Serinus Energy PLC

LSE:SENX

Earnings Call Transcript 2023-Q3

[Operator]

Good morning, and welcome to the Serinus Energy plc Q3 2023 Results Investor Presentation. [Operator Instructions] The company may not be in a position to answer every question received during the meeting itself. However, the company can review all questions submitted today and publish responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll. I would now like to hand you over to CEO, Jeffrey Auld. Good morning to you.

[Jeffrey Auld, executive]

Good morning. Thank you. Welcome, everyone, to the Serinus Energy plc financial results for the 9 months ended the 30th of September. My name is Jeffrey Auld. I'm the CEO of the company. With me is Stuart Morrison, the COO; Vlad Ryabov, the CFO; and Calvin Brackman, our Vice President of External Relations and Strategy.

Production for the quarter averaged 641 barrels a day. That was 117 barrels a day for Romania and 524 barrels a day equivalent for Tunisia. Tunisian production has remained stable. We carried out a listing in October of 56,600 barrels, and we got a price of just over $85 a barrel. The [ Chouech ] field continues to increase production and exceed expectations. As investors will know, we've installed artificial lift and pumps in that field, and we've been very successful in having those pumps increase their life from -- initially when we put the pumps in, they were lasting about 8 months. We now have pumps that are exceeding 24 months. So that is a real effect on the economics of those pumps. Installation of artificial lift Sabria-W1 was planned when we did the work over at W1. As people know, W1 ran into junk in the well that was -- it was going to take us to 85 days to go through it. The sidetrack will be about 22 days. So economically, it was just preferable to go and get a clean portion of the whole by means of a sidetrack. The sidetrack design and the target of the sidetrack has been completed, and we've started tendering to the long lead items.

One of the big determinants of when we'll be able to do that sidetrack is rig availability, and we're out looking for rigs and availability right now. As people know, rigs -- there are not a lot of rigs in Tunisia, so finding the proper rig does take some time. And so that will be the major determinant of when we do that sidetrack and when we're ultimately able to get a pump into W1 well.

Sabria N-2well was a well that had never produced, a damaged completion in the hole when it was originally drilled. We went into that. The sidetrack was -- very effectively removed all the damage completion. We perforated that well. The well is dewatered and a slow rate.

We want to go in and [ outsize ] that well so that the dewatering is more effective. And the water pulls -- the dewatering pulls water out of the fractures and allows the oil to come out of the matrix. We're negotiating -- we're discussing with our partner these simulation technics to enhance that dewatering so we can get to see oil. That is ongoing.

In Romania, we've had an extension to the exploration phase of the Satu Mare concession. We completed that at the end of October, and that was granting another 4-year extension to the exploration phase. And in that, we'll do some seismic reprocessing and will require some more 2D seismic. That will help us identify where we go next for gas in the Satu Mare concession.

In the Moftinu field, we have a number of zones that are not completed. There are higher zones when we originally drilled producing wells that produced in the Moftinu gas plant. Those zones were bypassed to go for deeper and more -- and bigger ones. And as we complete those lower zones, we will move up the wells. We'll complete those zones that we'll bring that gas into production. Those are light workovers and could be done fairly quickly. The timing of that depends, really, on our internally generated capital and how we deal on the depletion of the deeper zones.

We are still waiting for the remaining course to recognize the ICC award, that award at the 40% of the operating interest that we've been operating for the last 6 years, and the Romanian courts are not the fastest courts in the world.

The Canar-1 water injection well was originally drilled as an exploration well for gas. We found gas of noncommercial quantities. We turned that well into a water disposal well for the produced water that comes out of the other wells. So far, up until the end of the third quarter, we've saved about $600,000 on our disposal piece to that well. And the cost of that well has been paid back from the water disposal. I'll hand it over to Vlad, so he can run through the financial numbers. Vlad, do you want to go through these?

[Vlad Ryabov, executive]

Thank you, Jeffrey, and yes, I will. So the revenue for the 9 months ended September 2023 reduced to $13.3 million from $48.1 million in the comparative period of the previous year, which is a result of dramatic changes from the commodity prices throughout period. The gross profit for the announced 9 months of the 2023 was $1.8 million, and the EBITDA for the 9 months of the 2023 was $1.2 million, reduced from $12.6 million, again, as a dramatic result -- as a result of dramatic changes in [indiscernible] expenditure.

