Q4 2022 Noble Corporation PLC Earnings Call

February 27, 2023

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Operator: Good morning, and welcome to Noble Corporation's Q4 2022 financial results conference call. All participants are in a listen-only mode. After the speaker's presentation, we will conduct a question and answer session. To ask a question, you'll need to press Star followed by the number one on your telephone keypad. As a reminder, this conference call is being recorded. I would now like to turn the call over to Ian Macpherson, Vice President, Investor Relations. Please go ahead.

Good morning, and welcome to Noble Corporation's fourth quarter 2022 financial results conference call.

All participants are in a listen only mode. After the speaker's presentation, we will conduct a question and answer session.

To ask a question you'll need to press star followed by the number one on your telephone keypad.

As a reminder, this conference call is being recorded.

I would now like to turn the call over to Ian Macpherson, Vice President of Investor Relations. Please go ahead.

Ian Macpherson: Thank you, Julianne, and welcome everyone to Noble Corporation's Q4 2022 earnings conference call. We appreciate your continued interest in the company. You can find a copy of our earnings release issued yesterday evening, along with the supporting statements and schedules, on our website at noblecorp.com. Also located adjacently on the website is a Q4 earnings slides presentation that we will make reference to during this call as well. Joining me today are Robert Eifler, President and Chief Executive Officer, and Richard Barker, Senior Vice President and Chief Financial Officer. Also joining are Blake Denton, Senior Vice President of Marketing and Contracts, and Joey Kawaja, Senior Vice President of Operations. For today's call, we will begin with prepared remarks followed by Q&A.

Thank you Julian and welcome everyone to Noble Corporation's fourth quarter 2022 earnings Conference call. We appreciate your continued interest in the company.

You can find a copy of our earnings release issued yesterday evening, along with the supporting statements and schedules on our website at <unk> Dot Com also lake located adjacent lay on the website as a fourth quarter earnings slides presentation that we will make reference to during this call as well.

Joining me today are Robert Eifler, President and Chief Executive Officer, and Richard Barker Senior Vice President and Chief Financial Officer also joining are Blake Denton Senior Vice President of marketing contracts and Joey can watch us senior Vice president of operations.

For today's call, we will begin with prepared remarks, followed by Q&A. During the course of our call. We may make certain forward looking statements regarding various matters related to our business and companies that are not historical facts such statements are based on upon current expectations and assumptions of management and are.

Ian Macpherson: During the course of our call, we may make certain forward-looking statements regarding various matters related to our business and companies that are not historical facts. Such statements are based upon current expectations and assumptions of management and are therefore subject to risks and uncertainties. Many factors could cause actual results to differ materially from these forward-looking statements, and Noble does not assume any obligation to update these statements. Please refer to our SEC filings for more information regarding our forward-looking statements. Investors should carefully read our previous and ongoing disclosure with respect to these events, including our press release issued yesterday and other filings with SEC.

And therefore subject to risks and uncertainties.

Many factors could cause actual results to differ materially from these forward looking statements and noble does not assume any obligation to update. These statements. Please refer to our SEC filings for more information regarding our forward looking statements.

Investors should carefully read our previous and ongoing disclosure with respect to with respect to these events.

Including our press release issued yesterday and other products with SEC.

Ian Macpherson: Also, note that we're referencing non-GAAP financial measures on the call today, and you can find the required supplemental disclosure for these materials, including the most directly GAAP measure and associated reconciliation in our earnings report, as well as our filings with the SEC. With that, I'd now like to turn the call over to Robert Eifler, President and CEO.

Also note that we're referencing non-GAAP financial measures on the call today and you can find the required supplemental disclosure for these materials, including the most directly GAAP measure and associated reconciliation in our earnings report as well as our filings with the SEC and with that I'd now like to turn the call over to Robert Eifler, Our president and CEO .

Robert Eifler: Thank you, Ian. Good morning. Welcome everyone, and thank you for joining us on the call today. I'd like to begin with some opening remarks and a brief update on our integration progress, and then provide some views on the market outlook and regional demand perspectives before turning the call over to Richard to review the financial results and outlook. Starting on page 3 of our earnings slide deck, 2022 was indeed a transformational year for Noble, culminating with the business combination with Maersk Drilling that has created a leading player in ultra-deepwater drillships and harsh environment jackups. We're now approaching the 5-month milestone since closing the business combination with Maersk Drilling, and I couldn't be prouder and more appreciative of our offshore and shore-based teams around the world, who have made these first and most crucial few months of this integration go as smoothly as it has.

Thank you Ian and good morning, welcome everyone and thank you for joining us on the call today.

I'd like to begin with some opening remarks and a brief update on our integration progress and then provide some views on the market outlook and regional demand perspective before turning the call over to Richard to review the financial results and outlook.

Starting on page three of our earnings Slide deck 2022 was indeed, a transformational year for noble, culminating with the business combination with Maersk drilling that has created a leading player in ultra deepwater drillships and harsh environment Jackups.

Robert Eifler: We're now approaching the 5-month milestone since closing the business combination with Maersk Drilling, and I couldn't be prouder and more appreciative of our offshore and shore-based teams around the world, who have made these first and most crucial few months of this integration go as smoothly as it has.

We're now approaching the five months milestone since closing the business combination with Maersk drilling and I couldnt be prouder and more appreciative of our offshore and shore based teams around the world.

You have made these first and most crucial few months of this integration goes smoothly as it has.

Robert Eifler: To our employees on the call, we asked each of you to check your egos at the door and to heed the mantra of listen, learn, and lean in. Well, that is exactly the response that we've gotten. I'd just like to say a huge thank you for the tremendous effort and commitment that you've given. We still have work ahead of us, but we're off to a great start. Richard will speak more to the financial elements of this in the next few slides during his remarks. Now on to the market outlook. In short, the fundamental setup for our industry is arguably the best that it has looked in the past 20 years, based on a confluence of macro supply and demand factors. Leading indicators on offshore project sanctioning uniformly point to a sustained multi-year upturn in offshore investment and rig demand.

To our employees on the call we ask each of you to check your egos at the door and to heed the mantra of listen learn and lean in.

Well that is exactly the response that we've gotten and so I'd just like to say a huge thank you for the tremendous effort and commitment that you've given we.

We still have work ahead of us, but we're off to a great start.

Richard will speak more to the financial elements of this in the next few slides during his remarks.

Robert Eifler: Now on to the market outlook. In short, the fundamental setup for our industry is arguably the best that it has looked in the past 20 years, based on a confluence of macro supply and demand factors. Leading indicators on offshore project sanctioning uniformly point to a sustained multi-year upturn in offshore investment and rig demand.

Now on to the market outlook.

In short the fundamental setup for our industry is arguably the best that it has worked in the past 20 years.

Just on a confluence of macro supply and demand factors, leading indicators on offshore project sanctioning uniformly point to a sustained multiyear upturn in offshore investment in rig demand.

Robert Eifler: Our near-term commercial pipeline for 2023 and 2024 confirms as much. We're also observing an interesting increase in licensing bid rounds in several frontier regions that further support the demand story. All of these improving demand signals are a result of an upstream sector that is finally inflecting after a decade of structural under-investment. The world runs on oil and gas and will continue to do so for decades. In the new energy order, the largest producers are prioritizing lowest lifting cost and lowest carbon profile barrels of production, both of which align squarely with Noble's fleet positioning. While the value to over volume imperative for upstream producers has both validity and a sense of permanence, it is not to be mistaken for a cap on growth.

And our near term commercial pipeline for 2023, and 'twenty four confirms as much.

We're also observing an interesting increase in licensing bid rounds in several frontier regions that further support the demand story.

All of these improving demand signals are a result of an upstream sector that is finally, inflicting after a decade of structural underinvestment.

The world runs on oil and gas and we'll continue to do so for decades in the new energy order. The largest producers are prioritizing lowest lifting cost and lowest carbon profile barrels of production.

Both of which aligns squarely with Noble's fleet positioning.

And while the value to over volume imperative for upstream producers has both the validity and the sense of permanence. It is not to be mistaken for a cap on growth on the contrary they call on hydrocarbon production growth over the next decade, Israel with international deepwater set to command a rising share of investment.

Robert Eifler: On the contrary, the call on hydrocarbon production growth over the next decade is real, with international deepwater set to command a rising share of investment, as indicated by an expected sharp increase in greenfield FIDs over the next two years relative to prior decade levels. The supply side of the offshore rig market has been comprehensively redefined by fleet attrition, capital flight, and tightening, and a much more economically rational, competitive structure. All of which, of course, stand in complete contrast with the fast and loose growth at all costs market conditions that derailed the broader energy industry during prior commodity upcycles since the early 2000s. Meanwhile, threshold utilization for most rig classes has been eclipsed over the past year, and day rates continue to rise in direct correlation with incremental demand growth. Deepwater, in particular, has taken another significant leg higher over the past several months.

As indicated by unexpected sharp increase in Greenfield F. I DS over the next two years relative to prior decade levels.

The supply side of the offshore rig market has been comprehensively redefined by fleet attrition capital flight in tightening and a much more economically rational competitive structure all of which of course standing complete contrast, with a fast and loose growth at all cost market conditions that derail the broader energy industry.

