Thank you for standing by. My name is Gail, and I will be your operator for today. At this time, I would like to welcome each and every one of you to the Q2 2025 Helix Energy Solutions Group, Inc. Earnings Conference Call. [Operator Instructions] It is now my pleasure to turn today's call over to Brent Arriaga, Vice President of Finance and Accounting. Please go ahead. Brent Ar

Good morning, everyone, and thanks for joining us today on our conference call, where we will be reviewing our second quarter 2025 earnings release. Participating on this call for Helix today are Owen Kratz, our CEO; Scotty Sparks, our COO; Erik Staffeldt, our CFO; Ken Neikirk, our General Counsel; Daniel Stuart, our Vice President of Commercial; and myself. Hopefully, you've had an opportunity to review our press release and the related slide presentation released last night. If you do not have a copy of these materials, both can be accessed through the Investor Relations page on our website at www.helixesg.com. The press release and slides can be accessed under the News and Events tab. Before we begin our prepared remarks, Ken Neikirk will make a statement regarding forward-looking information. Ken?

During this conference call, we anticipate making certain projections and forward-looking statements based on our current expectations and assumptions as of today. Such forward-looking statements may include projections and estimates of future events, business or industry trends or business or financial results. All statements in this conference call or in the associated presentation other than statements of historical fact are forward-looking statements and are made under the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual future results may differ materially from our projections and forward-looking statements due to a number and variety of risks, uncertainties, assumptions and factors, including those set forth in Slide 2 of our presentation and our most recently filed annual report on Form 10-K, our quarterly reports on Form 10-Q and in our other filings with the SEC. You should not place undue reliance on forward-looking statements, and we do not undertake any duty to update any forward-looking statement. We disclaim any written oral statements made by any third party regarding the subject matter of this conference call. Also during this call, certain non-GAAP financial disclosures may be made. In accordance with SEC rules, the final slides of our presentation provide reconciliations of certain non-GAAP measures to comparable GAAP financial measures. These reconciliations, along with this presentation, the earnings press release, our annual report on Form 10-K and a replay of this broadcast will be available under the For The Investors section of our website at www.helixesg.com. Please remember that information on this conference call speaks only as of today, July 24, 2025, and therefore, you are advised that any time-sensitive information may no longer be accurate as of any replay of this call. Scotty?

