Good morning, good afternoon, and welcome to Ventura Offshore's Q3 2025 earnings call. My name is Guilherme Coelho, I'm the CEO of Ventura Offshore, and I would like to thank you all for joining us today.

Joining me today are Marcelo Issa, our CFO, and Olav Revheim, our financial advisor, and we'll provide you an overview of our performance between July and September of this year, an overview of the market, and at the end, open for questions. As usual, questions are to be made in writing, use the Q&A item you can see on the top of your screen, okay?

You write them down, and at the end of the session, I'll read them out loud and answer them. Thank you.

Next slide, please, Lars. That's our disclaimer.

We're used to, okay. First off, we were very pleased to announce in Q3 our customer Eni declaring the second of the four optional wells in Indonesia for the semi-submersible Catarina, adding an estimated additional backlog of $10 million, which is a testament to the great work done by our teams onshore and offshore on the rig.

The Catarina has delivered 99.2% operational uptime last quarter with safe operations with more than 2,000 days with no lost-time incident. 2,000 days and counting.

Also happy to report, and this is not in the document share presentation you see because we just got notice that Eni intends to exercise the third optional well as well, which will take us well through Q2 next year, with a potential backlog addition the order of $20 million. Upon that confirmation, we'll have just one remaining optional well yet to be exercised, and we continue to be positive that it should also occur, which will take then the rig to Q3 of 2026.

Moving on to Q3 operational performance, and thanks for the work of our exceptional crews and support teams onshore, I was very pleased to see our operational results for the fleet back towards alignment with our historical performance with an average of 95.6% uptime. On other key highlights for the quarter, in Q3, Ventura Offshore has delivered an adjusted EBITDA of $19.7 million and net income of $22.3 million.

We maintain our industry-leading cost structure, operating with an average opex of $113.8 thousand per day, excluding ancillary service for the Catarina, which are fully reimbursed by the customer with a markup margin. We closed the quarter with a strong cash position of $35.5 million after repaying $9.5 million on the RCF.

Our firm backlog now stands at $576 million, not including the third optional well to be exercised by Eni. Could you move to the next slide, please?

Next slide, Lars, please. Thank you.

Going back to our backlog, you can visualize it how it is spread in years to come. The $576 million that I mentioned is our firm backlog and is represented by the darker green bars, taking us to firm contractual commitments all the way to 2029, while the existing options not yet exercised are represented by the lighter green bars and add up to more than double the firm backlog number and could potentially take us all the way to 2033.

As for rigs, both the Carolina and the Victoria continue to operate for Petrobras in the Búzios field under their current contracts until Q2 of 2026 next year. Carolina has then an out-of-service period for contract preparation before starting the Sépia-Atapu contract that should take her to 2029 or potentially 2033 if all options are exercised.

The Victoria remains being actively marketed and has participated in recent Petrobras market inquiries, which results have not yet been disclosed. We'll talk a little bit more about that in the market section.

The Catarina continues, as mentioned, operating on its 12-well base contract for Eni in Indonesia. The exercise of the two additional optional wells, as mentioned earlier, enhances visibility of the duration of this contract, which we now see well into Q2 of 2026.

The last optional well in Indonesia is yet to be exercised by Eni, and if exercised, it will take the rig into Q3 of 2026. Finally, our managed rig, Atlantica Zonda, is performing extremely well considering it has barely 6 months of operations, and has delivered an almost 96% uptime this quarter with no lost-time incidents.

Actually, this rig has not experienced any lost-time incident ever since we got involved in this project 795 days ago. As a reminder, this is a three-year firm contract taking operations to 2028 with three additional optional years, which could take her all the way to 2031.

Finally, and before I hand it over to Marcelo, our CFO, a quick comment on the Carolina interdiction. We have no news yet to share.

Discussions with Petrobras are ongoing, and we expect a conclusion still end of the year or more likely early 2026. As and we're going to talk about it, Petrobras has been very involved in the renegotiations with their key suppliers, I think this has been put a bit on the back burner while this other initiatives is concluded.

With that, I'll hand over to Marcelo Issa, who will cover the financial highlights for our third quarter of 2025. Marcelo?

Thank you, Guilherme, and thanks to everyone for joining Ventura's earnings call. In Q3, Ventura generated a total adjusted revenue of $57.5 million, and this was composed of $53.9 million from the operating activities of our three owned drilling rigs and $3.6 million in management fees.