During prior commodity upcycle since the early two thousands.

Robert Eifler: Meanwhile, threshold utilization for most rig classes has been eclipsed over the past year, and day rates continue to rise in direct correlation with incremental demand growth. Deepwater, in particular, has taken another significant leg higher over the past several months.

Meanwhile.

Threshold utilization for most rig classes has been eclipsed over the past year and day rates continue to rise in direct correlation with incremental demand growth.

Deep water in particular has taken another significant leg higher over the past several months.

Robert Eifler: The contracted UDW rig count in H1 2022 averaged ±80 rigs, with 86% utilization of the marketed fleet. Today, the contracted UDW count has reached 91 rigs and rising with 91% marketed utilization, while utilization of the approximately 45 Tier One drillships remains above 95%. Consequently, not only are Tier One drillships pricing firmly in the low to mid $400,000s per day with an upward tilt, the lower capability UDW rigs are also being pulled higher. Yes, there has been some recent transacting and capital formation behind a handful of sideline UDW rigs, of which there are approximately 12 7G drillships between cold stacked units and stranded new builds. However, the majority of these are not necessarily fully Tier One ready in terms of being equipped with two BOP stacks.

The contracted U D. W rig count in the first half of 2022 average plus or minus 80 rigs with 86% utilization of the marketed fleet today.

Today, the contracted you D. W. Count has reached 91 rigs and rising with 91% marketed utilization our utilization of the approximately 45 tier one drillships remains above 95%.

Consequently, not only our tier one drillships pricing firmly in the low to mid 400 thousands per day.

With an upward tilt.

The lower capability U D. W rigs are also being pulled higher.

Yes, there has been some recent transacting in capital formation behind the handful of sideline you DW rigs of which there are approximately a dozen a dozen seven G. Drillships between cold stack units and stranded in new builds. However, the majority of these are not necessarily fully tier one ready in terms of being equipped with two B O P. <unk>.

Robert Eifler: In any event, this pool of sidelined capacity is both finite and fully required to meet expected incremental demand growth, especially given the most recent developments with UDW utilization moving into scarcity territory. Also, the fact that established drilling contractors are prioritizing investment in 7G drillships stranded in shipyards is also a very clear indication, in our view, that most of the stacked 6G rigs in the world are becoming more and more marginalized with the passage of time. Moreover, the timing of the reactivation of these sidelined drillships will continue to be spread out due to disciplined contractor bidding, significant lead times for reactivation, and a limited number of multi-year tenders in the market that would be adequate to underwrite a compelling guaranteed return for a major capital project.

In any event this pool of sideline capacity as both finite and fully required to meet expected incremental demand growth, especially given the most recent developments with E D. W utilization moving into scarcity territory.

Also the fact that established drilling contractors are prioritizing investment in 17 Drillships stranded in shipyards is also a very clear indication in our view the most of the stacked 60 rigs in the world are becoming more and more marginalized with the passage of time.

Moreover, the timing of the reactivation of these sideline drillships will continue to be spread out due to disciplined contractor bidding significant lead times for for reactivation in a limited number of multi year tenders in the market that would that would be adequate to underwrite a compelling guaranteed return for made for a major capital project.

Robert Eifler: As a reminder, we have selectively marketed our cold-stacked Tier 1 drillship, Meltem, which we're budgeting as a $100 million all-in reactivation project with at least a 1-year delivery timeline. We continue to take a very disciplined approach with bidding the Meltem, which is to say that we would require a firm guaranteed contract with an attractive full payout plus return on capital in order to move forward with its reactivation. Looking forward at the global deepwater demand outlook, all indicators from our internal commercial perspective and customer dialogue to analyst and consultant research point to a probable multi-year rise in UDW rig demand.

As a reminder.

We have selectively marketed or cold stacked tier one drillship melt them, which we're budgeting as a $100 million all in rack reactivated reactivation project.

With at least a one year delivery timeline.

We continue to take a very disciplined approach with bidding the melt them, which is to say that we would require a firm guaranteed contract within attractive full payout plus return on capital in order to move forward with its reactivation.

Looking forward at the global deepwater demand outlook, all indicators from our internal commercial perspective, and customer dialogue to analysts and consultant research.

Two a probable multiyear rise in new DW rig demand.

Robert Eifler: Rystad, for example, is currently forecasting total floater demand to increase by 11% from 113 rig years in 2022 up to 125 rig years in 2023 on the way to a peak of 150 by 2026. While we would certainly love to see that level of demand to materialize, the truth is that even a modest increase of demand this year could likely exert further upward pressure on day rates. The fulcrum of demand growth for deepwater continues to be the Golden Triangle, and especially South America and West Africa. Starting in Brazil, Petrobras has been by far the most active operator in terms of securing rig capacity recently, comprising nearly 40% of all drillship rig years contracted throughout 2021 and 2022. A lot of this has been renewing and extending existing capacity.

Rice Dead. For example is currently forecasting total floater demand to increase by 11% from 113 rig years in 2022 up to 125 rig years in 2023 on the way to a peak of 150 by 2026.

While we would certainly love to see that level of demand and materialize. The truth is that even a modest increase of demand this year could likely exert further upward pressure on day rates.

The fulcrum of demand growth for deepwater continues to be the Golden triangle, and especially South America and West Africa.

Starting in Brazil, Petrobras has been by far the most active operator in terms of securing rig capacity recently, comprising nearly 40% of all drillship rig years contracted throughout 'twenty, one and 'twenty two.

A lot of this has been renewing and extending existing capacity, but still Petrobras is deepwater rig count has recently increased from plus or minus 20 rigs throughout most of the past two years to 24 rigs today and on the way to 26 with recent signings summer.

Robert Eifler: Still, Petrobras' deepwater rig count has recently increased from ±20 rigs throughout most of the past two years to 24 rigs today and on the way to 26 with recent signings. Some research indicates that Brazil could absorb an additional 10 to 11 rigs over the next year or so, although it's frankly hard to see where that much capacity could be sourced. Nonetheless, we do believe that Petrobras could realistically take an incremental 5 to 7 floaters over the next 12 to 18 months. Beyond Brazil, other South America, which represents 9 floaters of demand currently, could add an additional 1 to 2 rigs through 2023 and 2024. We're also seeing some pretty interesting leading indicators in this part of the world beyond the tangible near-term rig requirements.

Some research indicates that Brazil could absorb an additional 10 to 11 rigs over the next year or so although it's frankly hard to see where that much capacity could be sourced. Nonetheless, we do believe that Petrobras could realistically taken incremental five to seven floaters over the next 12 to 18 months.

Beyond Brazil.

Other South America, which represents nine floaters of demand currently could add an additional one to two rigs through 'twenty three and 'twenty four.

We're also seeing some pretty interesting leading indicators in this part of the world beyond the tangible near term rig requirements.

Robert Eifler: I'm referring to the emergence or re-emergence of frontier markets like Colombia on the deepwater side and Argentina on the jackup side, as well as increasing license bid round activity in places like Uruguay, Ecuador, and parts of the Caribbean. After South America, West Africa has become the second most dynamic region for deepwater rigs. We're seeing a significant increase in tendering driven by Angola, Nigeria, and the emergence of Namibia as an important exploration basin. West Africa was a late mover off the bottom, but it's now moving higher in a meaningful way, with several multi-year drillship requirements surfacing. Current marketed utilization of UDW units in the region is 18 out of 19 rigs, and we see a likely supply deficit of around 3 units by 2024.

I'm, referring to the emergence of reemergence.

The frontier markets like Colombia on the deepwater side in Argentina on the Jackup side as well as increasing licensed bid round activity in places like Uruguay, Ecuador and parts of the Caribbean.

After South America West Africa has become the second most dynamic region for deepwater rigs.

We're seeing a significant increase in tendering driven by Angola, Nigeria, and the emergence of Namibia is an important exploration basin west.

West Africa was a late mover off the bottom, but it's now moving higher in a meaningful way with several multi year drillship requirement surfacing.

Current marketed utilization of <unk> units in the region is 18 out of 19 rigs and we see a likely supply deficit of around three units by 2024.

Robert Eifler: The deepwater Gulf of Mexico has been more of a steady market with between 20 to 22 rigs of demand for the past couple of years, and we're not counting on a significant change here over the near term. However, the bias looks flat to up by perhaps 1 or 2 incremental rigs through 2024. The shorter-term nature of most of the contracting and the role played by more of the nimble, independent E&Ps on the demand side makes the Gulf of Mexico a little harder to forecast by nature. That's the outlook for the Golden Triangle, which comprises about 75% of the total UDW market and an even higher percentage of the current placement of our fleet. Additionally, however, both Australia and the Med look like they could each contribute a further 1 to 2 rigs of demand to global balances.

The deepwater Gulf of Mexico has been more of a steady market was between 'twenty to 'twenty two rigs of demand for the past couple of years and we're not counting on a significant change here over the near term. However, the bias looks flat to up but perhaps one or two incremental rigs through 2024.

The shorter term nature of most of the contracting and the role played by more of the nimble independent E&ps on the demand side. It makes it a gulf of Mexico, a little hard to harder to forecast by nature.