Thanks, Ken. Good morning, everyone. Thank you for joining our call today. We hope everybody is doing well. This morning, we will review our second quarter highlights, financial performance and operations. We'll provide our view of the current market and update our guidance for 2025. Our teams offshore and onshore safely delivered another well-executed quarter. Our current safety statistics are among our best on record. Moving on to the presentation. Slide 6 and 7 provide a high-level summary of our results and key highlights for the quarter. As expected, our second quarter results were negatively impacted by the regulatory docking of the Q5000, the transit and demobilization of the Q4000 from Nigeria and the market conditions in the U.K. leading to the continued warm stacking of the Seawell. In addition to these factors, we also experienced a later start to our Gulf of America shelf season, and we incurred a high number of deferred mobilization days at the end of the second quarter on the Q5000, Q4000 and Well Enhancer that have shifted revenues into the next quarter. Revenues for the second quarter were $302 million with a gross profit of $15 million and a net loss of $3 million compared to $278 million in revenue, $28 million in gross profit and a net income of $3 million in Q1. Adjusted EBITDA was $42 million for the quarter and had a negative operating cash flow of $17 million, resulting in negative free cash flow of $22 million. Year-to-date, we have generated revenues of $580 million, gross profit of $42 million and a breakeven net income with adjusted EBITDA of $94 million. Our cash and liquidity remains strong with cash and cash equivalents of $320 million and liquidity of $375 million at the quarter end. Highlights for the quarter include Brazil operating 3 vessels on longer-term contracts, successful completion of operations for the Q4000 in Nigeria and safe passage back to the Gulf of America, deployments of our third boulder grab and utilization in the quarter for all 3 boulder grabs, deployments of the JD Assister and the i-Plough in the Baltic Sea, execution of a 3-year framework agreement with Exxon for shallow water decommissioning in the Gulf of America. And in July, we signed a multiyear minimum 800 days trenching contract for the North Sea commencing in 2027, securing trenching work well into 2030. Over to Slide 9. Slide 9 provides a more detailed review of our segment results and segment utilization. In the second quarter, we continued to operate globally with minimal operational disruption with operations in Europe, Asia Pacific, Brazil, Africa, the Gulf of America and the U.S. East Coast. Our second quarter results were supported by strong seasonal improvements in robotics activity, 3 Well intervention vessels operating in Brazil and the marginal improvements in shallow water abandonments. These were offset by the regulatory docking of the Q5000, the demobilization of the Q4000 and the stacking of the Seawell. Slide 10 provides further detail of our Well Intervention segment. The Q4000 completed operations in Nigeria and a safe transit back to the Gulf of America during the quarter. The vessel then performed a brief shipyard visit for planned repairs, after which it commenced work on a 3-well decommissioning project. Due to some gaps in the schedule on completion of the works, we plan to pull forward the 2026 planned regulatory docking into 2025 to facilitate a clean runway in 2026. The Q5000 worked on 1 well in the Gulf of America in Q2 prior to undertaking planned regulatory 5-year class maintenance and inspection. The vessel is currently working on a multi-well program for 1 client prior to its scheduled return to work for Shell. In the North Sea, the Well Enhancer had 100% utilization during the quarter, working on 4 wells for 3 customers. Due to the well-known market turmoil in the North Sea, the Seawell remained warm stacked and is expected to remain warm stacked at a low-cost base for the remainder of 2025. In Q2, the Q7000 completed work on 5 wells for Shell on the 400-day decommissioning campaign in Brazil. SH1 had 94% utilization working for Trident. And in late Q3, early Q4, the vessel is expected to transfer to the 3-year Petrobras contract with a gap in operations whilst undergoing vessel acceptance. SH2 had a very strong quarter with 100% utilization for Petrobras. Moving to Slide 11. Slide 11 provides further detail of our Robotics business. Robotics had a strong quarter. The business performed at high standards, operating 7 vessels during the quarter, working between trenching, ROV support and site survey work on renewables and oil and gas-related projects globally. Robotics worked 6 vessels on renewables-related projects within the quarter and had strong vessel utilization overall with 3 vessels working on trenching projects. We operated 3 vessel trenching spreads in Europe, including the GC III and the North Sea Enabler with jet trenches and the JD Assister with the i-Plough. The Glomar Wave and the Trym support vessels are working on renewable site clearance utilizing the IROV boulder grabs in Europe. And the Shelia Bordelon completed a small project in the Gulf of America prior to transiting to the U.S. East Coast for renewables works. Also in renewables, we have the T1400-1 trencher working on a longer-term contract from a third-party vessel of Taiwan. And in July, we are mobilizing the T1400-2 on a third-party vessel for a longer-term contract in the Mediterranean. The GC II in the Asia Pacific region performed oil and gas support work offshore Malaysia during the quarter. Our renewables and trenching outlook remained very robust with numerous contracted works in 2025 through to 2030. We are extremely pleased to recently announce that we executed a multiyear 800-day minimum trenching spread contract in the North Sea. The contract commences in 2027 for initial 4-year period plus options, and the long-term outlook for global renewables market is very strong with a solid pipeline of tender activity as far out as 2032. Slide 12 provides detail of our Shallow Water Abandonment business. In Q2, activity though was increased as the season commenced, led by the start of the season for the Hedron heavy lift barge and an increase in utilization with a high number of P&A spreads working offshore. We expect similar or improved activity into Q3. Whilst 2025 continues to be a soft year, we continue to believe in the long-term outlook of this segment as wells age and customers look to reduce their decommissioning obligations. This is further supported by a recent award of a 3-year agreement for decommissioning services with Exxon. In summary, whilst we have seen a softer-than-expected U.K. intervention market and some potential gaps possible later in the year for the Q4000 due to work being pushed back into 2026, we are encouraged by our strong Robotics and Brazil segments, and we are pleased to see improved tender activity with some quite sizable tenders in the U.K. globally. We're expecting Q3 to be a very strong quarter. I'd like to thank our employees for their efforts, delivering again at a high level of execution and for securing backlog and long-term contracts. I will now turn the call over to Brent.

Thanks, Scotty. Moving to Slide 14. It outlines our debt instruments and key balance sheet metrics as of June 30. At quarter end, we had $320 million of cash and availability under the ABL facility of $70 million with resulting liquidity of $375 million. Our funded debt was $319 million, and we had negative net debt of $8 million at quarter end. Our balance sheet is strong and is expected to strengthen further as we anticipate generating meaningful free cash flow in the second half of 2025 and beyond and have minimal debt obligations between now and 2029. I'll now turn the call over to Erik for a discussion on our outlook.