The income statement reports $73.2 million for the revenue related to the drilling services. However, it's important to highlight that this includes $19.3 million from the amortization of non-favorable contracts, which is a non-cash item.

Ventura remains committed to keeping opex low. Total opex for the quarter was $32.1 million, including the ancillary services provided to the clients.

Excluding these services, the average opex amounted to $113.8 thousand a day. The SG&A for the quarter is $5.7 million, and as a result, the adjusted EBITDA for the period stands at $19.7 million.

Our final free cash position in Q3 is $35.5 million, and during the quarter, we made a $9.5 repayment to the RCF. With the RCF utilized, decreased from $28.3 million in Q2 to $18.8 million this quarter, split between $9.3 million in cash withdrawals and $9.5 million in a guarantee issued for the Eni contract.

We have $11.2 million available under the RCF. There is $21.4 million in restricted cash held on behalf of the owners of the managed vessel.

The bond loan was amortized by $10 million, and the gross interest-bearing debt in Q3 stands at $504.3 million. Next slide, please.

Looking at the balance sheet, accounts receivable includes $13.7 million related to Eni contract, $27.8 million to Petrobras, and $17.6 million for the managed vessel with Petrobras. The capex in Q3 was $3.5 million, of which $2.5 were related to items for Carolina's new long-term contract with Petrobras.

I will now hand it back to Guilherme for some market highlights. Thank you.

Thanks, Marcelo. I'll now quickly cover the the the market conditions and then open up for for questions.

I thought maybe we want to start off by addressing a concern or question that most of you may have, or the elephant in the room, which are those renegotiations with Petrobras. What are those all about?

What is the impact for Búzios and Mero tenders? How does that affect Ventura?

Actually, I already got the first question, and that's exactly what the question is about. Basically, as you all know, Petrobras' expectation for sustained lower oil prices, around $65—actually, just last night, Petrobras published their five-year plan, and it's actually $63 for '26 and $70 thereafter—have led them to revisit their plans, focus on addressing short-term cash flow concerns, prioritize projects with greater return, and look for smart ways to reduce costs while maintaining similar level of activity, and I think this is important to stress.

In that context, they have invited several of their key contractors, well services, subsea companies, and drilling contractors, in an initiative called the Renegoc to have those discussions. We have also been invited, obviously, and we have had a few meetings with with Petrobras, as have all our competitors in Brazil.

I must say it's been collaborative, good meetings. Several options have been brought to the table, and discussions are evolving, but we have not come to a conclusion yet.

We believe it to be Petrobras aims to close all discussions by end of this year, but I do not believe this to be set in stone, it could be that it drags on to early '26. Again, I think that if thing go goes the way Petrobras is expecting, they they will be closing out everything by end of December.

Let's see. Now, one of the main impacts or the immediate impacts of the Renegoc is that both Búzios and Mero market inquiry process are now components of this big puzzle Petrobras is putting together.

Understandably, conclusion of Búzios and Mero is tied to the conclusion of those discussions. I know there have been, and we've read about this, some concerns voiced about those process being canceled, and I do not see that.

Of course, anything is possible, but if if we just stick to the facts, there are currently six rigs operating in Búzios. Búzios just reached 1 million barrels per day with expectation to go to 2 million barrels by 2029.

Five new FPSOs FPSOs expected to come, in additional FPSOs, right, between '26, '27, and one beyond 2030. The way things are today, Petrobras will be down to one rig by end of 2026.

If you just do the math, there is a need for rigs in Búzios. I see the process happening moving forward.

It just we just might not see announcements happening this year. We do continue to have an optimistic view for our rig Victoria.

Now, that being said, and as we all know, Petrobras just published late last night their new five-year plan. Same as you, we're still going through the report.

It's a thick presentation, 150 slides. We're still going through that to digest and come up with our own conclusions.

Main topics of interest, I believe, are the 1.8% reduction in investment for the period of '26 to '30. It's about $2 billion.

However, on E&P, the number is about 1% higher, $78 billion now versus $77 billion in their previous five-year plan, but with significant more projects under evaluation. With respect particularly to rig count, Petrobras indicates an need for two rigs less in comparison with their last five-year plan.

Again, we're still in process of reviewing this to come up with our own conclusions, but I anticipate that the numbers disclosed by the Petrobras five-year plan are not necessarily a surprise to us, and they actually came in higher than what the market was commenting in in some in some remarks over the past couple weeks. Those numbers, they certainly do not change how we feel about recontracting opportunities for the fleet and the Victoria particularly.

