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

Good day, and thank you for standing by. Welcome to Nostrum Oil & Gas Financial Results for the Second Quarter and 6 months Ending 30 June 2021. [Operator Instructions] I'd now like to hand the conference over to your speaker today, Martin Cocker. Please go ahead.

Thank you, and good afternoon, everyone, and welcome to this call to present the financial results for Nostrum Oil & Gas for the 6 months ending 30 June 2021. As the announcer said, my name is Martin Cocker, and I'm the interim Chief Financial Officer at Nostrum. I'm joined on the call today by our Chief Executive Officer, Arfan Khan. We'll be following the presentation of the financial results for the 6 months ending 30 June 2021 that's available on our website or through the link in this morning's announcement of results. I need to apologize for a start. I think there was a glitch in the investor deck that was posted this morning, Slide 4, dealing with liquidity. I understand that the bars appeared but not the numbers. But I do understand that this has now been corrected. As usual, throughout the presentation, we'll refer to the page numbers that appear in the bottom right-hand side of each page in the presentation. And at the end, Arfan and I will be available for any questions relating to the results. As per usual, I'll start with an announcement about the ongoing restructuring. As you will be aware, we entered into a forbearance agreement in October 2020 with an informal ad hoc committee of noteholders. Under the terms of that forbearance agreement, certain holders agreed to forebear from the exercise of certain rights and remedies under the indentures governing our 2022 and 2025 notes, including an agreement not to accelerate the notes obligation as a result of the missed interest payments. That agreement reached its longest update in May this year and was replaced by a second forbearance agreement, substantially similar to the first forbearance agreement. The second agreement had an initial termination date of 21 June 2021, which was extended to 21 of July and then again to the 25th of August. In respect to the extension to the 25th of August, Nostrum agreed to pay a further $1.1 million into the restricted bank account so that at the current date, there's approximately $22.6 million deposited on that account. The company and its advisers are in a fairly advanced stage of discussion with the informal ad hoc committee of noteholders and their advisers, but there's nothing further that we can say about the restructuring today. Of course, the company will make further announcements on the restructuring when appropriate but will not be answering any questions on the restructuring this afternoon. For anyone who wants further information on the process so far, there's a further detailed narrative in the interim financial statements and also on pages 28 and 29 of our 2020 annual reported accounts, a copy of which can be found on our website. So turning to the matters at hand, I refer to Page 2 of the presentation. Our earnings for the first half of this year were $92.3 million versus $92.6 million for the same period in 2020. In the first half of 2021, we've experienced improvements in the prices we received for oil condensate and LPG versus those that we received in the first half of 2020. However, the price that we received for our dry gas was lower in the first half of 2021 than the first half of 2020, and also the natural decline in production from the Chinarevskoye field, and our sales volumes were lower this year versus last. We also lost some production in the first half of this year because of the planned shutdown in April and May. The shutdown was completed safely and within budget, but production of approximately 69,000 barrels of oil equivalent were deferred into later periods and approximately 39,000 barrels of oil equivalent lost to flaring. The EBITDA for the first half of 2021 was $52.8 million, which represents a margin on revenues of 57.2% versus an EBITDA of $38.7 million for the first half of 2020 with a margin of 41.8%. This reflects that we have our costs under control. But as I will touch on later, the natural decline in the reservoir is making our cost per barrel of oil equivalent increase even though the underlying cash values of those costs are decreasing. Finally, in respect to the financial results and demonstrating our continued focus on liquidity management, our cash balance at the end of June was $108.1 million compared to $85.3 million at the end of March this year. And that compares again to $78.6 million at the end of 2020. The balance at the end of June does not include approximately $21.5 million that has been put -- that has been placed onto the restricted bank account under the terms of the first forbearance agreement. I'd now like to hand over to Arfan to talk you through the operational and strategic points.

