately with a separate taxation? No, no. Go ahead. Go ahead, Petro. Yeah, thanks Arfan. The UOG activity, the UOG income, both under the previous agreement and the current agreement, is the non-PSA activity for Zhaikmunai. It does not follow the tax structure of the production sharing agreement. It follows the standard current tax code. There will be different, it follows the standard CIT rate. As you can see, that income stream is accounted for separately from the PSA activity. I'm sure you just remind me of that rate. I thought it was 20%, but it may be different. Yeah, 20%, yeah. 20%. 20% corporate income tax rate, yeah. That's great. Thank you very much. Thank you. We currently have no questions coming through. As a final reminder, if you would like to ask a question, please press star one on your telephone keypad. There are no further questions, so I'll hand back over to you, host, to conclude today's conference. Thanks very much, François. No more questions. Obviously, I'm happy to wait a few seconds to see if anybody wants to ask a question. If there are no more questions, then obviously, thank you to everybody for joining the call. I think the annual report and the R&S and the presentation are obviously available for you to review after the call. As I've kind of explained, I think it's been a very, very busy and very productive and emotional performance year. Thank you very much for everybody attending, and we will catch up mid-year when we present the half-year results. Thank you all very much. Thank you for joining today's call. You may now disconnect your lines. Thank you.