Robert Eifler: That's the outlook for the Golden Triangle, which comprises about 75% of the total UDW market and an even higher percentage of the current placement of our fleet. Additionally, however, both Australia and the Med look like they could each contribute a further 1 to 2 rigs of demand to global balances.

So that's the outlook for the Golden Triangle, which comprises about 75% of the total U D. W market and an even higher percentage of the current placement of our fleet.

Additionally, however, both Australia and the med it looked like they could each contribute a further one to two rigs of demand to global balances.

Robert Eifler: Other peripheral markets outside of these are projecting roughly flat in total. That gets us to a global roll-up of about 12 to 15 incremental UDW rigs over the next 12 to 18 months. If this demand level does in fact materialize, we should expect to see a combination of an upward day rate movement and more sidelined capacity entering the market. These are not mutually exclusive outcomes. Now for a few comments on our own deepwater fleet status and outlook as summarized on pages 6 and 7 of the slides. Since our last fleet status report in early November, we have secured 24 months of additional backlog across our four 6G and 7G drillships at an average day rate above $420,000.

Other peripheral markets outside of these are projecting roughly flat in total so that gets us to a global roll up of about 12 to 15 incremental U D. W rigs over the next 12 to 18 months.

If this demand level does in fact materialize then we should expect to see a combination of upward day rate movement and more sideline capacity entering the market.

These are not mutually exclusive outcomes.

Now for a few comments on our own deepwater fleet status and outlook are summarized on pages six and seven of the slides.

Since our last fleet status report in early November we have secured 24 months of additional backlog across our four.

<unk> four <unk> and <unk> Drillships at an average day rate above $420000. This includes the nine month contract for the jury to Suzhou, which started recently in Nigeria, the six well program for the Stanley Lafalce in the in the Gulf of Mexico.

Robert Eifler: This includes the 9-month contract for the Jerry de Souza, which started recently in Nigeria, the 6-well program for the Stanley Lafosse in the Gulf of Mexico, a 1-well contract for the Faye Kozack in the Gulf of Mexico at $450,000 per day, and a 70-day P&A scope for the Globetrotter I, also in the Gulf of Mexico. The Globetrotter I's preceding contract with Pemex in Mexico has encountered a delayed start, however, and presently remains off-contract awaiting permit approvals. We believe this delayed permitting process represents a deviation from past precedent by the regulator there, and we continue to work diligently towards a solution. Our fleet status report now indicates an expected start date for this contract in March. However, the permitting process remains fluid.

A one well contract for the Fei Kozak in the Gulf of Mexico at $450000 per day, and a 70 day P&A scope for the Globetrotter one also in the Gulf of Mexico.

The globetrotter ones preceding contract with Petronas in Mexico has encountered a delayed start however, and presently remains off contract awaiting permit approvals. We believe this delayed permitting process represents a deviation from past precedent by the regulator there and we continue to work diligently towards a solution.

Fleet status report now indicates an expected start date for this contract in March however, the permitting process remains fluid.

Robert Eifler: Our 16 marketed UDW rigs are currently 75% contracted throughout 2023, with visibility towards securing additional utilization for a portion of the remaining availability for this year. Although some contract gaps and SPS time will remain uncontracted. The average day rate across our $2.7 billion floater backlog today is approximately $400,000. With over half of our 2024 floater days uncommitted, an upward trajectory for repricing the fleet is visible based on current market dynamics. We're very optimistic about how our deepwater fleet is positioned at the moment with a good ballast of backlog, but also 15 out of our 16 working rigs exposed to current or future market rates over the next year. Next on to jackups, which is an improving but still later cycle dimension to our fleet.

Our 16 marketed you D. W rigs are currently 75% contracted throughout 2023.

With visibility towards securing additional utilization for a portion of the remaining available availability for this year.

Although some contract gaps N S. P. S time will remain uncontrolled did.

The average day rate across our $2 7 billion dollar floater backlog today is approximately $400000 and with over half of our 2024 floater days uncommitted and upward trajectory for repricing. The fleet is visible based on current market dynamics.

So we're very optimistic about how our deepwater fleet is positioned at the moment with a good balance of backlog, but also 15 out of our 16 working rigs exposed to current or future market rates over the next year.

And next onto Jackups, which is an improving but still later cycled dimension to our fleet.

Robert Eifler: Globally speaking, the roughly 400-rig jackup market eclipsed 90% effective utilization in the middle of last year, driven primarily by the demand surge in the Middle East. However, in the North Sea and Norway region, where our harsh and ultra-harsh jackup fleet is now principally positioned, the market has been softer recently. Current activity in the North Sea/Norway region is 28 rigs with utilization at 85%. This is down from a 31 to 33 rig count during H1 of last year. The net impacts of tax policy levers out of the UK have not been stimulative for jackup activity in the North Sea over the short term. We continue to see encouraging demand indicators that support the case for an improving market from here forward, including, crucially, visible demand improvement in Norway from mid-2024.

Globally speaking, the roughly 400 rig jackup market eclipsed 90% effective utilization in the middle of last year, driven primarily by the demand surge in the middle East However, in the North Sea, and Norway region, where our harsh and ultra harsh Jackup fleet is now principally positioned the market has been softer recently.

Current activity in the North Sea, Norway region is 28 rigs with utilization at 85%. This is down from 31 to 33 rig count during the first half of last year.

The net impacts of tax policy levers out of the U K have not been stimulative for jackup activity in the North sea over the short term but.

We continue to see encouraging demand indicators that support the case for an improving market from here forward, including crucially visible demand improvement in Norway from mid 2024.

Robert Eifler: We believe this could provide decent earnings upside for Noble in 2024, 2025 compared to a fairly anemic jackup EBITDA contribution in 2023, which, depending on contracting results this year, is about 10% of our total EBITDA guidance. Naturally, a huge key to better margins is utilization, not just day rates, and the white space will certainly weigh on margins over the near term. This includes also the likelihood of losing at least most of this year for the Noble Regina Allen. On the positive side, during Q4, the Noble Innovator was awarded a 1-year contract with BP in the UK North Sea at $135,000 per day, with a 1-year option with day rate escalation. This is a premium rate for the UK based on the Innovator's high technical capability as a CJ70.

We believe this could provide decent earnings upside for noble in 2020 for 2025 compared to a fairly anemic jackup EBITDA contribution in 2023, which depending on contracting results. This year is about 10% of our total EBITDA guidance Natura.

Naturally a huge key to better margins as utilization not just day rates and the white space will certainly weigh on margins over the near term.

This includes also the likelihood of losing at least most of this year for the Regina Allen.

On the positive side during the fourth quarter. The noble innovator was awarded a one year contract with BP in the U S U K North sea at $135000 per day with a one year option with day rate escalation. This is a premium rate for the U K based on the innovators high technical capability is a C. J 70, but nonetheless, we do see.

Robert Eifler: nonetheless, we do see day rate improvement for the other harsh environment class rigs into the $110,000 to $125,000 range, up from sub-100 rates through the recent trough. I'd also like to highlight that the Noble Resolve recently commenced the on-site pilot scope at Project Greensand, the world's first industrial-scale offshore carbon capture project offshore Denmark. Long-term market growth potential from offshore carbon capture could prove quite significant. In the meantime, we're proud to be an early leader in this field. Further east, Noble Tom Prosser has recently completed its contract with Santos in Australia in late January. While we don't have future work for the Prosser reflected on our fleet status report, we do have strong visibility for a significant amount of work for this rig starting around the middle of this year.

Day rate improvement for the other harsh environment class rigs into the 110 to $125000 range up from sub 100 rates through the recent trough.

I'd also like to highlight that the noble resolve recently commenced the onsite pilot scope. It project Greensand, the world's first industrial scale offshore carbon capture project offshore Denmark.

Long term market growth potential from offshore carbon capture could prove quite significant in the meantime, we're proud to be an early leader in this field.

Further east Noble Tom Prosser has recently completed its contract with Santos in Australia in late January .

While we don't have future work for the process reflected on our fleet status report, we do have strong visibility for a significant amount of work for this rig starting around the middle of this year.

Robert Eifler: Overall, we do have some space to fill across our fleet over the near term, but the opportunity set looks promising. That wraps up the market overview. With that, I'd like to pause now and turn it to Richard to go over the financials.

So overall, we do have some space to fill across our fleet over the near term, but the opportunity set looks promising.

That wraps up the market overview and with that I'd like to pause now and turn it to Richard to go over the financials. Thank you Robert and good morning, or good afternoon.

Richard Barker: Thank you, Robert, and good morning or good afternoon all. In my remarks today, I will go over some brief highlights of our Q4 results, provide an update on our synergy progress, go through our 2023 financial guidance, and highlight a few key points related to our return of capital program. Starting with our quarterly results. The Q4 was our first as a combined company with Maersk Drilling. As such, the type of prior period comparisons that we typically reference have less relevance, so I will dispense with the prior period comps for the purposes of this review. Additionally, as mentioned previously, we have included on our website a handful of earnings slides that summarize some of the key elements of our Q4 results.

