Transocean Ltd

NYSE:RIG

Earnings Call Analysis

Earnings Call Transcript 2024-Q2

[Operator]

Good day, everyone, and welcome to today's Second Quarter 2024 Transocean Earnings Call. [Operator Instructions] Please note this call is being recorded, and I'll be standing by if you should need any assistance. It is now my pleasure to turn the program over to Alison Johnson, Director of Investor Relations.

[Alison Johnson, executive]

Thank you, Good morning, and welcome to Transocean's Second Quarter 2024 Earnings Conference Call. A copy of our press release covering financial results, along with supporting statements and schedules, including reconciliations and disclosures regarding non-GAAP financial measures, are posted on our website at deepwater.com. Joining me on this morning's call are Jeremy Thigpen, Chief Executive Officer; Keelan Adamson, President and Chief Operating Officer; Thad Vayda, Executive Vice President and Chief Financial Officer; and Roddie Mackenzie, Executive Vice President and Chief Commercial Officer. During the course of this call, Transocean management may make certain forward-looking statements regarding various matters related to our business and company that are not historical facts. Such statements are based upon current expectations and certain assumptions and therefore, are subject to certain risks and uncertainties. Many factors could cause actual results to differ materially. Please refer to our SEC filings for our forward-looking statements and for more information regarding certain risks and uncertainties that could impact our future results. Also, please note that the company undertakes no duty to update or revise forward-looking statements. Following Jeremy, Keelan and Thad's prepared comments, we will conduct a question-and-answer session with our team. During this time, to give more participants an opportunity to speak, please limit yourself to one initial question and one follow-up. Thank you very much. I'll now turn the call over to Jeremy.

[Jeremy Thigpen, executive]

Thank you, Alison, and welcome to our employees, customers, investors and analysts participating on today's call. As reported in yesterday's earnings release, for the second quarter 2024, Transocean delivered adjusted EBITDA of $284 million on $861 million of contract drilling revenues, resulting in an adjusted EBITDA margin of approximately 33%. Needless to say, I'm very proud of our team's continued commitment and diligence. Over the past several quarters, the Transocean team worked together to overcome numerous challenges as we mobilized nearly 40% of our active fleet across multiple jurisdictions worldwide, all the while maintaining the highest standard of safety, reliability and efficiency. This result allowed us to once again achieve superior uptime performance for our customers, driving revenue efficiency of approximately 97% in the quarter. Thank you to each and every member of the Transocean team for what you do, day in and day out. Largely due to this consistent reliable operational performance and the effort, knowledge and tenacity of our marketing and contracts team with strong support from our legal team, we enjoyed an incredibly exciting past few weeks, culminating with the announcement of extensive contracting activity on our fleet, particularly with respect to our fleet in the U.S. Gulf of Mexico. First, Beacon Offshore Energy awarded the Deepwater Atlas, a 2-well contract at an industry-leading rate of $580,000 per day, including additional services. The estimated 150-day contract is expected to commence in direct continuation of the contract we received in April and includes 2 contingent 45-day 20,000 completions at a rate of $650,000 per day. As a reminder, the contract that was awarded in April consists of 4 wells at a rate of $505,000 per day, including additional services. The program also provides for 3 contingent completions for up to a combined 120 days at that same rate. Next, as we disclosed yesterday, BP awarded the Deepwater Invictus a 3-year contract at a rate of $485,000 per day, which also includes up to 2 years of options that mutually agreed upon rates, which will likely be determined at some point in 2025. The contract is expected to commence in the first quarter of 2025. Of note, as the Invictus is now solidly booked throughout the period of time in which it was previously assigned to a 3-year contract for work in Mexico, that contract will now be reassigned at our election to one of the remaining rigs in a pool of similarly capable rigs, including the Deepwater Thalassa, Deepwater Proteus, Deepwater Conqueror and Deepwater Asgard. Additionally, the Invictus was also awarded a 40-day contract in direct continuation of its current program at an undisclosed rate, enabling us to begin filling gaps, mitigating and hopefully, ultimately eliminating white space. Also since our fleet stats report update last week, we secured a letter of intent for one of our rigs in the Gulf of Mexico that have some availability and expect to add additional wells to the other rig in the Gulf of Mexico that has availability in the very near future, effectively taking them off the market for other near-term opportunities. We will update you on our progress as appropriate. Lastly, for the U.S. Gulf, the Deepwater Asgard received a 1-year contract extension with Hess at a rate of $515,000 per day, including additional services. In Brazil, Petrobras exercised a 279-day price option on the Deepwater Myconos at a rate of $366,000 per day. As a reminder, the option pricing for this campaign was submitted in May of 2022, which explains why this day rate while still healthy, represents a fairly meaningful discount to current leading-edge rates. Importantly, the firm duration now extends through October 2025 and generates meaningful cash flow, which can aid our deleveraging efforts. Moving to the harsh environment fleet. In Norway, the Transocean Norge was awarded a 3-well extension with Wintershall DEA at a current rate of $517,000 per day, extending the rig's firm duration into the second quarter of 2028. It was this combination of day rate and term that provided the impetus to execute our strategy to acquire the remaining balance of this unique high-specification assets. Also, in Norway, the Transocean Spitsbergen was awarded a 3-well extension with Equinor at a current rate of $483,000 per day. The program is expected to commence a direct continuation of the rig's fixed-price option and keep the rig off the market through the first quarter of 2026. In Australia, Woodside exercised a 1-well option the Transocean Endurance at a rate of $390,000 per day. The firm period now extends through mid-2025, and with the remaining options, the rig is expected to remain in Australia until at least the second quarter of 2026. With these contracts, our working fleet is more than 90% committed through the end of 2025. And based upon advanced discussions with our customers and reflecting LOIs and strong verbal commitments, we believe that aside from some small activity gaps, which could arise in our customer drilling programs, our fleet that is currently working could soon be completely booked well into 2026. As such, our customers may soon need to consider financing the reactivation of cold stacked assets to meet their future program requirements. We are certainly pleased with these new contract awards, some of which have been a long time in the making as they demonstrate materially increasing day rates and linked terms, which combined reinforce our confidence in the strength and longevity of the offshore drilling market. As discussed on previous calls, we expect Deepwater prospects to become an even more important source of the word for the next several years, and we're not alone in this expectation. According to Rystad Energy, the equivalent of 56 million barrels per day of newly discovered oil will be required to satisfy global oil consumption by 2030, and over 16% of this incremental supply is expected to come from Deepwater production. Accordingly, global offshore greenfield exploration production investments are projected to grow to $110 billion in 2027. That's up from $48 billion in 2024, a 129% increase, with approximately half of this increase is expected to be driven by activity in South America and Africa. I'll now hand it over to Keelan to talk about the regions in our fleet.