Thanks, Brent. As we provide an outlook for the second half of 2025, our customers are reacting to the uncertainties created by the current geopolitical environment and the financial impact of lower oil prices. Our customers are deferring work in the North Sea and Gulf of America, impacting our Well Intervention and Shallow Water Abandonment segments. We are taking steps to mitigate the impacts of a slower market. As discussed last quarter, in the North Sea, we have stacked the Seawell. In the Shallow Water Abandonment segment, we have stacked 5 of our vessels. This quarter, in response to the slowing Gulf of America Well Intervention market, we have accelerated the regulatory maintenance on the Q4000 into 2025 from 2026. The maintenance period is expected to take approximately 30 days and be performed in the third quarter. This will limit the utilization on the Q4000 during 2025 during this period of slower demand, but is designed to provide greater availability in 2026. In our outlook, we have endeavored to account for the increased uncertainty and risk in our markets. We are adjusting our outlook as follows: revenue to a range of $1.2 billion to $1.3 billion and EBITDA to a range of $225 million to $265 million, both revenue and EBITDA decreasing with the softer Gulf of America Well Intervention market. Free cash flow, a range of $90 million to $140 million, variability driven by EBITDA changes as well as the ultimate working capital movements. Capital of $70 million to $80 million, a slight increase in CapEx due to the acceleration of the regulatory maintenance period on the Q4000 into 2025. These ranges include some key assumptions and estimates adjusting for the current market environment with any significant variation from these assumptions and estimates causing results that could fall outside our estimates and ranges provided. Our quarterly results typically follow a seasonal pacing with more active summer months and slower winter months. For the second half of 2025, we expect the third quarter to be our strongest quarter of 2025 with good contract coverage. The timing of our expected free cash flow generation is concentrated to the latter half of the year. Providing our key assumptions by segment, First with our Well Intervention segment. The Q4000 is currently completing a project and scheduled to commence regulatory docking by the end of July. The vessel is expected to be available in September. We are pursuing opportunities, but do expect gaps in the schedules. Q5000 has strong contract coverage and expected to have high utilization into 2026. As discussed, the U.K. North Sea is weak, and we have stacked the Seawell and are focusing work on the Well Enhancer. The Well Enhancer is expected to have good utilization into Q4. The Q7000 is operating for Shell in Brazil on a firm 400-day project. The Siem Helix 2 is on contract for Petrobras. The Siem Helix 1 is currently performing well abandonment for Trident with contracted work to extend to the end of Q3, followed by a 3-year contract with Petrobras. The vessel is expected to have an approximate 30-day off-hire period as it transitions for vessel acceptance between contracts. Moving to the Robotics segment. It continues to generate positive returns. Bidding activity has been and continues to be extremely active. We recently announced a significant trenching contract in the North Sea, representing over 800 days of trenching beginning in 2027. In the North Sea, the Grand Canyon III is expected to have an active trenching season with overall strong utilization. The North Sea neighbor has contracted trenching projects into Q4. The Glomar Wave and Trym are forecasted to have good utilization performing site clearance operations. T1400-2 is contracted for its first work in the Mediterranean in the second half of 2025. The APAC region, the Grand Canyon II has contracted work through Q4. The T1400-1 trencher is working on provided vessel and is expected to remain in Taiwan through the end of '25. The U.S., the Shelia Bordelon has contracted work in Gulf of America and the U.S. East Coast into Q3 then is scheduled to transition back to the Gulf Coast with good utilization expected into Q4. Moving to production facilities. The HP1 is on contract balance of '25 recently extended to June of '26 with no current expected change. We do have expected variability with production as the Droshky field continues to deplete and Thunder Hawk field is shut in. Continuing our Shallow Water Abandonment segment had a strong third quarter before being impacted by the normal seasonal slowdown during the fourth quarter. We expect the Offshore Marine business to maintain good utilization on 5 to 7 liftboats with some variable seasonality on the OSVs and crew boats. The Energy Services should have seasonal utilization for up to 10 P&A spreads and up to 2 coiled tubing units in '25. There is seasonality in the diving and heavy lift business where the Epic Hedron and diving vessels are expected to have good utilization during Q3, but slow down during Q4. Moving to Slide 18. Our CapEx forecast for '25 is heavily impacted by the dry docks and maintenance periods on our vessels. The Seawell Q7000, Q5000 completed their dry docks in the first half of 2025. The Q4000 is now planned to enter dry dock in the third quarter with forecasted completion at the end of August. We are increasing our CapEx range for 2025 to $70 million to $80 million to account for the acceleration of the Q4000 docking into 2025. The majority of our CapEx forecast continues to be maintenance and project related, which primarily falls into operating cash flows. Reviewing our balance sheet, our funded debt of $319 million at June 30 is expected to decrease further by $4 million in 2025 with scheduled principal payments on our MARAD debt. We repurchased our shares -- $30 million worth of our shares during the second quarter. At this time, I'll turn the call back to Owen for a discussion on our current outlook for '25 and beyond and for closing comments.