However, if we look around the most recent oil and gas market developments in Brazil, they're invariably very auspicious. Starting with the obvious Equatorial Margin licenses and the start of the drilling campaign, this has been in the works for 13 years now.

You're all aware of the great hopes Petrobras and the country have for the potential reserves to be found. Here's interesting to note that in their five-new-year their new five-year plan, Petrobras has not reduced the number of exploratory wells to be drilled in the Equatorial Margin.

Then you add to that the fact that BP announced their largest find in 25 years, the Bumerangue field in pre-salt Santos Basin. Then just last week or a couple weeks ago, Petrobras announced a new find of oil of excellent quality, and these are the words taken out of Petrobras PR, not my words, oil of excellent quality in Tartaruga Verde in post-salt Bacia de Campos.

Again, Campos Basin post-salt, not pre-salt, right? Today, 80% of Petrobras production comes from from pre-salt.

Post-salt Campos Basin was the North Sea in Brazil. Nobody was believing anything would come out of it, and all of a sudden, you have this this major find from Petrobras.

Again, just adding to the the the number of of good news we've been hearing in Brazil. Then again, all the record-breaking Brazilian oil agency, ANP, rounds this year, bringing huge investments not only from Petrobras, but also from Exxon, Chevron, Equinor, Shell, Karoon, etc., in Campos, Santos, Pelotas, and Equatorial Margin basins.

I think if I if I make a quick pause here, if I circle back, the investments by the likes of Exxon and Chevron that I just mentioned, those were made in blocks in the Equatorial Margin. If I remind you that the Equatorial Margin geology extends from the northern part of Brazil all the way up and west to Guyana, and then I point out that Exxon and Chevron are the operators in major blocks in Guyana, that should give all of us some idea of how these companies, who know this geology quite well and have benefited from it, feel about the Brazilian Equatorial Margin potential.

Finally, and we've heard this from Petrobras CEO, it's part of their five-year plan, the previous one and their current one, and we heard from her loud and clear in the latest OTC Brasil edition now in in October, reserves replacement is vital to the future of Petrobras. Quite a few positive data points about the future of the Brazilian offshore drilling market, I would say.

Now, moving away from Brazil for a minute and looking Southeast Asia, where the Catarina is operating right now. Initially, I wanted to reiterate that we're very happy with the partnership with Eni and the future visibility into the duration of the current contract.

We see Eni very actively advancing its development strategy in Indonesia through ongoing pre-qualification tendering processes. While these are aimed at dual-activity drillships, the deployment of additional assets in the region reflect Eni's commitment to reinforce Indonesia's status as a prominent global oil and gas hub for them.

This is in line with broader industry trends emphasizing deepwater exploration and production expansion within Southeast Asia. We're seeing opportunities in India, East Timor, Malaysia, and we remain actively engaged with prospect clients and looking at those opportunities and showcasing the Catarina capabilities.

If we were to summarize a little bit our our market view and what I just went through: one, immediate concerns on sustained lower oil prices have led Petrobras to call in key contractors to negotiate; two, conversations are in good level and looking at ways to optimize costs while preserving the contract returns, the contractors' returns; three, impact on ongoing tenders is more about timing than it is about whether or not they will move ahead; and four, Petrobras' new five-year plan has marginal investment changes, but do indicate a two-rig reduction in their rig count, which I do not necessarily lose my sleep over. I guess the last point is that the overall market indications and all data points in the Brazilian offshore oil and gas market remain positive.

Next slide, please. That closes our presentation.

This is our our standard slide about about our position in Brazil, our proven track and and and low cost structure and scalability for the future. That closes our presentation, and I couldn't close it without thanking our teams onshore and offshore for delivering efficient and safe operation to our customers in Q3, maintaining our industry-leading cost structure, and positioning the company so well for the opportunities for recontracting our rigs.

I also wanted to express express my appreciation to our shareholders, partners, and customers for their continued trust in Ventura Offshore. With that, I close our presentation, and we'll open for questions.

Again, as a reminder, there is a Q&A icon on your screen, on the top part of your screen. You can write down your questions.

I'll read them out loud and and answer them, either myself or Marcelo. I already have a first question, which is actually is a pretty long question, I'm going to try and go through it.

It's from Fredrik from Clarksons. Some of your questions, Fredrik, have been answered, okay, in the course of of our presentation.