[Keelan Adamson, executive]

Thanks, Jeremy, and good morning, everyone. As Jeremy mentioned, many of the programs for which we are in discussions with our customers have commencement dates well into the future. Based on what we see today, we expect the U.S. Gulf of Mexico to remain in balance for the next several quarters with a number of gap filler type programs still to be awarded. Looking forward, our customers remain committed to developing their existing Deepwater assets and adding to their portfolios. Our customers continue to move forward with their 20000 development plans. And as an example, on Tuesday, BP announced taking their final investment decision on the Kaskida project, with nearby Tiber expected in 2025. This investment decision sets an important development in motion, unlocks the potential future development of 10 billion barrels of discovered resources in place across the Kaskida and Tiber catchment areas and marks another data point of additional 20,000 opportunities being sanctioned by our customer base. In 2018, Transocean took the strategic decision to upgrade the hook load, drilling, completions and 20000 capability on both of the new eighth-generation drillships, the Deepwater Atlas and Deepwater Titan to best position these rigs for the anticipated Gulf of Mexico 20000 programs. As a result, they are effectively purpose-built for our customers' 20,000 operations and their design will facilitate efficiencies in well delivery, not achievable from the highest specification seventh generation rigs. As such, we believe we are well qualified for any of the multiple 20000 opportunities currently being discussed in the Gulf of Mexico. Moving to Brazil. We expect Petrobras' Norbe tender will be awarded in the next few months and the Sepia tender thereafter for a combined 5 rig awards. Also, over the last 2 weeks, Petrobras issued a new tender for four rigs, which is consistent with our expectation that they will continually roll over their existing fleet to support production targets that require at least 30 operational floaters through 2030. While we expect these rigs to be largely renewals of floaters already in country, we do believe an incremental rig or two could, mobilize to the Brazilian market to satisfy this demand. In West Africa, we expect substantial rig demand beginning in early [Technical Difficulty] [2025]. Nigeria is expected to require four rigs, two more than are currently in the region. In Angola, there are 7 floaters operating, and we expect this level of demand to be sustained. Ghana, Ivory Coast and Namibia could also add to the rig demand in 2025 and 2026, with four programs expected to commence in this time frame. If all programs proceed as expected, three drill ships could be required from outside of these countries. We believe it is likely the entire West Africa region will require at least four additional Deepwater rigs from 2026 onwards, which could possibly require the reactivation of some currently cold stacked assets. Lastly, for the ultra-Deepwater markets. In India, we anticipate the award of alliances tender in the coming weeks and continue for the KG1 is well placed to secure this program. Moving now to the high-specification harsh environment market. Assuming outstanding options are exercised, the Transocean fleet is effectively sold out through 2025. Looking ahead, we believe Norway will be undersupplied by 2 rigs in 2026. Our recent fixtures in Norway underscore the strength of that market as our customers are contracting rigs like the Transocean Norge up to 4 years in advance. Regarding the Norge, as you know, in June, we successfully completed a transaction to acquire this 7% outstanding in the joint venture that owns the rig. It was always our intention to eventually own the rig outright in line with our asset strategy as it is one of the most capable harsh environment semi-submersibles in. Additionally, we have dedicated substantial resources to automating drill floor pipe handling operations on the rig and are very pleased with the progress we have achieved to date. We will continue to pursue opportunities for automation in our fleet with the ultimate goal of driving significant improvement in safety and operational performance while simultaneously reducing our carbon footprint. Before I pass the mic, I'd like to strongly reiterate Jeremy's gratitude to the entire Transocean team and specifically recognize our people for the tremendous efforts in mobilizing and preparing the Deepwater Aquila for a maiden contract in Brazil. As a result of the significant collaboration across the organization, we commenced operations in late June, nearly a week ahead of schedule. In addition to the commencement of the Aquila contract with Petrobras, during the last 6 months, we have relocated and commenced operations on the Transocean Endurance, Transocean Equinox in Australia, reactivated and commenced operations on the Deepwater Orion in Brazil, and recommenced operations on the KG1 in India. These are all examples of our extensive experience to reliably bring new build market, reactivating warm stacked assets and relocating our active rigs to different geographic markets and customers safely and efficiently. I'll now hand the call back to Jeremy.