Thanks, Erik. Well, I've never been one to gloss over the challenges we're facing or have faced in the past and what we tell investors. Last year, going into the year with higher rates and major contract awards, it was easy to think we were in a sustainable up cycle. Many companies, including Helix are disappointed in the 2025 market. While the long-term fundamentals are solid and cash flow outlook is still strong, the market is more nuanced than the expectations for continuing improvements would suggest. The markets for 2025 can best be described as impacted by uncertainty and indecision on the part of the producers. We have 3 primary markets that have disappointed and negatively impacted our expected results. You might notice in this that these are areas where we're most exposed to the spot market nature of the market. First, the U.K. North Sea market has come to a temporary standstill. Coming into the year, to some degree, we expected this as a result of government policy uncertainty, continuation of the excess profit tax and merger activity with resulting integration periods as producers with profitable outlooks merge with producers with net loss tax positions, but I'm not sure anyone anticipated the true weakness of this market this year. We know several major producers have announced their intentions to leave the U.K. North Sea. This should generate meaningful levels of abandonment work with most of it being forecasted to occur starting in 2027. At this time, planning and engineering is occurring. We do see at least 2 significant larger projects for 2026, but the competition for them is expected to be stiff affecting potential margins. Our expectations for 2025 remain low with improvement in 2026 and recovery by 2027. In the Gulf of America intervention market, the intervention market is also looking soft for the second half of the year. The Q5000 backlog looks solid. Depending on demand, the Q4000 may be able to find more consistent opportunities deployed elsewhere. To position for this flexibility, we're bringing the regulatory dry docking forward into 2025. This will have ramifications in 2025, but sets up for more available days in 2026 and flexibility on regional deployment. Third area to mention is the Shallow Water Abandonment. There continues to be a significant backlog of regulatory required abandonment work in the Gulf of America shelf. The abandonment orders are being given out, but 2025 has proven to be a year of planning, engineering and permitting. As a result, the volume demand has been low with competitive pressures depressing margins and increasing labor costs as all contractors struggle to find skilled people. We believe we've rightsized the business for 2025, but lower margins and higher labor costs will result in a second year of less than satisfactory results. We expect 2026 to improve with a further improvement in 2027. Elsewhere, Helix is operating as expected with a strong 3-vessel market in Brazil for intervention and the offshore wind trenching and site clearance market demand remaining strong globally despite the challenges of the U.S. wind farm market. In production facilities, our Droshky field continues to produce well beyond the original expected end of production. The Thunder Hawk field remains shut in while planning and long lead items are prepared for an intervention. At this time, we're planning for production to be restored in early 2026. Again, I've never been want to shy away from the challenges we face and whether it's good or bad, we're open with our shareholders. There's no doubt that 2025 has not gone as well as we had expected, but the overarching themes are macro instability and market uncertainty, lower oil prices and resulting lower cash flows. The customers are facing their own challenges and it's pushing out their spend and impacting our business. In spite of these unexpected hiccups for 2025, Helix remains financially very strong. Even in this down market, we're anticipating free cash flow generation that's likely greater than $100 million with a strong balance sheet and good long-term backlog. With signs of renewed activity in the North Sea Well Intervention market, we still have expectations for a meaningful improvement in 2026 and a return to full strength results by 2027. So thanks, Erik, and thanks everybody for joining us today. We very much appreciate your interest and participation and look forward to having you on our third quarter '25 call in October.

Operator, at this time, we'll go ahead and take any questions.

[Operator Instructions] So your first question comes from the line of Greg Lewis with BTIG.

Owen, I appreciate the comments. And clearly, as we look at Shallow water Abandonment, it's kind of just been there, maybe not as good, kind of hanging in there. I guess my question is, as you think about that market, there's always this give and take around, well, there's a lot of wells that need to be plugged and abandoned, the regulatory backdrop around that. And then, of course, the oil price also seems to matter. As you kind of think about what we should be looking at for potential signs of shallow water in SWA, like what do you think we should be focused on just thinking that it looks like we might be finding a bottom here?