And overall, the company reported a net loss of $4.6 million in the 9 months -- for the 9 months of 2023, which compares to $3.4 million income of the previous year. Capital expenditures of $5.3 million in the 9 months 2023, fully, out of Tunisia, $4.8 million, which is also done in [ 25th ] of August; and Romania of $0.5 million, which will depend on the full extension of the Satu Mare concession and the Canar-1 water injection pumps and this is in the Moftinu area.

The company realized net price of $76.84 per barrel of oil equivalent for the 9 months of 2023, which compares to $162.18 per barrel for equivalent in 2022. As we can see, there is a dramatic change in the commodity prices throughout 2023. And the realized oil price is $78.68 per barrel in Tunisia, driven [indiscernible] Tunisia, and the realized natural gas price is just about $12 per Mcf, which compares to $36.66 per Mcf on the comparative period of the previous year.

The netback reduced in line with the commodity prices and comprised $34.15 per barrel of oil equivalent in 2023, whereas it was -- the netback in the comparative period of 2022 was $120 per barrel of oil equivalent. Romanian operating netbacks are dramatically lower as a result of dramatic changes in the commodity prices throughout the period and comprised $4.22 per barrel of oil equivalent in the 9 months of 2023, which compares to $195.73 per barrel of oil equivalent in 2023.

Tunisian operating netback has been more stable, but again, they were heavily impacted by the global commodity prices and oil and gas prices in 2023 and comprised $40.68 per barrel of oil equivalent in 2023, which compares to $59.11 per barrel of oil equivalent in 2023. The company reported cash balance at the end of September 2023 of $1.5 million, which compares to [ $5 million ] at the end of 2022. The cash balance as at 15 November 2023 was EUR 3.5 million, which is a result of the completion of portfolio which the company completed in the middle of October 2023.

This slide summarizes and [ visibly show ] of the -- graphically show of the revenue, gross profit, cost of sales and net income. We touched on the revenue and on the cost of sales. The cost of sales decreased $11.5 million from $30 million in 2022, due to significantly lower direct taxes and royalties, which are coming from Romania and are leading to the realized prices in Romania.

The company managed to optimize our OpEx with significant controls around the operational expenses, which led to a reduction of those by 28% against 9 months of 2022, despite the higher reinflationary environment, which we all are experiencing in the 2023. The gross profit was $1.8 million as we saw on the previous slide.

And we can go to the next slide and look into the average production volumes. Jeffrey said before, in Romania, we are experiencing a [indiscernible] in production due to a natural decline and the loss of 1 well. The Tunisian production has been very stable as part of the workover program which was under by the company in the 9 months of 2023. And the average realized price of $76.84 per barrel of oil equivalent is going to reflect the lower Brent price and dramatically lower gas prices in Romania. Production expenses decreased from $8.2 million in 2022 to $5.9 million in 2023. And that's based on Tunisia and Romania, with Tunisia incurring 3.8 million of production expenses in the 9 months of 2023 and Romania going $2.1 million. Group production expense of barrel of oil equivalent of $34.14 per barrel of oil equivalent and that based on Tunisia and Romania as shown on this slide.

Operating netbacks, again, reflect the significantly lower cash prices and volumes in Romania versus comparative period with an average realized price being $76.84 per barrel of oil equivalent. And we're looking to the realized price of the netback on previous slide. The capital expenditure reduction on the previous slide was $5.3 million was placed to Tunisia, $4.8 million and 0.5 million in Romania. In Tunisia, we incurred the CapEx from Sabria W-1, artificial lift program and Sabria and the workover. And just above $1 million of the capitalized inventory purchases for the upcoming workover in Tunisia. The group's funds from operations were at $1.3 million, whereas Tunisia is contributing just a little bit, again, and Romania is using funds of $700,000 and the corporate fund at the corporate level is at $4 million. Overall, the EBITDA was $1.2 million, which is a significant reduction from the previous year EBITDA of $12.6 billion. And the key trigger here is the dramatic changes in the commodity prices in 2023.