[Jeremy Thigpen, executive]

Thanks, Keelan. The offshore drilling industry is in its best condition since 2014. As we discussed on our first quarter 2024 earnings call, the average contract duration for new ultra-Deepwater fixtures has remained above 500 days for the last 2 years. Concurrently, as mentioned earlier, day rates have continued to increase. These 2 indisputable data points define the positive investment thesis for the industry and particularly for Transocean. Looking specifically at Transocean's fleet, in 2022, our average new contract fixture was approximately $359,000 per day. In 2024 today, our average is $504,000 per day, a 40% increase. While we, like our competitors, are certainly benefiting from positive market dynamics, the industry-leading capability of our assets and the consistently safe, reliable and efficient performance we provide to our customers, combined with our deep understanding of the market, enable us to differentiate ourselves from our peers, which you can see in our leading-edge day rates in our industry-leading $8.64 billion backlog that we announced with our recently status report, which, by the way, excludes the $531 million backlog associated with the BP contract we announced yesterday. As we have reiterated for the past several quarters, we continue to be highly encouraged by the conversations with our customers and are certainly excited by the momentum created by our recent fixtures. As many of you will remember, less than 9 months ago, the entire offshore drilling community expressed on the timing for the first contract to exceed $500,000 per day. Now we are seeing rates in the 500s more often than not, fixed across the entire space with Transocean once again leading the way with ever-improving fixtures for both 15000 and 20,000 work. And while we will always endeavor to identify and seek the appropriate opportunities to test day rates, we also recognize and appreciate the value of term and adding to our industry-leading backlog, providing us clear visibility to future cash flows. As such, Transocean will continue to strategically manage its portfolio of assets, striking the appropriate balance between day rate and term to maximize shareholder value. In closing, we continue to believe the underlying fundamentals support a multiyear growth cycle for our assets and services. Given our backlog and the visibility it provides to future cash flow flows, along with a future reduction in CapEx requirements as our new builds are now all out of yards and on contract, we expect our unlevered free cash flow to continue incrementally increasing each quarter for the next several quarters, which can enable us to deliver our balance sheet and ultimately position us to design, communicate and implement a sustainable strategy to make distributions or otherwise return value to our shareholders. With that, I'll now turn the call over to Thad to discuss our financial results.