I'm just going to focus on the questions that have not been addressed, all right? He had a general question about how the renegotiations with Petrobras are going.

I think I have addressed this. The next one is, could this impact the already signed contract for the Carolina?

May these discussions also have an impact on the scope and length of any potential award for the Victoria on the Búzios tender? We have not had any discussions about about renegotiating the Catarina—the Carolina Sépia-Atapu contract, okay?

Now, as I mentioned, our discussions are ongoing, they have not finalized, but so far, we have had no discussions on the Carolina, okay, on the current next contract, the Sépia-Atapu contract. Could these discussions also have an impact on Victoria under Búzios?

Listen, I cannot comment if Victoria is under Búzios or not, but what I can say is just reiterate what I mentioned earlier is that I believe that the Búzios market inquiry will move forward. Contract awards were expected to to occur now in November, but because of the Renegoc, I think they're going to be pushed to early next year.

As I mentioned, and I reiterate, I do not think it's a matter of whether this is going to go ahead, but rather when. Okay.

Next question is about refinancing the debt, and the question is if we could share some light on sizing and timing of of this of this exercise. The refinancing is in the books, this is this is this is not news, you are aware.

We do feel that ideal timing would be preferably on the back of visibility of recontracting of the Victoria, okay? We would estimate sometime hopefully in early 2026 to go through this exercise.

The refi will be in principle in the form of a combination of refinancing of RCF and existing bond. As for amounts, well, we do need to have the visibility on capex requirements, and this is directly tied to the visibility of recontracting of the Victoria.

We we do need to know exactly capex requirements before we can put some numbers to the refinancing, so this this will have to wait a bit before we can give you more more clarity, okay? Current best estimate for capex required to prepare Carolina for the new work.

I think as I have mentioned in the previous calls and in in in industry events, net of mobilization, we estimate in the ballpark of 40 to 45. What Next question, I think this has been answered.

There was a question about the likelihood of the two remaining options on the Catarina being exercised. I think this has been answered on the call.

If you need to find work with other operators or in other regions, what are sensible assumptions for potential downtime on the rig? I think this is this is related to the Catarina obviously, okay?

I think this is highly dependent on the visibility that we have and whether or not the fourth optional well will be exercised. We are seeing opportunities for the rig in 2027, mostly early 2027.

If we see the rig operating, if the fourth optional well is exercised and it does take the rig all the way through well into Q3, probably the remainder quarter of the year is the time that you need for contract preparation, mobilization to other to other countries. There is there is a scenario where we see very little potential downtime for the rig, depending on what what the next opportunity is.

Let's Fredrik, I think I answered all your questions. Let me know if I didn't.

Two questions Next question again is about financing. Can you discuss that refinancing plan in the event Victoria is not allocated a contract in the ongoing tender process?

I I don't think it changes the the timeline we set for ourselves, okay? For one, because we continue to be optimistic about the rig about the rig getting a a new contract, and secondly, because we do have capex requirements for the Carolina for the next contract.

We do anticipate Q1, latest Q2 of next year, as timing for for the refinancing. In the event you do achieve a contract for the Victoria, what that quantum, margin, and award profile and term do you think are achievable?

I already answered this. This is highly dependent on capex requirements, I think we'll have to wait a little bit to see once we have visibility on recontracting for the rig, we'll be able to give more details on on those topics.

Next question: how do you plan to handle the $85 million payment due in April 2027? I'm assuming this refers to the to the to the balloon payment on the So I mentioned we are going to be looking at a refinancing in early next year, this is going to be part of of the plans for the refinancing.

Another question about the refinancing, I think I've already answered. Can you talk about the refinancing for the outstanding bond?

We already mentioned this. One concern Next question.

One concern is the size of potential capex build between contracts for both Brazilian rigs exceeding the mobilization fee by a large amount. Is there any discussion on trading off dayrate against reducing capex and term, particularly in the Búzios tender, potentially dropping the MPD requirement?

As I mentioned, there have been several ideas brought to the table, not only by us with Petrobras, but I'm sure by our competitors with Petrobras, and of course, capex requirements is one of those topics that are discussed. Petrobras is known for having, pretty heavy capex requirements every new contract, even though the rig has been operating in country with Petrobras previously.

This is one of the topics that is being discussed. Potentially dropping MPD requirement is also something that has been discussed, but likelihood is not high.