Thank you, Martin. Good afternoon, everyone. Of course, the COVID-19 remains a key issue that we successfully manage our way through and so we remain extremely vigilant. Daily infection rates in West Kazakhstan are increasing, and the area continues to be designated as a red zone. Therefore, we are working with restricted levels of occupancy in the office in Uralsk, testing all employees before shift changes, are taken to field and then regular testing at the field site. We are -- as everyone is doing, it's encouraging our employees and contractors to take the vaccine when offered. To date, we have been successful in our mitigation efforts and continue to see no material impact from the COVID-19 on our operations. In terms of the field performance, average production after treatment for the 6 months was 18,107 barrels of oil equivalent per day, which translated into sales volumes in the quarter of an average of 16,249 barrels of oil equivalent per day. Production is higher than sales, mainly because we use an amount of our production to generate our energy needs. Sales in 2021 are a little lower than normal from the levels of production because we are no longer selling a cargo of condensate every month, and June's production was sold in July. So the volumes of condensate being produced is relatively small, so we have to accumulate the sufficient inventory in order to get a full-sized cargo going. Our production and sales in the second quarter of this year were also impacted by the planned shutdown in April and May, the maintenance campaign, including the GTU and the oil treatment unit. I'm pleased to report that the maintenance shutdown was completed without any environmental or safety-related incidents, and all facilities are now back online. The actual cost of the maintenance work was less than budgeted, and the time that the facilities were off-line was also less than anticipated. So overall, it was a successful exercise, and we confirm the integrity and process safety elements of all of our operations and facilities. Our 2021 well work intervention program also kicked off and some more I'll touch on in a few minutes. More on the strategic issues, as I think everyone is aware, our key priority is to utilize the spare capacity in a world-class gas processing plant of 4.2 bcm per year that's available by sourcing the nearby third party and/or acquiring additional proven reserves nearby. We are working hard on this and believe that we're making some good progress. I meet on a regular basis with potential partners to explore how using our process facilities is for everyone's advantage, including a stakeholder in Kazakhstan. And I meet with the national government because progressing -- processing gas through our facilities and having it available for local distribution is very much in line with Kazakhstan's clean energy ambitions. However, for the moment, I hope you can appreciate that the detail of the conversations that are ongoing must remain confidential. And as soon as there is something to report, then we will make the appropriate announcements. We recently announced that we have agreed with Ural Oil & Gas LLP that delivery of first gas and liquid condensate can be delayed from 9 April 2020 to 31 October 2023. We fully appreciate the reasons for the delay, but we are also working alongside Ural to see if there are ways that the lost time can be made up and the original deadline met. On the restructuring, Martin has already made the customary announcement that will now be answering any questions. He will also give a short overview of the status of the process in a few minutes. I would just like to say that a lot of hard work has been put into the restructuring because everyone concerned understands how vital a successful conclusion to this process so that Nostrum can press on with the projects to utilize the spare capacity in the process facilities without the question of our financial stability. We have entered into an agreement to dispose of the Rostoshinskoye license subject to the satisfaction of various conditions precedent, including the reset of all relevant regulatory approval. This follows the disposal of the Darjinskoye and Yuzhno-Gremyachinskoye licenses in late 2020. The appraisal period for Rostoshinskoye expired in 2022. And given the group's other priorities appraising this license area no longer fits with our strategic objectives. And finally, it gives me great pleasure to announce that we have appointed a new Chief Financial Officer. Shane Drader will join us on 30 August following a comprehensive recruitment process. Shane will be based in Uralsk rather than London and has significant experience in both our industry and the region, having been most recently the Head of IPO at the National Company KazMunaiGas, and before that, holding several roles at KazMunaiGas Exploration Production. We're confident that Shane will make a significant contribution to the future success of our business. Martin will step down from his role as interim Chief Financial Officer on the same date, but will continue on the Board and be designated as an independent non-exec director member of the Audit Committee, Nomination Governance Committee, Remuneration Committee and Health, Safety, Environment and Communities Committee. The Board recognizes that redesignating Martin as an independent non-exec director does not fully comply with the core government standards, however, Martin has been central in the restructuring process so far, and the Board and advisers don't want to lose that knowledge and experience. In addition, as you'll be aware, we have lost 3 non-exec directors in the last year. So the Board assessed that would be very difficult, if not impossible, to recruit quality resource to the board until the restructuring is completed. So to lose another director at this time would make it difficult for the remaining directors to cover all the bases. So we will, of course, explain all this again in the 2021 annual report. I now move to the top of the Page 3. This graph shows quite clearly the natural decline in the production from the field. The decline in production was flattened out to some extent in 2020 because successful well intervention workover campaign in spring and summer of that year. That helped to mitigate the decline. Most of this benefit from this program was, in fact, seen in our oil production. We started a similar campaign in March this year. The program is currently for 6 workovers out of 20 interventions with an expected cost of about $7.3 million. As of today, we have completed work on 2 wells with encouraging results. We're also considering an extension for this program into late 2021 and early 2022. As I've said in the past, these workovers intervention campaigns are not game changers, but rather they represent a very cost-effective means to enhance well productivity at a very rapid payback with the associate boost to short-term cash flow. In terms of guidance, I think we retained that given previously nearly 17,000 barrels of oil equivalent per day production with 16,000 barrels of oil equivalent per day available for sale. This sort of wraps up my summary. I will now hand back over to Martin.