I think we are at a bottom right now. When the Fieldwood and the Cox bankruptcies occurred, I think it became apparent to the industry that the model was sort of broken, and this is the first time we've seen massive boomerang properties going back to the majors. That's been a relatively new thing for the government and the producers to deal with. And I think what you're seeing right now is a little indecision on the part of both. The government basically came out and allowed the producers a 3-year period to come up with a plan. Some producers are going ahead and getting ahead of that curve. But when that happened and the Cox bankruptcy was delayed, that basically means that right now, all the producers are sort of trying to figure out what are they going to do, what are their plans and then doing the engineering and permitting all takes time. I think by 2027, that period expires. So what I would look at is the bidding activity between now and '27. Are you going to see producers getting ahead of the curve and coming out with major bids? I think we just announced that we won a major contract with Exxon 3 years, what, 195 wells or thereabouts. So that was a major bid that came out. I think you'll see follow-on bids coming out. So I would watch the bid activity over the next 12 months to judge as to when the market returns to normalcy.

Okay. Great. And then just on the Well Intervention in the Gulf of America. When we think about that with the Q5000 and the Q4000, clearly, the Q5000 is good for the remainder of 2025. And I know we don't necessarily comment on pricing. But maybe could you talk a little bit about maybe the difference and how we should think about if we're able to secure like multi-quarter work versus spot work? And I'm kind of curious on your view. I know one of the [ Globetrotter ] rigs that had previously kind of competed in Well Intervention is leaving the Gulf, right? It's heading over to, I believe, the Black Sea. So just kind of curious how that positions your assets in the Gulf of America, just sometimes things benefit from a little less competition.

That's true. I don't really see the competition as being the hurdle for us. That's not the challenge for us. I think we're very competitive and our efficiency can outcompete rigs. I don't see that as the issue. I think what happened this year is we were anticipating a little bit of a softness, which is why we took the work in Nigeria with the Q4000. That work, unfortunately ended a little bit short because a couple of the wells that they were planning to do got eliminated from the schedule by the client, and that cut our time in West Africa short, which was not a major issue because we were looking and in discussions with a lot of clients about work that originally at the beginning of the year, they had planned to do for the second half of the year. By the time we got back to the Gulf, though, most of these producers decided not to spend the money and the work all pushed out into 2026, which has left us with a gaping hole in the second half of the year for the Q4000, which was unanticipated, and it wasn't even visible until we got back here. So we're scrambling right now. I wouldn't say that it's a fait accompli, but we did decide that we would move the dry docking forward into this year so that we would have the vessel fully available for what we would expect as an increase in demand for 2026. So we'd have more available days. And Scotty, you may have a little more insight.

Yes. I think we should add that the Q5000 is very well contracted at good rates for the remainder of 2025 and has a good backlog going into 2026. Shell and options with other clients plus options into 2027. So Q5000 is in very good shape at good rates. The Q4000, one of the reasons we've moved the regulatory docking forward into 2025 is we're also looking at works out with the Gulf of Mexico again, Southern America, back in Africa, whereas we wouldn't be able to undertake the regulatory planning and docking for that asset. So we're seeing a lot of work go from '25 into '26. There's some good discussions with clients, but Q5000 is looking good and international opportunities are in discussion for the Q4000 again.

I think I'll just add a little bit more because if you're looking for a bridge from last year to this year and what happened, I think as I mentioned earlier, you don't need to look further than the exposure to the spot market, which segments of ours are exposed mostly to the spot market. The areas that we are having that exposure is the Well Ops U.K., the Shallow Water Abandonment and the fourth quarter here for the Gulf of America for the Q4000. Those are the 3 areas where we -- it's typically a spot market. It's not a matter of the competition or the rigs white space or anything else. It's simply a matter that the clients -- we can suffer a slowdown in one area, maybe 2. But when all 3 areas slow down in the same year, that results in the impact that you're seeing on our results for this year.

Your next question comes from the line of Jim Schumm with TD Cowen.

Maybe just starting in Robotics. If I look at the Subsea Robotics revenue this quarter year-over-year, the revenues are up a little bit, but EBIT was way down. So what's driving that? Is that -- I mean, I see some lower integrated trenching work, but is that it? Or is there something else?

The main reason for that is that last year, we had the T1400-1 and the vessel in the full package operating in Taiwan. This year, the client is providing the vessel on the survey. So we just have the trencher on contract for the client in Taiwan. So there's quite a big difference. I think year-over-year, it results in about $10 million worth of difference of not providing the full trenching spread and just providing the trencher.

So I think, Jim, yes, I think there is a little bit of a margin difference in our contract makeup. I think we have a bit more vessel days as our contracts are primarily day rate contracts. Last year, we had some lump sum contracts that were completed at the end of the second quarter at very good margins. And so I think that's where you see probably an increase in cost is higher asset activity, so to speak, on day rates as opposed to some of the lump sum that we benefited from last year.