The new profile of wells, particularly for Búzios, the MPD is something that the operational team in Petrobras does require. Everything is on the table.

MPD, I think, is unlikely, okay. Is there a possibility Next next question: is there a possibility of a new contract with Eni in Indonesia after the ongoing contract?

Eni made an option to go for seventh-generation dual-activity drillships. They have two tenders for for that process ongoing, and in principle, those rigs would take up all the future requirements for Eni, okay?

I'm not counting on that. That being said, we do remain in very close contact with Eni, and they know about the Catarina.

They like the rig. Again, as I mentioned, 2,000-plus days without any lost-time incident, 99% uptime in Q3, it is a rig that's been delivering to Eni, and it's a rig that is in a different dayrate dayrate area that those those seventh-gen dual-activity drillships are.

I'm sure Eni is doing their own math internally, but in principle, at this moment, the the future work for Eni is going to be covered by the drillships that they're looking for. What is the base case Next question: what is the base case Victoria net capex you are currently using for the next contract?

Again, it's it really depends on what the final outcome is and what the contract requires, okay? If you consider Búzios or Mero, you can look at the numbers I just mentioned for the for the Carolina and add a MPD requirement, okay?

That's basically you get to your number. Next question from Nick: do you still expect the same start time for rigs that win Búzios tender?

If so, how do you manage the lead time necessary to order long-lead items to equip the Victoria with MPD capabilities for the new contract? Yes, for the rigs that win Búzios tender, I think the mobilization window remains the same.

There hasn't been a change for the time being, but I'm sure that the the rigs awarded, they are talking about this in their in their individual negotiations with Petrobras. We're talking about early 2027, right?

Assuming contracts are awarded in January or February of '26, you have about a year, which is tight. It's perfectly doable, but it's tight, and MPD is the delivery time for MPD is about 10 months, give or take.

It's you have time, but yes, you're you're you're getting close. It's one of the I'm sure it's one of the of the concerns from the the companies participating.

How do you think the carnival season will impact Búzios awards? Carnival, actually, I don't know when carnival is next next year.

It's between February and March. I believe Petrobras has their their goal internally to have this this finalized before then, okay?

I I would say it does not impact, but it's it's hard to to confirm, okay? I I do not think it's going to impact.

Marcelo, I think the next one would be for you, as a question from Nick: you showed some depreciation and amortization for for your managed rig, $1 million in Q3 2025. What does this relate to, and do you have ongoing capex for the Zonda?

Marcelo, can you take this one?

Sure. No, really, I don't see any depreciation for the managed rig.

Really, I didn't understand your question. Maybe there's something that the capex for Zonda is not recorded in our books.

The capex for Zonda is related to the owner of the vessel. We only purchase capex and we get the reimbursement for them, it's not a cost for us or recorded in our books.

It is recorded in reimbursement expenses.

Thanks for that. Nick, if you want to shoot me an email and clarify the question, but Marcelo is absolutely right.

All the capex for the Zonda are borne by the rig owners, and we do not show them in our books, so. I have another question on Búzios and Carnival, again, I'm expecting it's not going to impact.

What is the average opex dayrate for your competitors? I don't know if I have that information very clearly, but it really depends because different rigs have different types of capex, right?

Our rigs, they are single activity with no MPD, and similar rigs with single activity, no MPD, I would say they're between $130 to $150. If you have dual activity and MPD, then there's extra crews required, you have extra consumables required, this number can go up between $150 to $180.

Next one: are there any interesting growth opportunities in owned or managed rigs within this oil price environment? Listen, I think regardless of the oil price environment, the interest exists, right?

We are having a very successful partnership with Eldorado managing the Zonda. We've had in the past a very successful partnership managing the Catarina before we bought the rig back.

We do have the scalability, we do have the knowledge of Brazil, we are always interested in opportunities that make sense. The oil price environment impacts the dayrates, right?

Again, it goes back to the financials. If they do make sense, yes, we have an interest in growing.

We have the scalability and the capability to do that. Not long ago, we operated six vessels, and it's very easy for us to go back to that number without any major impact on G&A, physical yard space, nothing of the sort.

So. I think this was the last question.

Let me see if there is another one. No, I think that's the last question, I'm going to give it another couple of minutes if there is any follow-up or new questions.

I think that was the last question. I wanted to once again thank you all for your interest in Ventura Offshore and continued support, and we'll talk again in February of 2026.

Thank you all very much. Have a good day.