My remarks today I will go over some brief highlights of our fourth quarter results provide an update on our synergy progress go through our 2023 financial guidance and highlight a few key points related to our return of capital program.

Starting with our quarterly results.

Fourth quarter was our first as a combined company with mask drilling as such the type of prior period comparisons that we typically reference have less relevance. So I will dispense with the prior period comps for the purposes of this review.

Additionally, as mentioned previously we have included on our website a handful of earning slides that summarize some of the key elements of our fourth quarter results.

Richard Barker: For Q4, which included 90 out of 92 total days as a combined company, our diluted earnings per share was $0.92. Contract drilling services revenue for Q4 totaled $586 million. Adjusted EBITDA was $157 million, with an adjusted EBITDA margin of 25% for the quarter. Additionally, we generated free cash flow of $106 million in the quarter. As previously cited, the downtime and cost impacts of the Noble Regina Allen incident, as well as the delayed contract start for the Noble Globetrotter I in Mexico, had adverse impacts on the quarter's financial results. On a combined basis, these two rigs represented a $15 million decrease to Q4 EBITDA relative to our expectations.

For the fourth quarter, which included 90 out of 92 total days as a combined company our diluted earnings per share was <unk> 92.

Contract drilling services revenue for the fourth quarter totaled $586 million adjusted EBITDA was 157 million for an adjusted EBITDA margin of 25% for the quarter.

Additionally, we generated free cash flow of $106 million in the quarter.

As previously cited the downtime and cost impacts of the noble Regina Allen incident, as well as the delayed contract start for the noble Globetrotter, one in Mexico had adverse impacts on the quarters financial results and on a combined basis. These two week represented a $15 million decrease to Q4 EBITDA relative to our.

Expectation.

Richard Barker: As we worked through the closing for the first integrated quarter as a combined company, certain impacts from the merger, including accounting impacts from the purchase price allocation, have served to partially offset this negative impact. Noble's year-end revenue backlog stands at $3.9 billion. Page 5 in the presentation slides provide a summarized schedule of backlog for floaters and jackups over the next 5 years. Our balance sheet remains in terrific shape, with December 31 net debt of approximately $200 million. Subsequent to the end of Q4, we have elected to repay the $150 million Denship finance loan with excess cash on-hand. In conjunction with our banking partners, we are currently evaluating alternatives to further optimize and simplify our capital structure. Before discussing our guidance for 2023, I would like to first provide a cost synergy update related to the business combination.

As we work through the closing for the first integrated cord as a combined company certain impacts from the merger, including accounting impacts from the purchase price allocation have served to partially offset this negative impact.

Noble's yearend revenue backlog stands at $3 9 billion.

Page five in the presentation slides provide a summarized schedule of backlog for floaters and Jackups over the next five years.

Our balance sheet remains in terrific shape with December 31st net debt of approximately $200 million.

Subsequent to the end of the fourth quarter, we have elected to repay the 150 million Danish ship finance loan with excess cash on hand and.

In conjunction with our banking partners. We are currently evaluating alternatives to further optimize and simplify our capital structure.

Before discussing our guidance for 2023, I would like to first provide a cost synergy updates related to the business combination.

Richard Barker: Our integration activities continue to progress strongly as we work towards realizing the target of $125 million in annual run rate cost synergies by October 2024. We expect to have realized over three-quarters of these savings on a run rate basis in Q4 of this year, and we achieved the first $50 million of run rate synergies as we exited 2022. As previously disclosed, we expect, in the aggregate, for the one-time cash cost to achieve these synergies to be within a range of $1 to $1.25 for every dollar of annual synergies realized. In calendar year 2023, we expect to have one-time cash costs of approximately $70 to 85 million related to achieving the cost synergies, leaving minimal thereafter. Now I will cover our guidance for 2023.

Our integration activities continue to progress as strongly as we work towards realizing the targeted $125 million in annual run rate cost synergies by October 2024.

We expect to have realized over three quarters of these savings on a run rate basis in the fourth quarter of this year and we achieved the first $50 million of run rate synergies as we exited 2022.

As previously disclosed we expect in the aggregate for the one time cash cost to achieve these synergies to be within a range of $1 to $1 25 for every dollar of annual synergies realized.

In calendar year 2023, we expect to have one time costs of approximately $70 million to $85 million related to achieving the cost synergies, leaving minimal thereafter.

Now I will cover our guidance for 2023, we.

Richard Barker: We anticipate total revenue to be between $2.35 and 2.55 billion. Adjusted EBITDA, which adds back merger and integration costs, to be between $725 and 825 million, and capital expenditures net of client reimbursables to be between $325 and 365 million. Additionally, note that our total revenue guidance is impacted by two items. Firstly, revenue includes the non-cash amortization related to net unfavorable customer contracts, a function of accounting rules for both the recent combination and our emergence. Secondly, revenue includes various client reimbursables, which generally carry a minimal margin. In total, these items are expected to contribute approximately $200 million of revenue in 2023, split somewhat evenly across the two items.

We anticipate total revenue to be between $2 35, and $2 55 billion adjusted EBITDA, which adds back merger and integration costs to be between 725, and $825 million and capital expenditures net of client reimbursable to be between 325 and $265 million.

Additionally, note that our total revenue guidance is impacted by two items.

Firstly revenue includes the noncash amortization related to net unfavorable customer contracts are function of accounting rules for both the recent combination and our emergence.

Secondly revenue includes various client reimbursable, which generally carry a minimal margin.

In total these items are expected to contribute approximately $200 million of revenue in 2023 split somewhat evenly evenly across the two items.

Richard Barker: Additionally, we expect our cash taxes in 2023 to be just over 10% of our adjusted EBITDA. Incorporated in our guidance is the anticipated impact of the recent contract termination for the Noble Regina Allen, as has been previously disclosed. We continue to develop the repair plans and the rig has applicable insurance coverage with a $5 million deductible. Given this insurance coverage, our guidance excludes any projected expense or capital required to repair the rig. However, there could be a timing difference between the payment of repairs and receipt of funds from our insurers. While we are not providing quarterly guidance, I would like to provide the basic directional comment that we have a couple of key factors at play that we anticipate should drive a progressively stronger contribution of both EBITDA and free cash flow as the year unfolds.

Additionally, we expect that cash taxes in 2023 to be just over 10% about adjusted EBITDA.

Incorporated in that guidance is the anticipated impact of the recent contract termination for the noble Regina Allen as has been previously disclosed we continue to develop the repair plans and the rig has applicable insurance coverage with a 5 million deductible.

Given this insurance coverage, our guidance excludes any projected expense or capital required to repair the rig however.

However that could be a timing difference between the payment of repairs and receipt of funds from Avon shows.

While we are not providing quarterly guidance I would like to provide probe to provide the basic direction will comment that we had a couple of key factors at play that we anticipate should drive a progressively stronger contribution of both EBITDA and free cash flow as the year unfolds.

Richard Barker: One expected factor is the momentum of day rates, with the fleet continuously repricing into an improving market. Secondly, we expect operating days to increase in H2. We currently expect to generate approximately 65% of our 2023 EBITDA in H2. Additionally, our 2023 adjusted free cash flow generation will be heavily weighted to H2. On last quarter's call, we cited recurring high single-digit percentage inflation rates across major OpEx and CapEx categories persisting throughout 2023, and that view is indeed embedded in our 2023 guidance today. Also, as previously stated, CapEx for this year, and likely to an even greater extent next year, is influenced by a higher than historical average number of SPSs across our fleet.

One expecting factor is the momentum of day rates with the fleet continuously repricing into an improving market.

And secondly, we expect operating days to increase in the second half of the year.

We currently expect to generate approximately 65% about 2022 EBITDA in the second half of the year. Additionally.

Additionally, at 2023, adjusted free cash flow generation will be heavily weighted to the second half of the year.

On last quarter's call, we cited reoccurring high single digit percentage inflation rates across major opex and capex categories assisting throughout 2023 and that view is indeed embedded in our 2023 guidance today.

Also as previously stated Capex for this year and likely to an even greater extent next year is influenced by a higher than historical average number of sps's across athlete.

Richard Barker: As the majority of our working fleet approaches its 10-year SPS, we have approximately half of our fleet due for these surveys over the course of 2023 and 2024. The reality with a typical rig life cycle is that the first 5-year survey is usually inconsequential in terms of capital and downtime. In addition to the capital for a deepwater rig, a 10-year SPS generally requires 30 to 60 days out of service. For 2023, excluding the Noble Regina Allen repairs, we have 7 rigs combined across our jackup and floater fleet planned for major projects.

As the majority of our working fleet approaches its 10 year Sps we have approximately half of athlete you for these surveys over the course of 2023 and 2024.

The reality with a typical rig lifecycle is at the first five year survey is usually inconsequential in terms of capital and downtime in.

In addition to the capital for deepwater rig attend USPS generally require 30 to 60 days out of service.

The 2023, excluding the Regina Allen in the past, we have seven weeks combined across our Jackup and floater fleet planned for major projects.