Okay. On the shallow water, you said you've rightsized the business, but it is Q2, it's a seasonally strong quarter typically, and you're EBIT neutral. So I mean, what's the -- I would think that maybe you'd want to go after more cost cuts here, but you said you're rightsized. So how should we -- how are you thinking about that?

So I think the second quarter in shallow water was a bit disappointing. I think the biggest driver from our standpoint is -- was the later start on our heavy lift. That is a season that's usually between 150 and 180 days. We had expected to be able to start in early May. And due to weather patterns in the Gulf, we weren't able to, I think, mobilize that asset until the -- you could say, middle of June. And so I think that had a significant impact on our expectations there, obviously, increased the cost ready to mobilize that asset and we were hampered by the weather patterns there. So that was a big driver of that. I think, Owen, you could speak to perhaps the P&A side of things, but that was a big driver of some of the, I guess, poor performance in the second quarter.

I think in addition, we're seeing downward pressure on liftboat rates in the near term. The market utilization at the moment is fairly low. So our larger liftboats are having to compete with the smaller liftboats that command a lower rate in the marketplace. So that, coupled with the [indiscernible] late start has really led to the lower-than-expected Q2 results. But we do expect improvement on a go-forward basis. I think very telling and as Owen sort of mentioned previously, is the bid activity and the recent 3-year Exxon framework agreements. On a go-forward basis, we expect that to provide roughly 1,000 days of overall utilization in the P&A spreads over that 3-year period with pull-through for other assets. So we do want to ensure that we can meet demand on a go-forward basis as well.

And I think on just an overview, we did rightsize the business. We cut roughly $15 million worth of cost out of the business, but we had to maintain sufficient personnel and equipment on the ready to be able to deal with the peak of the market. The problem is with the dearth of work out there, all of the competitors are seeking utilization. So the competitive rates have been reduced greatly. Margins have been reduced greatly. And in order to provide for that utilization, there's been a real competition on personnel. When we rightsized the business, we did let people go. We've stacked 5 vessels, and that started sort of an exodus of people. And due to the competitive pressures, we then responded by increasing our labor costs. So that sort of gives you a picture of -- we did cut costs, had to add back and we're carrying the rightsized capacity to meet the peak demand during the middle of the season so that we can maintain market share.

Understood. And then what about the -- so I understand the rationale for the Q4000 accelerating the regulatory maintenance here. But why not remediate the Thunder Hawk well this year while you have this downtime? Like why wait until early 2026 when potentially you could be doing customer work at that time? Why not pull that forward?

To do the intervention on the Thunder Hawk well, first of all, took a lot of time to try and diagnose what was going on. And then we work with partners. So in order to bring them along, one of the potentials is that the downhole safety valve could be faulty among other things, but we -- that required a long lead order time in order to have the insert valve manufactured and to make sure that we had the right SOPs in place to be able to carry that out. Beyond that, the partners would -- there's different methodologies for clearing the blockage and the partners -- both partners are strongly in favor of exhausting all possibilities prior to doing an intervention. And I don't know, Daniel, you have a little more clarity on that.

I think that's accurate. We're expecting the delivery of long lead items towards the back end of Q3 going into the beginning of Q4. And also the partners have a preference for the intervention to be carried out at a slightly later date. So earlier Q1 of 2026 is also their preference.

Your next question comes from the line of Jim Rollyson with Raymond James.

Owen, you kind of covered this a little bit, but maybe just to dive in a little bit more on intervention and the decisions from some of your customers to push work. Just curious, when you have these conversations, what's the main challenges that they're looking at that's kind of driven incremental pushes from 90 days ago to now? Is it the tariff uncertainty? Is it the oil price? I'm just kind of curious as we set up for what you're kind of describing as a maybe better '26 and heading into an even better '27, maybe just so we understand the drivers better so you can kind of think about how realistic those time frames are when that work comes back, if that makes sense.

Jim, I think it's a matter of all of the above. I think you have weaker oil prices. You have the regulatory uncertainty in the fiscal regime in the North Sea. It's just a plethora of reasons. What happens is that the producers basically because of all the uncertainty, just decide that they're going to sit on the sidelines right now and everything just gets pushed to the right. Now how far it gets pushed to the right, that's the question that we're trying to figure out probably the industry as well. I've seen some people coming out saying second half of '26. We think it's going to be more -- it's not a light switch that turns on at some point in time. I think what we're expecting is that some of the activity can't be pushed out to the right forever and some of the producers are going to get back into the game a little early. So that's why we're seeing a gradual ramp-up during 2026. And who knows, but I'm hoping that a lot of the uncertainty or the pent-up demand allows us to get back to a more normalized market by 2027. We're certainly seeing the green shoots in, for instance, the U.K. where producers -- even the producers that say they're going to get out, that then trips the clock on when they do their P&A. And everything that I've seen right now would indicate that, that's going to become pretty heavy between '27 and ‘30, ‘31.