[R. Vayda, executive]

Thank you, Jeremy, and good day to everyone. As is our practice during today's call, I will briefly recap our second quarter results, provide guidance for the third quarter and conclude with an update on our expectations for the full year 2024. As reported in our press release, for the second quarter, we reported a net loss attributable to controlling interest of $123 million or a loss of $0.15 per diluted share. During the quarter, we generated EBITDA of $284 million and cash flow from operations of approximately $133 million. Positive free cash flow of $49 million in the second quarter reflects $133 million of operating cash flow, net of $84 million of capital expenditures. Capital expenditures for the quarter included $53 million related to the new build Deepwater queue, with the balance associated with various other projects across the fleet. During the second quarter, we delivered contract drilling revenues of $861 million at an average daily revenue of [Technical difficulty] [$1,000]. Contract drilling revenues are slightly below our guidance, mainly due to the prolonged 15000 psi drilling operations of the Deepwater Atlas, which delayed the start of the rigs higher 20,000 psi day rate. Recall at the rig's 15,000 psi operating day rate, which was negotiated in the second quarter is about $268,000 per day. The 20000 psi day rate is $455,000 per day. The customer delayed commencement to the KG1 in India also adversely affected our contract drilling revenue. These factors were partially offset by higher fleet revenue efficiency 96.9% and the commencement of the Deepwater Aquila in Brazil on June 25, about a week earlier than anticipated. Operating and maintenance expense in the second quarter was $534 million. This is below our guidance primarily due to the delay of in-service maintenance in the active fleet and the favorable resolution of old contingencies. G&A expense in the second quarter was $59 million, generally in line with our guidance. We ended the second quarter with total liquidity of approximately $1.5 billion, including unrestricted cash and cash equivalents of $475 million, about $400 million of restricted cash, $316 million of which is reserved for debt service and $576 million of capacity from our undrawn revolving credit facility. I will now update you on our expectations for our financial performance for the third quarter and full year 2024. As always, our guidance excludes speculative reactivations and upgrades. For the third quarter, we expect contract drilling revenues to approximate $940 million based upon an average fleet-wide revenue efficiency of 96.5%, which, as you know, can vary based upon uptime performance, weather and other factors. This estimate includes approximately $55 million of additional services and reimbursable expenses. Please recall that the additional services and customer reimbursables generally carry low single-digit margins. The sequential increase in revenue was mainly due to, first, a full quarter of activity for the Deepwater Aquila following commencement of the rig initial contract in Brazil; second, higher utilization on the KG2, KG1 and Transocean Equinox, which had contract preparation activities in the second quarter. And lastly, a higher contractual day rate for the Deepwater Atlas as the rig started 20000 psi operations on July 7. We expect third quarter O&M expense to be approximately $610 million. The quarter-over-quarter increase is primarily due to the changes in activity that I just reviewed, an increase of in-service maintenance costs, some of which is deferred from the second quarter and the aforementioned resolution of various contingencies that have no comparable activity in the third quarter. These are partially offset by the absence in the second quarter of costs paid to the joint venture that owned the Transocean Norge. As you would expect, these were eliminated as a result of the acquisition of the outstanding interest in the entity. We expect G&A for the third quarter to be approximately $50 million. This quarter-over-quarter decrease is primarily related to lower personnel costs and professional fees. Net interest expense for the third quarter is forecast to be approximately $145 million. Capital expenditures and cash taxes are expected to be approximately $35 million and $10 million, respectively. For the full year 2024, our revenue guidance of approximately [$3.6] [technical difficulty] is unchanged at this time. This guidance includes approximately $215 million of additional services and reimbursable expenses, of which about $105 million were realized in the first half of the year. Full year O&M expense is still expected to be between $2.2 billion and $2.3 billion. Finally, full year G&A costs are expected to be around $215 million. Our projected liquidity at year-end 2024 is unchanged from last quarter at approximately [$1] [technical difficulty], which includes the full $576 million capacity of our undrawn revolving credit facility as well as restricted cash of approximately $390 million, most of which is reserved for debt service. This liquidity forecast includes 2024 CapEx expectations of $250 million, of which approximately $115 million is related to the Deepwater Aquila, about $15 million of CapEx associated with the Aquila remains. Of the approximately $135 million expected for sustaining and contract preparation CapEx, approximately $65 million has already been incurred. We continue to actively manage our balance sheet, making decisions that we believe prioritize the long-term interest of the company and our shareholders. In June, we issued 55.5 million shares and $130 million in aggregate principal amount of our 8% senior notes due 2027 as part of the consideration to acquire the outstanding 67% ownership interest in the joint venture, which owns Transocean Norge. In addition to the qualitative benefits Keelan mentioned earlier, this transaction is anticipated to provide an incremental $40 million in free cash flow per year on average over the next 5 years, which can be used to reduce our debt. We remain committed to maximizing the conversion of our industry-leading backlog into cash. We will continue to ensure that our capital allocation aligns with our priority of deleveraging the balance sheet and also allows us to effectively manage our portfolio of assets. We believe this approach fosters sustainable growth in the upcycle and enables us to capitalize on opportunities that maximize value creation. This concludes my prepared remarks, and I now turn it back over to Alison for Q&A.