[Jeffrey Auld, executive]

Yes. Thanks, Vlad. I think to sum it up, we've had significant drops in commodity prices. In the face of that, we've managed to cut expenses. There is -- these per barrel numbers in Romania are obviously affected by the denominator as the production goals, and we work to reduce the cost of that operation.

Environmental and safety, we continue to focus on the safety and the environmental aspects of our operation. We've had no lost time incidents in Tunisia of 2,854 days, and in Romania, 1,618 days. In Romania, that's no lost time incidents since the start of production, the start of the plant. We've installed solar panels in Moftinu to further reduce the electricity consumption.

And we've just completed our environmental modeling -- monitoring for the 2 business units, which looks at all our fugitive emissions, looked at all our plants and we report that in our annual report. We have those fugitive emissions gas emissions audited by third parties, and you can find the results of those audited reports in our annual reports and those will be forthcoming in our annual report.

So the company continued to generate stable cash flow. We have $3.5 million of cash in the bank at the 15th of November. The asset base provides opportunities both in Romania for finding and developing another Moftinu-style field. We have the large oil asset in Tunisia that is subject to those workovers.

Going forward, we hope to be able to get the N-2 well dewatered and have that producing. We'd like to get the asset stimulation job done, but that really does depend on the conversations with our partner. And the sidetrack design for W1 and the long-lead items are being procured. And as I said, rig availability is going to be one of the key, key items to when we are able to get that done. That will be in 2024. We're just trying to find a way to figure out when exactly in 2024, we can plan. In Romania, we talked about the block-wide geological geophysical study, that's to enhance the knowledge for the next phase of exploration program, moving beyond the Moftinu area. Remember, the Moftinu gas plant cost $7.8 million to build, and another probably $6 million or $7 million to drill the wells to it. And we've announced previously that we're closing in on $100 million of revenue out of that plant. So the shallow gas projects, they don't last that long, but they really do generate you great credit returns.

The 2D seismic program that we're planning and that we committed to, in the extension of the exploration period, is designed to find the next Moftinu gas field. So there's good exploration opportunities in Romania, and then there's excellent opportunities to work a big oil field and just produce that oil and feel better. We've shown we can do that in flesh, and we're working hard to try to do that in Sabria.

Going through this very quickly. The workover event, the only thing we haven't really talked about is the workovers on Moftinu 1003 and 1007. We'd like to see those in the first half of 2024. But as I say, that's dependent on how the depletion on the lower zones go. What we don't want to do is open up those upper zones, which are higher pressure and higher flow until we've gotten all the gas we can out of the lower zones. If you look back at all of our reserve reports -- historical reserve reports, we've outproduced what the reserve engineers -- independent third-party reserve engineers anticipated out of Moftinu. We'd like to continue to extract all the gas we can out that before we move to higher zones and open those zones up for production. One main guidance for WIN-12 artificial lift. After we've completed the installation of artificial lift in the W1, we'd like to turn our attention to our best-producing well, which is WIN-12bis, and we'd like to put a pump in that as well. And so the long lead items for that are being procured in 2024. And again, depending on how W1 goes, when we can get that sidetrack done, once we have some performance we can show our partner from that sidetrack, we'll move on to the WIN12 well.

That is -- that concludes the presentation. I'll hand it back to our moderator.

[Operator]

[Operator Instructions] While the company takes a few moments to review those questions submitted today, I would like to remind you that a recording of this presentation, along with a copy of the slides and the published Q&A can be accessed via investor dashboard. Jeffrey, Vlad, as you can see, we have received a number of questions throughout today's presentation. And Jeffrey, if I may hand back to you and kindly ask you to read out the questions, give responses where appropriate to do so, and I'll pick up from you at the end.

[Jeffrey Auld, executive]

First question, how can we get a copy of the summary of the geological review you completed this year and the general structural figures? The short answer that, you can't. We conducted a geological review over the Satu Mare concession. That is proprietary information where we used our proprietary seismic and our well results, tied together, the other seismic we have on the block, and that is proprietary information to the company, so we don't circulate technically sensitive information like that, and we don't plan to. What we plan to do is take that information to allow us to drill new prospects in Satu Mare. The next question, our cost and CapEx seems to grow or shrink to match the revenues, but there's never anything left for shareholder returns. That is not entirely true. Our costs have consistently been compressed. We've done a very thorough job of managing our costs. And our CapEx does grow or shrink to match our operating cash flow, not our revenues and that's simply because we take the operating cash flows that we generate and we reinvest them in the field for growth.