We're in discussion with some large tenders in the North Sea that would take us back, hopefully, in '26 to a 2-vessel market. And the feedback from the customers in the Gulf of Mexico, they've seen 2 sizable drops in oil price, and they're just pushing decommissioning work out into 2026.

Yes, that was why I was asking because obviously, the tariff uncertainty is probably more clarified the U.K., who knows? And there's a lot of speculation that oil prices may get worse before they get better. So that was kind of the context of the question. When you look at 3Q specifically, when you think about the guidance adjustment lower, is most of that reduction coming in 4Q? Like you mentioned 3Q being your best quarter, seasonally stronger, et cetera. But I'm just kind of curious as we think about the magnitude of improvement in 3Q versus maybe what we were expecting 90 days ago.

Yes. No, I think thinking about it from a perspective of impacting our fourth quarter is the right way to visualize it. We do have a very strong contracted backlog. We probably have a little bit of weakness on the Q4000 towards the end of the quarter. But the driver of, you could say, our adjustment to guidance and the uncertainty that we see is really in the fourth quarter. It's always a challenge with the normal seasonal downturn, how quickly operators are going to shut down activity. But then, of course, on top of that is the general reluctance to spend and the impact that that's having on our Well Intervention market in the Gulf of Mexico. So it is concentrated in the fourth quarter.

Got it. And Erik, just one last thing. On the free cash flow, obviously, you mentioned second half ramp versus first half. It looks like DSOs ticked up a decent amount this quarter. Maybe just a little color on kind of what's going on there. And I presume unwinding some of that is part of what helps drive the second half improvement.

Yes. I think our DSO did jump up quite a bit here in the second quarter. I think we have a couple of larger blue-chip customers that are pushing out payments and making that a little bit challenging. But I think that's something that we'll be able to address, obviously, before the end of the year.

Your next question comes from the line of David Smith with Pickering Energy Partners.

I apologize in advance if my question has been touched on. It's been a busy morning in OFS land. And I understand there can be quarter-to-quarter volatility and Well Intervention, right, things like contract transitions, regulatory downtime, accounting for mobilizations. I'm just struggling a little bit to reconcile the Q2 segment results with Q1. Based on disclosed utilization, it looks like operating days were actually a little higher in Q2, but revenue and profitability came down pretty sharply. Can you walk us through the main drivers of that step down? And was there anything in the Q2 segment result that was much different than what you expected 90 days ago?

So from that standpoint, David, we don't give annual guidance, but we did, I think, qualitatively say that we expected our Q2 results to be more in line with Q1 because of the regulatory drivers. Q1 was about $52 million. We came in about $42 million of EBITDA in the second quarter. Two big drivers there. Number one, I think the shallow water, obviously, a slower start to the season. That impacted us a bit. And then, of course, we mentioned before the number of mobilization days where we had deferred revenue cost and margins associated with Well Intervention that got pushed into the third quarter. That was approximately about 20 days. And so those were probably the 2 biggest drivers that did not allow us to achieve sort of results in line with the first quarter. As far as the revenue, I think what we'll say is I think the utilization numbers include 45 days of transit on the Q4000, which were not revenue days, but were cost incurred days. So I think that is possibly skewing the numbers. And then the rates on the Q4000 working overseas in Nigeria, where there's a significant amount of pass-throughs also definitely skews the revenue and per day rate that you see in Q1. I don't know, Brent, if there's anything you'd like to add?

No, I think, Erik, I think you've covered all the main points there.

Okay. I do appreciate it. Just a quick housekeeping question. Were the mobilization days -- so I did exclude the 45 days for the Q4. Were the mobilization days for the Q7000 and the first quarter contributing to the Q1 revenue?

So the Q1 revenue on the Q7000, we only had about 5 or 6 days of revenue in Q1 on the Q7000. And so obviously, second quarter, we had the vessel working. I think other than downtime, the vessel was working in the second quarter.

The mobilization days Erik is talking about is relating to Q5000, Q4000 and Well Enhancer. Those mobilization days, 20 days he's talking about are going into Q3.

Your next question comes from the line of Josh Jayne with Daniel Energy Partners.

First one, I just wanted to go back to the 3-year agreement you signed with Exxon on the Shallow Water Abandonment side. I think, Owen, in your commentary, you said close to 200 wells. Maybe could you frame the number of other opportunities that are out there that are being bid on today just so we can sort of think about how that could progress over the next couple of years?