[Alison Johnson, executive]

Thanks, Thad. Britney, we're now ready to take questions. And as a reminder to the participants, please limit yourself to one initial question and one follow-up question.

[Operator]

At this time, if you would like to ask a question [Operator Instructions]. We'll take our first question from Eddie Kim with Barclays.

[Eddie Kim, analyst]

Yes good morning. Just wanted to start off with BP's FID of the Kaskida development recently, which was need a 20k psi rig. Would the Atlas be a good candidate for that when it comes off contract beacon in early [2027]? Or do you think BP will need a rig earlier than that, in which case, I mean, what do you see is the likelihood of maybe another upgrade to 20000 psi capabilities? And -- and how much would you expect to be the cost of that type of upgrade.

[Jeremy Thigpen, executive]

Thanks, Eddie. Kind of a 2-part question. I'll let Roddie handle the marketing side of it and then Keelan will address the -- what it takes to actually upgrade an existing Seventh Gen rig to 20000 capable?

[Roddie Mackenzie, executive]

Yes. So as we've illustrated before, the point of us doing the proactive upgrade to that rig was to be the rig available when the 20,000 completion activity really kicked off. So that would be a logical choice, I think. And certainly, having a rig available not only in that time frame, but a hot rig that's gone through all of the upgrades and has been operating for some time in 20000, I think that opportunity would suit us very well.

[Keelan Adamson, executive]

And maybe just to pick up on the second part of that question on what it takes to upgrade another rig. First of all, you've obviously got to buy all the equipment with the lead times that's associated with that. And today, I think it's probably in the 30-month mark to be able to get a 20,000 BOP if you ordered it today. On top of that, there's a lot of other ancillary equipment that's required for the riser system. And then you've got to go and take a hole and upgrade all of the internal piping systems for that rig that related to pressure control system up to 20,000 psi as well. And that is an intrusive and long process. So if you think about a seventh generation rigs that's currently working, they'll have to come out of service and they will probably have an opportunity cost associated with that for 4 to 6 months to be able to at least get that upgrade completed. Along with the lead time for the other equipment that's required, you're looking at 3 to 4 years in advance and multiple $200 million plus to be able to complete that upgrade without even considering the opportunity cost that's lost.

[Jeremy Thigpen, executive]

Right. I want to pretty get the vision here.

[Eddie Kim, analyst]

I'm hearing it's difficult to upgrade, which bodes well for the Atlas and the Titan. Got it. My follow-up is just on the full year '24 EBITDA guidance which you maintained. Just wondering what the assumption is on your idle rigs. So you have 2 rigs idle today, the DD3 and the Inspiration, does your latest guidance, the midpoint of it, let's say, assumed incremental work for these rigs this year? And to the extent they get no work this year, does that put us kind of at the low end of your EBITDA guidance? Just how should we think about that?

[Roddie Mackenzie, executive]

Yes. So, in our guidance in our marketing strategy, we are not expecting to put those rigs to work this year. So that's already baked in there that they will not be active during this year. I think as we said before, we're basically going to only put them on the right opportunities, but we're not going to try and compete with them for short-term mark. So we're basically keeping them drive for longer opportunities. So yes, our guidance numbers have no activity on those rigs.

[Keelan Adamson, executive]

And I guess also that while the rigs would technically be characterized as warm-ish, we've taken a number of steps to ensure that they are marketable, but the costs associated with keeping them in that condition are as low as possible.

[Operator]

We'll take our next question from Greg Lewis with BTIG.

[Gregory Lewis, analyst]

Thank you and good morning and thanks for taking my question. Congratulations on an locking up e Invictus. I did want to talk a little bit about your strategy in the Gulf of Mexico, though, I mean that rig has kind of been like the hammer rig over the last couple of years on rates higher. You kind of locked that rig off. I mean, realizing that the Conqueror is on contract into kind of the middle of next year, is that kind of going to, should we think about that rig being a spot rig bouncing around the Gulf of Mexico? Or are we at a point in the cycle now where customers are really starting to lock up any and all available 7G hot rigs?

[Roddie Mackenzie, executive]

Yes. I think I'll take the last part of that first. So yes, that's exactly the more that the customers are in at the moment, right assets, they're really looking to lock them up. So as Jeremy had mentioned, we do have an LOI on one of those rigs, and we never give the details of that and we kind of would rather not. But we're very confident that those rigs are going to have good work immediately ahead of them. Hopefully, we'll have some updates very, very soon for you on that. But as we think about the strategy on the Invictus, as you point out, that was our flex rig. She was the market mover at some point. And now we really got a fantastic opportunity here with a new customer for us to put our way on some very meaningful work that opens up a number of very other -- very interesting other opportunities. And I think that's kind of the -- what we see at the moment, Greg. We're basically, as Jeremy alluded to, very close to being sold out, but we've certainly seen a significant increase in contracting activity over the last couple of months. In fact, as we think about having booked $1.4 billion already this year, $1.2 billion of that has happened just within the last few months. So we've seen a real acceleration in the number of awards and of course, covering a lot of the white space that we had that now is really a very, very small amount of white space left in the working fleet.