Richard Barker: While we expect the peak number of 10-year SPS to drive CapEx in 2024 to a level somewhat higher than 2023, with our schedule currently showing 10 major projects in 2024, our plan is to achieve five-year average annual CapEx in the $275 million area between 2023 and 2027 as the 10-year surveys taper off after 2024. It is important to note that there is a tightening impact on effective supply that results from structurally higher global fleet downtime caused by these SPS services, surveys over the next couple of years. An additional consideration is how the shipyard and OEM supply chain will respond to a handful of deepwater rig reactivations layered on top of the SPS spike. This is a recipe for pinch points, cost inflation, and delays.

While we expect the peak number of 10 USB drive Capex in 2024 to a level somewhat higher than 2023 with our schedule currently showing 10 major projects in 2024. Our plan is to achieve five year average annual capex in the 275 million area between 2023 and 2027 as the 10 year surveys.

Taper off after 2024.

It is important to note that there was a tightening impact on effective supply that results from structurally high global fleet downtime caused by these Sps services studies over the next couple of years and.

An additional consideration is how the shipyard and OEM supply chain will respond to a handful of deepwater rig reactivation laid on top of the Sps Spike.

This is a recipe for pinch points cost inflation and delays. However, we feel very confident that we have the right team and plans in place to knock out these major projects in an efficient manner.

Richard Barker: However, we feel very confident that we have the right team and plans in place to knock out these major projects in an efficient manner. Now, I'd like to wrap up with a quick refresh on capital allocation. We believe our conservative balance sheet and strong free cash flow results and outlook are differentiating factors for Noble. Since authorizing a $400 million share repurchase program in Q4, we have repurchased nearly $100 million in shares through January, including the mandatory purchase associated with a squeeze out of legacy Maersk Drilling shareholders. Returning capital is central to our capital allocation strategy. To restate our current priorities as it relates to the use of cash are as follows: To maintain what we believe is a conservative through-cycle balance sheet coupled with significant liquidity. To invest in the maintenance and maximum potential of our existing working fleet.

Now I'd like to wrap up with a quick refresh on capital allocation we.

We believe our conservative balance sheet and strong free cash flow results and outlook are differentiating factors for noble.

Since authorizing a $400 million share repurchase program in Q4, we have repurchased nearly $100 million in shares through January including the mandatory purchase associated with a squeeze out of legacy most willing shareholders.

Returning capital is central to our capital allocation strategy.

And to restate, our current priorities as it relates to the use of cash are as follows to.

To maintain what we believe is a conservative to recycle balance sheet, coupled with significant liquidity.

To invest in the maintenance and maximum potential of our existing working fleet.

Richard Barker: Once these objectives are achieved, we will look to return at least 50% of our free cash flow to shareholders and target disciplined and accretive investment opportunities. That concludes my prepared remarks and I'll now turn it over to Robert.

Once these objectives are achieved we will look to return at least 50% of our free cash flow to shareholders and target disciplined and accretive investment opportunities.

That concludes my prepared remarks, and I'll now.

Alright.

Robert Eifler: Thank you, Richard. To wrap it up here, we're increasingly confident in the outlook for a sustained multi-year upcycle for our business. It's a tight market today with structurally redefined supply governors that should drive further tightening as demand continues to recover from an unsustainably low baseline. We have an optimally positioned elite UDW fleet with an enviable backlog, and we're looking out into the future for fairly significant upside optionality from our jackup business, which is still under-earning in 2023. Noble will not deviate from our disciplined and conservative financial position and capital allocation framework, and we look forward to returning growing amounts of free cash flow to shareholders over the long run. Operator, we're ready to begin the Q&A segment of the call.

Thank you Richard.

So to wrap it up here, we're increasingly confident in the outlook for a sustained multiyear up cycle for our business.

It's a tight market today with structurally redefined supply governors.

That should drive further tightening as demand continues to recover from an unsustainably low baseline.

We have an optimally positioned elite U D. W fleet with an enviable backlog and we're looking out into the future for fairly significant upside optionality from our Jackup business, which is still under earning in 2023.

Noble will not deviate from our disciplined and conservative financial position and capital allocation framework and we look forward to returning growing amounts of free cash flow to shareholders over the long run.

Operator, we're ready to begin the Q&A segment of the call.

Operator: Our first question comes from Greg Lewis from BTIG. Please go ahead. Your line is open.

Thank you if you'd like to ask a question. Please press star followed by the number one on your telephone keypad to withdraw your question. Please press star one again.

There's still time, we please ask that you limit yourselves to one question and one follow up question. Thank you our.

Operator: Our first question comes from Greg Lewis from BTIG. Please go ahead. Your line is open.

Our first question comes from Greg Lewis from <unk>. Please go ahead. Your line is open.

Greg Lewis: Yeah, thank you. Thank you, and good morning, and good afternoon, everybody.

Yeah. Thank you. Thank you and good morning, good afternoon everybody.

Robert Eifler: Morning, Greg.

Greg Lewis: Hey, Robert. You know, Robert, I was hoping you could provide a little bit more color. You know, clearly one of the big things that people are watching is the potential of rig reactivations, and you alluded to the potential about, you know, we're looking to potentially activate, you know, looking for that right contract to reactivate potentially the Meltem. As we look globally, you know, could you talk about some of those opportunities? It seems like most of the rig reactivations we're hearing about are largely focused around Brazil.

Great.

Hey, Robert.

You know Robert I was hoping you could provide a little bit more color.

Clearly one of the big things that people are watching is the potential of rig reactivation and you alluded to the potential about.

We're looking at potentially act looking for that right contractor to reactivate potentially the Melbourne.

As we look globally.

Could you talk about some of those opportunities it seems like most of the rig reactivation as we're hearing about are largely focused around Brazil.

Greg Lewis: You know, I guess what I'm wondering is, as you look at potential opportunities for the Meltem, you know, how are you thinking about that rig and really, you know, where those opportunities potentially could be?

And I guess, what I'm wondering is as you look at potential opportunities for the melt them.

How are you thinking about that that rig and really.

Where those opportunities potentially could be.

Robert Eifler: Yeah, sure. Look, I think the Golden Triangle is gonna host the vast majority of the opportunities. Specifically, as you mentioned, Brazil and West Africa right now seem to be carrying, you know, the term that would be required. Whether it's specifically Petrobras or not is very much up in the air. Recall that to take a rig outside of Brazil into a Petrobras contract, there's a pretty hefty capital requirement.

Yes sure.

So look I think the Golden Triangle is gone is going to host the vast majority of the opportunities.

And specifically as you mentioned, Brazil and in West Africa, right now seem to be carrying the term that would be required.

Whether it's.

Specifically Petrobras or not is very much up in the air recall that to take a rig outside of Brazil into a Petrobras contract Theres, a pretty hefty capital requirement.

Robert Eifler: As we said, I didn't repeat it in the script today, but we have said previously, and we do hold to the idea that where we sit in 2023 in the bids that we're considering, we would be looking to get a significant portion of that $100 million up front so that we can maintain our cash flow story, which I think is unique to Noble. Realistically, in the very near term, I think those opportunities exist through the Golden Triangle. They're very few and far between. Today, more likely to be outside of a Petrobras contract than with Petrobras. The market is moving, and I think as we move through this year, that could change.

And so as we said I didnt repeat it in the script today, but we have said previously we do hold to.

Ah the idea that where we sit in 2023 and in the in the bids that we're considering we would be looking to get a significant portion of that $100 million upfront. So that we can maintain our cash flow story, which I think is unique to noble.

So realistically in the very near term I think those opportunities exist through the Golden triangle, they're very few and far between and today.

More likely to be outside of the Petrobras contract than with Petrobras, but the market is moving and I think our I think as we move through this year that could change there are a very small handful of opportunities that could come up for 24, and even 25 work.

Robert Eifler: There are a very small handful of opportunities, you know, that could come up for 2024 and even 2025 work that would exist outside the Golden Triangle. But we're just maintaining a constant dialogue with customers globally. I think you said my words for me, we're picking our opportunities very carefully and making sure it's the right opportunity for that rig.

That would exist outside the Golden triangle, but we're just maintaining a constant dialogue with with with with customers globally and I think I think you said said my words for me, where we're picking our our opportunities very carefully and are and making sure. It's the right opportunity for that rig.

Greg Lewis: Okay, great. Great. I did wanna touch on the jackup market. I mean, clearly, you know, post the Maersk acquisition, you guys have a very solid position in the North Sea. You know, that being said, it seems like at least in 2023, that's gonna be a little bit of an air pocket. You know, not only for floaters, but also for jackups, which is really what you guys run in the North Sea. As you think about that, you know, and those dynamics, is it kind of a let's just kind of wait it out for 2024, which is expected to see some improvements?

Okay, Great Great and then and then I did want to touch on the Jackup market I mean, clearly post the market <unk> acquisition, you guys have a very solid position in the north sea.

That being said.

It seems like at least in 'twenty, three that's going to be a little bit of an air pocket.

Not only for not only for floaters, but also for Jackups, which is really which is what can you guys run in the north sea. So as you think about that.

And those dynamics is it kind of a let's just kind of wait it out for 24, which is a better which is expected to see some improvements or could we think about maybe setting starting to try to.

Greg Lewis: Could we think about maybe setting up, you know, starting to try to you know find a you know another basin where maybe some of these rigs could go to kinda you know for employment until we see that actual North Sea shelf recovery?