So we are attempting to grow the business. And quite simply, if we -- I gave the example of the Moftinu field, finding another Moftinu field is a very high-return prospect. And so we take our capital and we invest that in either increasing production out of Tunisia, which we've very successfully done in Chouech or we look to expand our production, increase our production, and quite frankly, find another Moftinu field in Romania. So this is a growth company. We reinvest and we run our business based on the capital that's available to us from operating cash flow.

The next question, the share price remains suddenly below the net asset value, which remains there for quite some time. Not only does it remain below the net asset value, where -- the share price is essentially trading at cash. We have $3.5 million of cash at the middle of November. This is incredibly frustrating. We believe that the company generates consistent cash flow. When we do find a field in Romania, we get a big spike in production and cash flow, but those are short-lived fields, so we keep looking for the next one.

So we find it very, very frustrating that independent third-party reserve engineers reports, which are on our website, show an asset value -- a net present value, including abandonment, including the capital required to invest to get that value of in excess of $70 million, AND yet our share price remains stubbornly low. What are we doing to overcome this? Well, we try to show everyone those simple numbers, and we try to show people the deeply discounted value of this company.

This company has great assets and have performed well in those instances, and certainly, we've had times when we haven't been successful. We drilled 2 exploration wells in Romania. Both of them found gas but not commercial gas. That was very disappointing for the company, but it only takes one of those to produce commercial gas to make a big result for the company. Are we considering selling any concessions? We consider buying and selling all the time. It's a question of price. At the valuation that our shares are giving us right now, our assets are far more valuable generating cash flow for us than they are selling them. But of course, I still come through my career with everything is for sale. It's just a question of price. So no, we're not actively out there starting to sell any of our concessions. We've looked at whether there are ways to enhance value. But so far, the value is best generated by generating cash flow.

Next question compared to management's previously highly successful records than other companies and critically much better shareholder returns, how do your expectations for Serinus compared to one, of those higher bars? And two, original expectations for joining Serinus? Well, I'll speak for me personally. We maintain those high bars. We expect to make the returns that we've done in the past. We've taken steps to do that.

How does that compare to the original expectations? Well, when I originally joined the company, the company had $60 million of debt and 300 barrels a day of production. It's been a long process and hasn't been entirely in our control, but we've managed to eliminate that debt. We've managed to develop the Moftinu gas field from what was a corn field when I joined to that picture that's on the front of the presentation, a gas plant that produced $100 million -- close to $100 million of revenue. The expectation is to continue to take these quality assets and work the assets, generate cash out of them and grow the business. That continues to be our expectation.

We mentioned, yes, court case in the Romanian courts are pretty slow. What is the impact of that, if any? There is no -- and the further down the question, we're not waiting for any compensation back to revenue. No, it's simply a frustration. For 6 years, we have, in our presentation and in all of our reporting, called a deemed 100% interest in the Satu Mare concession. In March, we received the final arbitration award, which awarded us 100% of the concession, so we no longer call it a "deemed." 100% -- it is 100% ours.

Romania is a signatory to what's called the 1958 New York convention on the recognition of arbitration awards, which basically means the state of Romania recognizes arbitration awards. This is just a procedural impact, procedural effect of getting the court to recognize, in Romania, an arbitration award.

What practical effect does it have on us? It doesn't have any practical effect anymore after the arbitration award. But prior to that, we really couldn't look at bringing a partner in. We have 100% of this block. Philosophically, we're not a business that needs to have 100% of our blocks. We'd like to have partners. Without that arbitration award, we were not able to bring a partner in.

So in the future, and this reverses the previous question, would we bring up partnering to the Satu Mare concession on acceptable terms? Absolutely. Partnerships mean that there's more brain power. There's more people looking at things and there's a spreading of the risk. As I said, we don't have to have 100% of this concession. We would like to have a partner and, really, what the OE, the case did was prevent us the ability to have a partner. That's no longer the case.