[Gregory Lewis, analyst]

Okay. Great. And just, I guess, that, I'm kind of curious how you're thinking about the balance sheet. I mean I get the sense from investors, definitely, you guys have been doing a lot and keep them busy. But I think the goal is to maybe start getting that total debt level down. And so as we're here, you kind of have 2024 guidance, the table is any kind of long-range, long-term kind of targets you're thinking about around that debt level as kind of we look out over the next couple of years?

[Roddie Mackenzie, executive]

Thanks, Greg. So there's really not been any change in our approach to the balance sheet. I mean, have the discipline of debt associated with the red financings, the regular amortizations. We have talked about our interest in getting to a credit rating level of BB-ish which affords all the rights and privileges that one can have being essentially with a junk-rated balance sheet. No change there. We think that we get to that place somewhere in the 2026 period of time. And I suggest also that that's not necessarily anything more than mathematics. We do need to continue to reduce the overall gross debt on our balance sheet, but we've not really articulated any specific targets at this point. But no change to our plans.

[Operator]

Okay. We'll take our next question David Smith with Pickering Energy Partners.

[David Smith, analyst]

Was a very impressive harsh environment rates in Q2. I think the reported average of almost $450,000 a day, which is substantially better than the $386,000 a day average that was on the last fleet status report for Q2. And I was just going to ask if you could remind us about the moving pieces that contribute to that day rate out performance?

[Roddie Mackenzie, executive]

Yes. I think what we actually posted was the 483 and 517. So they're substantially higher than the 300 rates that you mentioned before. And this really happened because of the exits of rigs from Norway really tightened up that market. And of course, with the rigs finding gainful employment elsewhere, that market remains particularly tight. And I think going forward, we see that there's going to be another call on rigs to go back to Norway, which I think can only bolster those numbers. So, I would expect that a lot of those fixtures are going to be in those very high 4s and 5s as numbers going forward.

[David Smith, analyst]

I appreciate it, right. Definitely. I was more referring to not leading edge, but the average daily revenue realized in Q2 '24, which on the press release is $449,600. And just kind of thinking about that in comparison to the FSR from last April, right, where you've got an estimated average contract rate of $386,000 for the harsh environment fleet in the second quarter. And I know there's some other items that kind of explain that difference. I was just asking for a request around those items.

[Jeremy Thigpen, executive]

Yes, Dave, I'm trying to think back, but if I recall, second quarter of last year, we had quite a bit of waiting on weather, which would have been at lower day rates. So that probably factored into that. I don't have the information readily available, but I think that's probably part of it. That coupled with the higher day rates that we booked here of late and then roll over contracts where options are priced higher. So, the combination of all of those 3, I think, is to the fairly significant increase in day rate for those pictures.

[David Smith, analyst]

Great. Appreciate it. And I know this isn't really direct competition with you, and you don't have that much availability for the next 1.5 years anyways. But just thinking about the pretty notable decline for new contracts on the benign ultra-Deepwater semis. I wanted to ask if you're seeing any change in the competitive behavior of Joe's asset owners, including maybe more aggressive pricing competition to try to get work away from the Tier 1 rigs?

[Roddie Mackenzie, executive]

Yes, are you talking about in the U.K. primarily or...

[David Smith, analyst]

Benign -- we've had pretty light contracting to the deepwater semis...

[Roddie Mackenzie, executive]

Yes. Look, I think we have very little exposure to that point out. But I think the operators at the moment are very focused on booking the higher specification assets. And I think as those run out, which is happening very rapidly, you'll probably see a lot more attention going to those benign environment semis in the sixth-gen fleet. But for now, it's all about trying to make sure people get time on the rigs that they really need to drill our programs.

[Operator]

We'll take our next question from Kurt Hallead with Benchmark.

[Kurt Hallead, analyst]

I always appreciate the color. Thank you. I guess, let me just start by the state it this way, given that it's an offshore drilling day on conference calls. So just kind of calibrate we've heard from a couple of the other peer group and it sounds like between now and 2026, there could be incremental demand for 7G drillships in the range of somewhere between 5% to 10%. Is that a number that you guys like when kind of parse through your commentary, is that a number that we could get to as well?

[Jeremy Thigpen, executive]

Yes, absolutely. That would, in fact, would be our number basically 5% to 10% incremental mix [technical difficulty] all the sense in the world.