Fine.

Another basin, where maybe some of these rigs.

<unk> could go to to kind of.

For employment until we see that actual north seaver.

Shelf recovery.

Okay.

Robert Eifler: Yeah, it's a good question. I'm not gonna put any rule down here because we've always been, I think, pretty economic in how we think through bidding and potentially moving rigs. The change in windfall profit tax in the UK was a pretty major headwind that came through a few months ago. It essentially put the market, which does have some movement back and forth between the UK and Norway, on its heels. Of course, we have a portion of our jackup fleet scattered outside of the North Sea.

Yeah, It's a good question.

And I'm not I'm not going to put any any rule down here because we've always been I think pretty economic in how we think through through bidding and potentially moving rigs.

The the windfall from the change in windfall profit tax in the U K was was a pretty major headwind.

That came through a few months ago and it essentially put the market, which does have some movement back and forth between the UK and Norway.

On its heels.

Four are in and of course, we have we have a portion of our Jackup fleet scattered out outside of the North Sea.

Robert Eifler: The highest and best use for the units that we own is in the North Sea, whether it's outside of Norway or within Norway, depending on the unit. We do believe that ultimately, that's the right home for these rigs. From current fleet positioning, we are not actively trying to remove rigs from the region. We are mindful of the white space and managing costs in the meantime. I think in particular, the Norway class vessels. We now have visible demand in 2024.

The highest and best use for for the units that we own is in the North sea, whether it's whether it's outside of Norway or within Norway, depending on the unit.

And we do believe that that ultimately.

That's the right home for these rigs.

So we are from from current fleet positioning.

We are not actively trying to remove rigs from the region.

We are mindful of the white space in managing costs in the meantime.

And I think in particular.

The Norway class vessels.

We have we now have visible demand in 2024.

Robert Eifler: It doesn't meet the total supply from what we see today, but it's also still too early on a sales cycle for even a CJ70 to fully understand what H2 2024 is gonna look like. We stick to the view that late 2024 is gonna bring back the demand for our CJ70 fleet. Those are the most capable rigs, Norway class jackups. They will contract before and stay active longer than other Norway class rigs because of their performance capability. They also have the ability to work in certain transition zone waters that would otherwise go to harsh semis.

It doesn't it doesn't.

The total supply from what we see today, but it's also still too early on on a sales cycle for for even for CJ 70.

To fully understand what the back half of 'twenty four is going to look like.

And so we stick to the to the to the view that late 'twenty four is going to is going to.

Bring back the demand for our CJ 70 fleet those are the most capable rigs.

Nor way class Jackups.

They will contract before.

And stay active longer than other Norway class rigs because of because of their because of their.

The performance capability and they also have the ability to work and certain transition zone waters that would otherwise go to harsh semis and that's very much a dynamic that's too early to conclude today, but but does exist as a pocket of demand for those rigs in 'twenty four and onwards.

Robert Eifler: That's very much a dynamic that's too early to conclude today, but does exist as a pocket of demand for those rigs in 2024 and onwards. That was a bit of a rambling answer, Greg. I think to sum it up, neither UK nor Norway class rigs we are actively seeking to relocate. We will always remain economic, though.

So that was a bit of a rambling answer Greg I think to sum it up.

Neither U K, nor Norway class rigs, we are actively seeking to relocate we will always remain economic though.

Greg Lewis: Okay. Okay. Yeah, no, I thought that was great, Robert. Thank you very much.

Okay. Okay.

Thought that was great Robert Thank you very much.

Robert Eifler: Thanks.

Thanks.

Operator: Our next question comes from Eddie Kim from Barclays. Please go ahead, your line is open.

Our next question comes from Eddie Kim from Barclays. Please go ahead. Your line is open.

Eddie Kim: Hi, good morning. Very constructive outlook for the floater market, which would suggest the day rates continue to move higher throughout the year. I hate to start with a leading question, but do you think it's likely that we'll see a floater fixture announced later this year with a five handle? How are you thinking about contracting strategy in this type of environment? You'd think you'd wanna maybe sign shorter contracts today in anticipation of higher dayrates, maybe 12 to 18 months from now. Maybe the one well contract for the Faye Kozack at $450 a day was evidence of that, though I might be reading too much into that.

Hi, good morning, so very constructive outlook for the floater market, which would suggest the day rates continue to move higher throughout the year I hate to start with a leading question, but do you think it's likely that we'll see a floater fixtures announced later this year with a five handle.

And how are you thinking about contracting strategy in this type of environment, because I would think you'd want to maybe sign shorter contracts today in anticipation of higher day rates, maybe 12 to 18 months from now.

And maybe a one well contract for the Big day Kozak at $4 50, a day was evidence of that.

Be reading too much into that.

Robert Eifler: Yeah. Look, Eddie, thanks. A great leading question. Look, I think there's some things that have to fall in place. In the near term, I think we're actually gonna see a bit of a wide range of fixtures here, even among seventh-generation rigs. You've got some rigs, as I mentioned in the script, that are coming into the marketplace that were previously sidelined, and those can carry, you know, some slightly different economic motives behind them, which is fine and expected. We've said that for a couple of years. I think...

Yeah look Eddie Thanks and a.

Great leading question.

Look I think.

There are some things that have to fall in place.

In the near term I think we're actually going to see.

A bit of a wide range of fixtures here, even among seventh generation rigs.

You've got some rigs as I mentioned in the script that are coming into the marketplace that were previously sidelined and those can carry.

Some slightly different economic motives behind them, which is fine and expected we said that for a couple of years.

And I think and so I think with that at play.

Robert Eifler: I think with that at play, the fact, you know, we're experiencing this right now, where with all the short-term contracting, you do get white space in schedules. I think with those couple of dynamics, you know, people managing time between contracts, et cetera, you are gonna see a range of fixtures in the near term. I think very much what I laid out in the script, and what we see in terms of very tangible demand coupled with some of this project sanctioning coming through, like we're hopeful this year, puts us on a path to 500.

The the fact you know we're we're experiencing this right now where with all the short term contracting you do get white space and schedules and so I think.

With those couple of dynamics if people managing time between contracts etcetera, you are going to see a range of fixtures.

In the near term.

But I think very much what I laid out in the script.

And what we see in terms of.

A very tangible demand coupled with.

Some of this project sanctioning coming through like we're hopeful this year puts us on a path to 500.

Robert Eifler: I don't know that that rate's gonna be, you know, paid in 2023 for anybody, but I think there's very much a path where we could see a fixture this year that's above 500. I am even more confident in that if you include kind of a total contract value analysis of what an operator ultimately is gonna need to pay for a rig this year. As it relates to our strategy, we've been very lucky to have these contracts in Guyana with ExxonMobil, where we have had, you know, long-term visibility for four of our top drillships.

And I don't know that that that rates going to be paid.

Paid in 2023 for anybody.

But I think there's very much a path, where we could see see a fixture.

This year, that's about 500.

And even even more confident in that.

You include kind of a total contract value analysis of what an operator ultimately is going to need to pay for for a four rig this year.

As it relates to <unk>.

Our strategy, we've been very lucky to have these contracts in Guyana with Exxon, where we have had long term visibility for four of our top drillships.

Robert Eifler: Of course, we only have the Meltem cold stacked and then the Scirocco, which is 6G cold stacked. We, you know, we've been fortunate not to be put really to, as I think, as crucial a decision around taking a strategy towards long-term contracts or not at this point. We've got right up there with the largest Tier 1 fleet in the world. We'd be willing to take one or two long-term contracts at current dayrate levels, which, you know, we can produce a significant amount of cash flow here at current dayrate levels, even though we see a rising market.

And also of course, we only have the Melton cold stacked and then and then the Serco, which is 60 cold stacked.

And so we've been fortunate not to be put really too as I think as crucial a decision around taking our strategy towards long term.

Contracts are not at this point, but we've.

We've got a right up there with the largest.

Tier one fleet in the world.

We are in and we'd be willing to take one or two long term contracts that are at current day rate levels, which are you know we can produce a significant amount of cash flow here at current day rate levels, even if even even though we see a rising market, but I would say Andy that aren't our strategy. Thus far has.

Robert Eifler: I would say, Eddie, that our strategy thus far has been to take advantage of rising dayrates, and that's been enabled by the visibility we have in the Guyana-Suriname region.

Then to take advantage of a rising day rates and that's been enabled by the visibility we have.

And in the Guyana Suriname region.

Eddie Kim: Understood. Thank you. Thank you for all that color. Just shifting over to the SPS. As you mentioned, you have a good number of rigs undergoing programs this year and next. Specifically for ten-year SPSs for one of your drill ships, could you just remind us what the typical cost is for that and the approximate split there between OpEx versus CapEx?

Understood. Thank you. Thank you for all that color.

Just shifting over to the SBS as you mentioned you have a good number of rigs undergoing programs this year and next.

Specifically for 10 year STS this for one of your Drillships.

Can you remind us what the typical cost is for that and the approximate split there between between Opex versus capex.