We are seeing similar, although probably slightly less utilization -- utilization opportunities in the marketplace. There is bidding activity ongoing through Q3 and Q4 of this year for work on a go-forward basis. Generally, what we're seeing is that framework agreements are our discussion rather than firmly contracted work. However, we are getting better visibility on the marketplace, but we do continue to expect properties to move right back and for the demand to increase in 2026.

Just a little clarity around the Exxon contract. That contract was for the well work. There's a separate contract that was led that's ongoing right now, which is for the make-safe work. Our work really starts once that completes. But then our contract is for the well work. And then there is additional work for the subsea architecture and the provision of heavy lift and liftboats and everything that will be forthcoming. So this award puts us in a good position to expand our offering to what Exxon could contract us for later on.

Okay. And then one on the intervention side. I think you had mentioned the potential for the North Sea to be a 2-vessel market again in 2026. Any thought because I assume the timing of figuring that out will factor into your -- how to handle the Seawell from a cost standpoint. Could you speak to when you might anticipate knowing if it's going to be a 1 vessel or 2 vessel market in '26 and how you could also see regardless of what happens in '26, do you think that it will be a 2-vessel market in 2027?

So right now, we're concentrating all the work onto the Well Enhancer. The Seawell is stacked at a very low cost base, reduced the crew down to minimum safe manning and that sort of thing. We're in discussions with a couple of clients on larger decommissioning tenders. If those tenders are awarded to us, then we would expect to go back to a 2-vessel market in 2026. I think to be fair, the timing of the award of those tenders will be later Q3, probably Q4, and then they'll go into a planning stage. So those tenders are looking very good. What I will say they're very competitive. But I'm also of the mindset that they could easily shift that work into 2027. So based on the awards and the timing and when the work happens, we should know around Q4, whether we go back to a 2-vessel market or whether we stay in stack mode with the Seawell. There's certainly enough activity out there to keep the Well Enhancer busy for next year. But those tenders come into fruition, we will decide on whether or not we take -- go back to a 2-vessel market.

Next question will come from the line again of Mr. Jim Schumm, TD Cowen.

Yes. And I'm going to hit on the U.K. North Sea again, and you addressed it a little bit, but why not take this opportunity with the Seawell stacked? Why not upgrade the vessel to be able to mobilize it out of the U.K. North Sea? I mean, I think, Owen, what you were saying is if the customers decide that they're not going to do work, then that will trip the need to do a lot of P&A work, but they can just delay that, right? Like they can just not do work and just bide their time. I mean, we -- the P&A market, as you know, has been a great opportunity forever, but it always gets pushed to the right. So why is that not going to happen again? Why not take this opportunity? You've got a vessel stacked. Why not take the opportunity? You have plenty of cash, give yourself some optionality and be able to serve another region because the U.K. North Sea seems like very challenged going forward. Is it because you would rather upgrade the Well Enhancer and the Well Enhancer is working? And just help me understand that.

I think it boils down to capital deployment and return on capital. If the forecast and all the indicators right now are for a strong market from ‘27 to ‘31, we're going to need both vessels. So you're looking at an upgrade in order to redeploy the vessel for 2026. The cost of that upgrade is not cheap. There's no way that it would be cost effective to do it for a 1-year deployment and then have to return it to the North Sea by '27. So I think it's a little early to make that decision. I'm not saying that that's not the right long-term decision. And we are in discussions with producers in other regions about what their needs are, but there's no concrete definitive demand for riserless vessels in other regions right now. There's a lot of talk and hypothetical. So it'd be a little bit of a risk to spend that much capital on upgrading the Seawell at this time. We've decided that we're going to see how these 2 large projects play out for 2026. If we're successful on both of them, then there's a high probability that we return to a 2-vessel market in the U.K. for 2026 without the large capital expenditure.

Okay. Understood.

Just add to that, we are finally seeing that the government in the North Sea is putting pressure for decommissioning to happen. So these projects are planned for '26 with government pressure finally.

And given the uncertainty of the North Sea, if one of these clients we're talking to in other regions wants a riserless vessel with better terms and more certainty of duration of the contracts, then we would certainly price it to them and make that decision. And if the North Sea returned to a 2-vessel market, then we cross that bridge when we came to it, but we would take the more certain long-term future.

Thank you so much, everyone. And that concludes our Q&A session for today. I will now turn the call back over to Mr. Brent Arriaga for the closing remarks. Please go ahead.

Thanks for joining us today. We very much appreciate your interest and participation, and we look forward to having you on our third quarter call 2025 in October. Thank you.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect. Have a nice day ahead.