[Kurt Hallead, analyst]

Okay. That's awesome. So Jeremy, maybe for you or Keelan either way. There had been a relative lull in the cadence of contract to teams up until recently. And the contracts that have been signed have now pushed above that $500,000 a day marker. How do you see things evolving from here? Do we expect maybe there just to be a kind of a digestion period of what's been announced and then potentially another kind of spurt as we get towards year-end? Or is that spurt going to be more of a 2025 kind of dynamic?

[Jeremy Thigpen, executive]

Yes. I'll take that and Roddie and Keelan can sign in as appropriate. We said in the last call because there was a lot of talk about the lull in contracting activity. We said, listen, we haven't been this busy in the last decade. We are -- they're all direct negotiations with the vast majority of them, so you don't see them. You don't see all the conversations that are taking place behind the scene, but we said they're a little bit slower to execute these contracts because the dollar values are so substantial now. Back during the downturn, when you're talking about 1 or 2 wells at $253,000 a day, our customers could get those approved really quickly because it didn't make that much of a financial impact to them. Now we're talking about $500,000 a day plus over multiple years. And the approval process is pretty lengthy and the turns and conditions and negotiating of those get pretty onerous. And so it just takes a little longer to work through the system. And as we saw here, reaching with our fleet status report and then the recent announcement of BP, sometimes they all come in a flurry. It doesn't mean there's so much activity that's going on in the background right now, and there's so much still in front of us. I mean I would hope and expect that we'll have more announcements like these as we move through the rest of the year because we're in deep negotiations, deep conversations with our customers who all want to push these programs forward. It just takes a little bit longer for them to get all the necessary approvals internally and through their partners. And so the cadence, I couldn't tell you. I don't know that we'll see a great floor like we did here over the course of the last couple of months, all at once, but I do expect multiple contracts to be executed and announced over the course of the coming weeks and months.

[Roddie Mackenzie, executive]

Yes. I'll just add a little bit to that. I think there's a bit of a misunderstanding or a disconnect between what's reported as supply and demand amongst the analysts and what we actually see. So to Jeremy's point, we've never seen a lull in contracting activity. There may have been kind of a pause in some of time when the fixtures were made. But as we had articulated before, the decisions are much bigger now, right? So you're talking about much larger programs, higher day rates, and those take longer. But now we're seeing a rapid acceleration in these awards. And 2024 is already to this point of the year, a great contracting year for us, and we expect it to be even better by the end. So it could be one of our best ever contracting years. So there's obviously a tremendous number of announcements on our fleet that we're very proud of, but we expect a significant number more still to come. And I think you'll see that our backlog has already climbed if we include the BP fixture that we just announced, we're sitting currently at $9.1 billion, and we expect that to grow even further. So I think it's going to be a prolific year.

[Kurt Hallead, analyst]

Awesome. And then one for Thad. So that given where the backlog currently sits today and the average rates in the backlog and so on, how can we think about the prospect of converting that backlog into cash flow and then into outright debt reduction? Maybe following on one of the questions that we said earlier. But again, assuming no change in current backlog or day rate structure, how does that convert to cash flow? And how much debt can you take that in the use over the next couple of years?

[R. Vayda, executive]

So as I mentioned, we do have one of [technical difficulty] debt associated with our [technical difficulty] and sort of from this point on, we anticipate that there'll be a steady growth in cash flow available to address the balance sheet. In the natural course, we anticipate that by the end of 2026 or thereabouts, we'll be in the neighborhood of $4.7 billion of debt and then that goes down significantly in the next [technical difficulty]. The objective here is to put every available dollar of cash flow that makes sense into improving the condition of the balance sheet. It's going to be a capital allocation exercise. We anticipate that there will be opportunities to put some of our cold stacked assets back to work. There's always going to be a timing difference, notwithstanding the discipline that will exercise and ensuring the customers pay for those when we get the appropriate return. But given that our valuation is predicated primarily on our ability to reduce debt, it makes sense for us to deploy every dollar that we can to that purpose.

[Operator]

We'll take our next question from Doug Becker with Capital.

[Doug Becker, analyst]

So it looks like the Atlas contract mix distinction between drilling and 20,000 completion activity and then taking a look at the Invictus, I'm guessing there's probably some Kaskida drilling associated with that as well. So curious if you're seeing the 20,000 drilling versus completion market evolving in a way that the contracts are getting consistently making some type of distinction between drilling versus completion.

