Nostrum Oil & Gas PLC (NOG) Earnings Call Transcript & Summary

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.