Richard Barker: Sure, Eddie. Look, obviously it's very rig-dependent. But I think a good kind of rule of thumb from a capital perspective is probably think about a range of $20 to 40 million, obviously very rig-dependent. A lot of that is capital, but also there's definitely an element of OpEx there as well. It's just gonna be very specific to the rig. I do think what's important to note, and I referenced this in the script, was just the impact on top line, right? For example, a 30- to 60-day SPS means you aren't earning dayrate for that period of time.

Sure.

Look obviously, it's very dependent but I think a good kind of rule of thumb from a capital perspective.

But really think about a range of $20 million to $40 million, obviously very very rate dependent.

A lot of that is is capital but also.

There's definitely an element of Opex that was well, it's just can be very specific to the rig.

Do think what's important to note references.

References in the script was just the impact on top line right and so for example, a 30 to 60 day Sps means. It means you are earning day rate for that period of time and with rates north of $400000. A day I think that that can have a material impact on the overall financial statements. So I encourage you to think about it both obviously.

Richard Barker: With rates north of $400,000 a day, I think that can have obviously a material impact on the overall financial statement. I'd encourage you to think about it both obviously from a cost perspective, and again, which is very rig-dependent, but also the lost revenue if you will.

From a cost perspective, and again, which is very very rig dependent but also the lost revenue.

Robert Eifler: Yeah, I think let me just add to that, if I could, Eddie. You're gonna see a pretty wide range. We've got an example of a rig in Guyana that came out of service for just 19 days to do its ten-year SPS at a cost I think is just under $20 million total. Now, that was an instance where we were able to work very closely with our customer and plan out that SPS. In other instances, that's just not possible to do. If you're between customers in contracts, you can't be quite as efficient. You're not gonna get the customer preceding the SPS to allow you to do some of the onboard work that would make you more efficient.

If you will and I think let me just add to that if I could Eddie you're going to see a pretty wide range.

We've got an example of a rig in Guyana that came out for just 19 days to do its 10 year Sps that at a cost I think it was just under 20 million total.

Now that was an instance, where we were able to work very closely with our customer and plan out that is fast and in other instances that is just not possible to do if you're between customers and contracts you can't be quite as efficient a youre not going to get the customer preceding the Sps to allow you to do some of the.

The onboard work that would make them more efficient and it's hard to actually sign a contract. When you have you know when you have the Sps in the way and you're trying to manage a shipyard project timing on top of rolling between between customers. So you're just going to say see a range and Thats why Richard says, it's it is very rig dependent.

Robert Eifler: It's hard to actually sign a contract when you have, you know, when you have the SPS in the way and you're trying to manage a shipyard project on timing on top of rolling between customers. You're just gonna see a range, and that's why Richard says it is very rig-dependent.

Eddie Kim: Got it. Understood. All very clear. Thank you very much. I'll turn it back.

Got it got it understood very clear. Thank you very much I'll turn it back.

Robert Eifler: Thanks, Eddie.

Thanks, Andy.

Operator: Our next question comes from Kurt Hallead from Benchmark. Please go ahead. Your line is open.

Our next question comes from Kurt <unk> from Benchmark. Please go ahead. Your line is open.

Kurt Hallead: Hey, good morning.

Hey, good morning.

Robert Eifler: All right. How are you?

Alright, how are you.

Kurt Hallead: Doing well. Thank you. It's a great summary. Really appreciate the color commentary. I guess my follow-up here would be on CapEx and the CapEx guidance that you provided, not just for this year, but obviously over the course of the next few years, right? I'm going to make an assumption here that, you know, at least for 2023, your CapEx guidance does not assume any cost associated with the activation of the Meltem. Maybe let's start there. Is that fair?

Well. Thank you. Thank you it's a great summary.

Appreciate the color commentary so I guess my follow up here would be on on Capex and the Capex guidance that you provided not just for this year, but obviously over the course of next few years right.

I'm going to make an assumption here that you know at least for 2023 year Capex guidance does not assume any.

Costs associated with the activation of the ultimate maybe maybe let's start there is that fair.

Robert Eifler: Correct. Yes. That's right.

Correct, Yes, thats right.

Kurt Hallead: Okay. Of the potential activation cost of that $100 million, right? You mentioned you'd want a significant portion of that upfront. I know there's gonna be some probably horse trading between, you know, what kind of terms you can get, what kind of day rate you can get, what you want, but what's at a bare minimum, you know, what would be acceptable in terms of, upfront payment to activate the Meltem?

Okay and then.

<unk>.

The potential activation cost of that $100 million right, you mentioned you'd want a significant portion of that upfront.

And I know theres going to be some probably horse trading between.

What kind of terms you can get what kind of day rate and get what you want but it wasn't.

At a bare minimum what would be acceptable in terms of upfront payment.

To activate the melt them.

Robert Eifler: Yeah, look, it's a multivariable equation as you alluded to. You know, let's say somewhere in the order of half, something like that. A big piece of that is, and that's not a rule, but you asked the question. You know, a big piece of it also is when would the timing occur? You know, we're on a. As Richard mentioned in his script, we're very much on an upward trajectory on free cash flow here, and not looking to fall off of that track. We'll see what the world brings us this year.

Yeah look it's a multi variable equation is as you alluded to.

And so you know.

Let's say some somewhere in the order and the order of half something like that but a big piece of that is and that's not a rule.

You asked the question.

A big piece of it also is when when would when would the timing occur.

We're we're on as Richard mentioned in his script, we're very much on an upward trajectory on free cash flow here.

And not looking to fall off of that track.

We'll see what the world brings us this year, but as I kind of I think hit pretty hard I think things are set up quite well.

Robert Eifler: As I've kind of, I think, hit pretty hard, I think things are set up quite well in the industry for the next few years. As we move forward in time, I think, you know, that number is more likely to go down than up. Yeah.

And in the industry for the next few years. So as we move forward in time I think you know that that number is.

Is is more likely to go down well it is more likely to go down than up yeah.

Kurt Hallead: Mm-hmm. Okay. Just to kind of you know put a bow on the CapEx. Over the you know 2023 to 2027 period where you said an average of $275 million in CapEx, I would assume that you did include the Meltem into that calculation. Is that fair?

Okay, and then just to kind of.

Put a bow on on the Capex so over the two.

<unk> 23 to 2007 period, where you said an average two one.

<unk> hundred $75 million of Capex.

Then I would assume that new data include the melt them into that calculation is that fair.

Robert Eifler: No, actually, it's not. I think the way to think about it, obviously, there's guidance we've got out there for 2023. You know, we've talked about just given the number of SPS's next year, we expect that number to be higher. I think, you know, thereafter, as you think about the 2026 through 2027 timeframe, you know, you can therefore infer that if you will, capital on an average basis is gonna be, you know, ±$200 million in that timeframe. It doesn't include the Meltem.

No actually it's not so I think that the way to think about it obviously there's guidance we've got out there for 2023.

Talked about just given the number of Sps is next year, we expect that number to be to be higher.

I think thereafter as you think about the 26 through 2007 timeframe you can therefore inside that if you will capital on an average basis is going to be.

Plus or minus $200 million in that timeframe. So it doesn't include the momentum.

Kurt Hallead: Okay. All right. That's great. That's it for me. Really appreciate it. Thanks.

Okay, Alright, thats, great Thats. It from me really appreciate it thanks.

Robert Eifler: You bet. Thanks.

Thanks.

Operator: Our next question comes from Fredrik Stene from Clarksons Securities. Please go ahead. Your line is open.

Our next question comes from Fredrik Stene from Clarksons Securities. Please go ahead. Your line is open.

Fredrik Stene: Hey, guys. Hopefully you can hear me all right. I had some trouble with my line. Can you hear me?

Hey, guys. Hopefully you can hear me all right I had some trouble.

With my line can you hear me.

Robert Eifler: Loud and clear. Yes, Fredrik. Loud and clear. Thanks.

Larry, Yes, Fredric loud and clear things.

Fredrik Stene: Perfect. Okay. I'm sorry if you already said it again, a bit of trouble with the line, but I wanted to touch briefly on the guidance you gave, and then thank you for the color on the reimbursables and amortization. If you subtract those $200 million, I think we come to a midpoint of $2.25 billion approximately, just from regular revenue. If you look at your backlog chart a bit earlier, I think we had $1.66 billion secured for 2023 already. My question relates to this gap here. How should we think about that? Where will those $600 million come from? Do you think, you know, mostly floaters, jackups, et cetera?

Perfect. Okay. So I want to I'm, sorry, if you already said it again.

Coupled with a nine but wanted to touch briefly on the guidance.

Gabe and thank you for the color on the Reimbursable on amortization.

If you subtract those two hundreds.

I think we come to the midpoint of the.

$2.250 billion approximately.

From from regular revenue.

And if you look at your backlog chart earlier I think we had.

One.

Six six.

$65 $66 billion.

Secured for 2023 already.

So my question relates to this gap here and how should we think about.

Where will those $600 million come from.

I think mostly floaters, mostly.

Jack gifts et cetera, I guess you have some some insight.

Fredrik Stene: I guess you have some insight to where you find it likely that you'll be able to secure contracts that will actually contribute to close that gap. Any color you can give will either be super helpful.