[Roddie Mackenzie, executive]

Yes. Look, that's not the case going forward. This is actually just a small anomaly that essentially. The plan here was always to make the Atlas a completion centric vessel simply because you have the features of 20000 that nobody else does. So we're basically at the point now that the 20000 market is now mature enough and there's a pipeline of many, many different prospects that we would expect to keep her focused on 20,000 completions going forward. So this is really just the evolution of what, from when we took delivery of the rig all the way through its kind of maiden contract and then into these extensions that we've had. And going forward after that point, she will be very focused on 20000 because now there's very significant demand for 20,000.

[Doug Becker, analyst]

It completely makes sense. And then a quick one for Thad. The annual guidance seems to imply that O&M expense will decline in the fourth quarter. It's just hoping you could talk about that at just a high level what some of the moving parts might be on that.

[R. Vayda, executive]

I think the O&M guidance is generally consistent with what we articulated last quarter. There may be a slight decline. It's going to be a function of the amount of the O&M costs that were deferred in this period are spread over the next couple of quarters. But generally, I'd expect it to be close to flat. There's a rounding element in there as well.

[Operator]

Thank you. And in the interest of time, our final question will come from Josh Jayne with Daniel Energy Partners.

[Josh Jayne, analyst]

Thanks. First one I had is just on the Gulf of Mexico. In your prepared comments, you talked about the market being in balance, but that there are a number of gap filler type programs to be awarded. I was hoping you could elaborate on that in those opportunities a little bit. And then also just expand on your outlook for the Gulf of Mexico over the next 12 to 24 months?

[Roddie Mackenzie, executive]

Yes. So look, as we see it there, we have to talk about gap filler, but as we mentioned before, one is under an LOI, we expect another one option. So the likelihood of them actually being gas fillers are very small. They're going to hopefully turn into firm term very soon. And that really puts us in a fantastic position for visibility. So you asked about the outlook for the Gulf of Mexico. As we look at it, our fleet in the Gulf, assuming that we close these last couple of little pieces, is essentially sold out for a very significant period of time. Some of the rigs sold out for several years going forward. But as we think about the availability that we have, we have very little availability over the next 24 months. And -- the great thing about that is not only do we have the visibility to the activity, but all of the rates that we've booked in the Gulf of Mexico for these longer-term pieces are very attractive. So that's expected to generate very substantial cash flows and really part of the strategy that we've had all along about keeping the right assets available for the right opportunities. And now we're seeing that coming through in spades.

[Josh Jayne, analyst]

Thanks and then one thing I wanted to go back to that was also in the prepared remarks. I think I missed the detail, but you talked about a level of CapEx increasing from 2024 through 2027. That was largely going to be driven by expansions in South America and Africa. I just was hoping you could go back to that a little bit. And then for that level of CapEx increase, could you talk about how many rigs ultimately you would expect that to consume. You talked about the 5 to 10, maybe 12 months from now, but just how you're thinking about that level of CapEx increase and what the rig count -- what it could consume in 2027. Thank you.

[Jeremy Thigpen, executive]

Sorry, could you repeat the question? We're all -- it was a little bit muffled.

[Josh Jayne, analyst]

Sorry about that. Yes, I'm here. Sorry. So in the prepared remarks, you had said something about a level of CapEx that was expected to increase. I think it was more than 100% from 2024 through 2027, which was going to be driven by Deepwater activity in South America and Africa. And I was just curious if you could repeat those numbers and talk about how many rigs that would ultimately consume from going from sort of where we are today to them.

[Jeremy Thigpen, executive]

Oh, I'm sorry. You're talking about the total green exploration CapEx not our CapEx... We thought you were talking about our CapEx... Which is a decline

[Josh Jayne, analyst]

No, no, no. Sorry about that.

[Jeremy Thigpen, executive]

So in the prepared remarks, it was global offshore greenfield exploration and production investments are projected to grow to $110 billion in [technical difficulty] that's up 129% from $48 billion in 2024. And so that is what we believe is going to be driving the incremental 5 to 10 rigs that we discussed earlier on the call in one of the Q&A sessions. So I mean just that level of incremental capital is obviously going to lead to an increase. And so that's really what's giving us the kind of the confidence that we will see an increase in rig count. And since we're already at 98% utilization on the active fleet, this is going to lead to customer finance reactivations. And so that does give us some confidence that we will ultimately begin reactivating some assets here in the not-too-distant future.

[Operator]

Thank you. And I will now turn the call back over to our host Alison Johnson for any additional or closing remarks.

[Alison Johnson, executive]

Thank you, Britney, and thank you, everyone, for your participation on today's call. We look forward to talking with you again when we report our third quarter 2024 results. Have a good day.

[Operator]

Thank you. This does conclude today's program. Thank you for your participation. You may disconnect at this time and have a wonderful day.