Okay. Thanks, Arfan. If we stay on Page 3, the bar chart at the bottom of the page highlight that whilst we continue to manage our costs in cash terms, as is noted in my comments on the EBITDA earlier, the average cost per barrel is creeping up as the reservoir flow rates decline. Cash costs in second quarter '21 were $17 million against $14.7 million in quarter 1. The increase quarter-on-quarter in 2021 is explained by the cost of the planned shutdown, the start of the workover and intervention campaign and indexation uplift in salaries that apply from April this year. The cash cost for the half year to 30 June 2021 were $31.7 million versus $33.2 million in the second half of 2021 and $40.8 million in the first half of the year 2020. Therefore, we are demonstrating a reduction in actual cash cost, which is a reflection on the work we've done in the last 18 months to manage those costs. However, in dollar per barrel of oil equivalent terms, our cost in the first half of 2021 were in total around $10.20 against $8.60 in the second quarter of 2020 and $9.70 in the first half of '20 -- in the first half of 2020. If we adjust for the cost of the maintenance program in 2021 and the consequent lost production in sales and the cost per barrel in the first half of 2021 reduces to around $9.50 per barrel equivalent. So still an increase in the per barrel basis, but explained by the underlying natural decline in the field. Of course, as the field continues to decline, then we are likely to see increases in the cost per barrel in the future, even though we are managing the underlying cash costs. We will, of course, continue to be careful on all areas of expenditure, but we also recognize that Nostrum supports a number of enterprises local to Uralsk in the wider Kazakhstan region, many of which are struggling as a result of COVID-19. As a result, we are mindful always that obtaining the best price now might not be the optimum strategy in the medium to longer term. And therefore, whilst we remain on target for 2021 to bring in operating and G&A costs, excluding the cost of restructuring at a total of no more than $43.4 million, we note that there are increasing pressures, not least of which is to ensure that we are as fair as we can be with our local supplier colleagues to ensure that they generate a fair return and can operate robust businesses. However, we remain confident that we can manage these pressures successfully. If I turn now to Slide 4. The graph highlights the point I made earlier on liquidity management. Cash at the end of June was $108.1 million, up from $85.3 million at the end of March. At current product prices, we are cash generative over the coming quarters. And so assuming a successful bond restructuring and combined with our ongoing liquidity management, then we should be able to generate the financial capacity for some limited growth-related expenditures in 2022 and onwards. If I turn to Page 5 and the debt restructuring, this represents a summary of the more lengthy notes in the interim financials. In summary and as often said, everybody is working hard. We are mindful that 25th of August is not too far away. And we remain confident that all parties want the process to be successful. We will, of course, make further announcements when we have further news to convey. And with that, I will conclude the presentation. Thank you for listening. And if anybody has any questions, we'll be pleased to answer them.

[Operator Instructions] Your first question comes from the line of Michael Carter from Powerhut GmbH.

I wanted to get one thing on -- I don't think it counts as talking about restructuring. The restricted cash, is that -- who is the legal owner of that restricted cash? Is it the creditors? Or is it the Nostrum? Who has legal title to the restricted cash?

Okay. If I can take that, at the moment, Nostrum has legal title to that restricted cash. And there are various things within the forbearance agreements that enable us to access that cash in certain circumstances, but we haven't needed to access that cash so far. Does that answer your question, Michael?

Yes. Yes. And the last quarter, I remember asking with the production decline, if there was a chance of any turndown on GTU1, 2 on one of the trains or something. Is that something you're looking at? Because I assume production could be reaching the point where you have to make such a decision.

Arfan, can I hand that one to you, please?

Yes, sure. Yes, Mike, I remember your question from the last time. We don't anticipate any turndown issues on Train 1 or 2 because we can operate each train separately. And if we need to, we can bring one into a warm stack mode. So we don't see any concerns about turndown for the foreseeable future.

So you plan to continue operating both trains?

That is correct, yes. For the time being, yes. And then if it gets to a point where we need to bring one down on a one stack, then we can just operate a single plant.

Understood. And is there any update on the GTU3 repair?

GTU3 repair is -- I think, is well in hand. We're just waiting for the right assessment to progress that. Of course, we are working to secure third-party commercial opportunities in order to make sure that we can demonstrate long-term value from GTU3.

Okay. And does the UOG delay, if they come in, in October as now announced, how does that affect your sort of plant utilization forecast?