There's no back compensation. There's no outstanding revenue. We paid 100% to build the Moftinu plant. We took 100% of the revenue. We paid 100% of the tax. There's 100% of the insurance, so we have, for 6 years, acted de facto as 100% operator. And now it's simply -- we've been given 100% for the arbitration. What are the company's plans to return shareholder value? Well, we have had a shareholder vote last AGM that prevents us from buying back our own shares. So effectively, we're left at a position where we we'll take our operating cash flow and grow the business. And we believe that the market should credit that when we do grow the business.

The company went through production -- when we're at the peak production from Moftinu, we were at 2,700 barrels a day for the period and the market slowed us down to that. So it's been a very, very difficult fight to get market recognition. Next question, sorry, kind of slow here. A question, what does the company make of [ Axcelis ] taking a 7.5% holding over the period of October, November 2023. I'm afraid you'd have to ask [ Axcelis ] . We're thrilled to see investors coming in. That's a great business, and they've taken a significant holding, but I really can't comment on what their motivations are, other than they see another valued company that's a good opportunity.

Can you give us time frames on getting rigs in Tunisia at all? Could it be a year? 2? 6 months? What is the time frame? This has always been a challenging one. We compete for a very, very limited number of rigs in the country. I would say 6 months to a year is the best guess. There are rigs that we do not believe are appropriate. And so it's an even limited -- a smaller number of rigs.

I would suspect we would have an ideal outcome on the rigs by midyear where we would get that availability. But we've found in the past that the right rig make a great deal of difference when you're in operations. We don't want the wrong rig. We don't want a rig that's going to break down in the middle of operations, et cetera, so it's really very important to get the right rig and do your checks and get that rig certified properly before operations start. How long do we expect dewatering into wells take? Well, at the current rates, a long time. We very much feel that optimizing that, which is which is a very standard procedure, will accelerate that dewatering and accelerate it quite significantly. And so what we're doing here is there's fractures that run through this reservoir that are filled with water, and we know that from our other wells. And you need to drain that water out of the fractures so that the oil, which held within the matrix structure of the rocks can move into those fractures.

So you have to draw enough water out to get the pressure difference to allow that oil to come out of the fractures in the rock. At the current rates, it's very, very hard to ask me how long will it take, but it's not in a time frame that we're comfortable with. If we ask that and open up all the preparations that we put into it, we think it would be very -- much, much, much quicker.

One of the overhead costs that we've reduced, we've reduced cost of offices all over the board. We've reduced the cost of our operations in the field. There's efficiencies in things like how we're ordering our propane for compression. Certainly, one of the overhead costs we've reduced in water disposal. We talked about the Canar-1 instead of paying -- instead of trucking our water to someone else's water disposal well, we've converted one of our exploration wells as water disposals. So it's cost like that, but it's all over -- the business cost had been reduced across the business.

And that is the last question, so I will hand it back to our moderator.

[Operator]

That's great. Thank you for that, Jeffrey and Vlad. And I think you have addressed those questions you can from investors today. And of course, the company can review all questions submitted today, and we will publish those responses from investors on the company platform. But before we direct investors to provide you with their feedback, which is particularly important to the company, Jeffrey, Vlad, please, I ask you for a few closing comments.

[Jeffrey Auld, executive]

Thank you. Thank you for joining us. The results are we're a stable business generating cash flow, taking that cash flow to invest it. I think that the business -- Tunisia is certainly not going as quickly as we would like. It's a place that it takes -- we would like to have moved right from finding the junk in the hole in W1 to a sidetrack right away. That's what we would prefer.

But the country and the ability to get equipment and services in there just doesn't allow that sort of speed, so we press on. We remain confident in these assets. There's a great exploration opportunity in Romania, and we continue to have sweating the asset in Tunisia. It's a great asset. There's lots of oil there. We've just got to get it more faster. Thank you.

[Operator]

Jeffrey, Vlad, thank you once again for updating investors today. Can I please ask investors not to close this session as you will now be automatically redirected to provide feedback in order that the management team can better understand your views and expectations. This will only take a few moments to complete and I'm sure will be greatly valued by the company.

On behalf of the management team of Serinus Energy plc, we would like to thank you for attending today's presentation, and good morning to you all.