Do you find it likely that youll be able to secure a contract that would actually contribute contributes to close to.

Close that gap.

So any color you can give would be super helpful.

Robert Eifler: Sure, yeah. Let me just say a couple words, and then I'm gonna hand it to Blake, who's leading our global efforts there. We've got. I mentioned in my script, we have an excellent opportunity set behind effectively all of the rigs where we have white space. Those are works in process. Some are very well developed, and we hope to have some good news soon, and then others are still closer to the bidding stage. That includes some of the big enduring white space, but also perhaps a couple of filler jobs here where you see some gaps. So we're kinda working all of it right now, but maybe Blake, just some rig by rig or rig class color.

Sure Yeah, Let me let me just say a couple of words, and then I'm going to hand, it to Blake who's up who's leading our global efforts there.

We've got I mentioned in my script, we have an excellent opportunity set behind effectively all of the rigs where we have white space.

Those are works in.

Process, some are very well developed and we hope to have some good news soon and then others are still are closer to the bidding stage that includes some of the big Big and.

Enduring white space spaces, but also perhaps a couple of filler jobs here, where you see see some gaps. So we're kind of work and all of it right now, but maybe like just some rig by rig or rig class color. Yes of course. So the first first comment I'd make you asked about floaters versus Jackups I think it comes from the floater side.

Blake Denton: Yeah, of course. The first comment I'd make, you asked about floaters versus jackups. I think it comes from the floater side more than the jackups, the additional backlog and EBITDA contribution. I think we've talked about the SPS already sufficiently to describe how that affects the white space. Also the short-term nature of some of the contracts that have hit in the UDW that create this, I guess I'll call it inefficiency in the market. We have just the timing of different projects or programs. We have mobilization, and then, of course, you've got regional and contract-specific requirements. Depending on where we pick up the work, and the timing, that'll define the white space. What moves the needle is, of course, converting that white space to operating date.

More than the Jackups, the additional backlog and EBITDA contribution and then I think we've talked about the Sps are already sufficiently to describe how that affects the white space, but also the short term nature of some of the contracts that have hit in the U D. W that create I guess I'll call. It inefficiently inefficiency in the <unk>.

So then we have just the timing of different projects and programs with mobilization and then of course, you've got regional and contract specific requirements. So depending on where we pick up the work.

And the timing that will define the white space, but what moves the needle is of course converting that white space the operating days.

Blake Denton: As Robert mentioned, I mean, when you look at the drillships, the demand backdrop is incredibly encouraging. I would say equally encouraging are our discussions ongoing with customers. We should have some highlights.

As Robert mentioned I mean, when you look at the Drillships. The demand backdrop is incredibly encouraging I would say equally encouraging our discussions ongoing with with customers and so we should have some some highlights some highlights here soon on that and then when you look at the other ones for 2023 or two of our D class semi.

Robert Eifler: Some highlights here soon on that. When you look at the other ones for 2023 are two of our D-class semisubmersibles. When you look at these assets, I mean, they're some of the most capable DP plus moored units available in the world. Traditionally, they compete for both programs that require that niche DP plus moored capability, as well as UDW capacity, where there's gaps or where they're available on the back end. I think we have conversations in both of those spaces that are ongoing now. We see several opportunities that start for these specific rigs late in the year or early into 2024.

Submersibles. So when you look at these assets I mean, there are some of the most capable <unk> plus more units available in the world and traditionally they compete for both programs that require that niche DP plus moored capability as well as you'd EW that capacity, where there's where those gaps are where they are available on the back end and I think we have a convert.

<unk> and both of those spaces that are ongoing now.

And we see several opportunities that start for these specific rigs late in the year or early into 2024.

Fredrik Stene: Super helpful. Thanks, guys. Just a follow-up on the guidance. I think at least compared to my numbers pre-report, and when we adjust for the reimbursables, we're not, you still come in on the revenue side a bit higher than what I had expected. I think my EBITDA number was also a bit higher in the range, so around 800, and you guide $725 to $825. You mentioned that the guidance numbers take inflation into account. I think the inflation thing and then cost increases has been present also in some of your peers that have reported already.

Super helpful. Thanks.

Thanks, Scott and just a follow up on the guidance on how to.

I think as compared to my numbers.

Pre report on when we adjust for the Reimbursable. So were not used it you still come in on the revenue side, a bit harder than what probably unexpected and I think my EBITDA.

<unk> was also.

It would be higher in the range.

So around 800, a new guidance of 725 to eight quantified so you mentioned up.

The guidance the guidance numbers takes in <unk>.

<unk> into account and I think the inflation and cost increases has been present all Quinn.

Of your peers.

Reported already so I was wondering are you able to kind of give us some insight into how that has been factored in.

Fredrik Stene: I was wondering, are you able to kind of give us some insight into how that has been factored in, you know, in terms of percentage basis, and how do you view that going into 2024, as well, your cost base?

In terms of percentage basis, and how do you view that going into it.

2024.

Well your cost base.

Richard Barker: Sure. Yeah. Look, I think we've been pretty consistent around inflation here for a few quarters. You know, on my script, I talked about how we expect high single digit type inflationary pressures this year. That's absolutely embedded in our guidance, you know, which is consistent with what we said back in October. You know, we expect that in 2023. As you look forward to 2024, obviously as we expect global rig demand to continue to increase, we don't see that inflationary pressure stopping. Sorry.

Sure Yeah. So look I think we've been pretty pretty consistent around inflation here for a few quarters. So.

And on my script I talked about how we expect high single digit type in.

<unk> pressures this year.

So that's absolutely embedded in our guidance.

Consistent with with what we said back in October .

So we expect that in 2023 as you look forward to 2024, obviously as we expect global rig demand too to continue to increase we don't see that inflationary pressure.

Yes.

Stop stop stopping site and so therefore, I think you should expect in <unk>.

Richard Barker: Therefore, you know, I think you should expect, you know, in a rising rig demand market, essentially the inflationary pressures that we're seeing in that high single digit type area to continue both in obviously 2023, but also through 2024 as well.

Rising rig demand market essentially the inflationary pressures that we're seeing in that high single digit type area to continue both into and obviously in 'twenty, but also through 2024 as well.

Fredrik Stene: Thanks so much. I guess it's fair to assume that you'll try to push all these cost increases and, if not more than that, onto your clients.

Thanks Richard.

Yes, it's fair to assume that Youll try to push all these cost increases.

More than that on to your clients.

Robert Eifler: Yeah. Current market reflects typically the current cost basis as well, so. You know, just speaking generally about the industry, of course, I don't know about outside of Noble, but the market where most of the contracts were signed were producing revenue today. There's probably a few that have some cost recovery. We have a couple that have cost recovery, but it's not been the norm here over the past couple of years of contracts signed. You know, perhaps that's something that comes back into market as we move through this year.

Yeah, correct, Yeah current current market as current market and yeah reflects typically.

It reflects our current cost basis.

Basis as well so.

I don't I don't just speaking generally about the industry out of course, I don't know about outside of noble but.

Yeah.

The market, where most of the contracts were signed.

Producing revenue today.

Yeah, there's probably a few that have some cost recovery, we have a couple that have cost recovery.

But it's not been the norm here over the past couple of years of contract signed so.

Is that something that comes back and into a market as we move through this year.

Robert Eifler: you know, with the churn of contracts, particularly on the UDW side, you know, the pricing resets can reflect increased costs, so.

But you know with the with the churn of Av.

Of contracts, particularly on the EDW side.

The pricing resets can can reflect increased costs.

Fredrik Stene: All right. Thank you so much. That's all from me.

Alright, thank you so much.

So for me.

Robert Eifler: Thank you.

Thank you.

Operator: Our next question comes from Samantha Hoh from Evercore ISI. Please go ahead. Your line is open.

Our next question comes from Samantha Hoh from Evercore ISI. Please go ahead. Your line is open.

Samantha Hoh: Hey, guys. Congrats on the really great quarter. Thanks for providing that commentary that your floater backlog is averaging north of $400,000 per day. You know, I was kinda curious, given this backdrop, how you're viewing options, like potentially granting options with new contracts. You know, are the days of price options gone for the industry? Or, you know, how do you think about that in terms of, like, just new long-term contracts signed in terms of weighing price versus, you know, open-ended option pricing?

Hey, guys and congrats on a really great quarter.

Thanks for providing that commentary is that your backlog is averaging north of 400000 per day.

Yeah. It was kind of curious given this backdrop, how you're viewing.

Options like perpetually granting options with new contracts.

Yeah, I think as our price options gone for the industry or how do you think about that in terms of like Chris New long term contract signed in terms of price.

Price versus.

Ill open under option pricing.

Robert Eifler: Yeah, good question. Separated into two answers between floaters and jackups, unfortunately right now. I think we've been probably more aggressive than the average on not giving priced options here over the past couple of years. While it hasn't been a hard no, and we do have a couple of exceptions out there, generally speaking, we started pushing back very aggressively on priced options a year and a half ago, I think. Obviously, as the market tightens, you could expect us to continue or even stop giving options. The jackup side is a little bit different. It's a soft market and more tentative economics, I think, for our customers.

Yes, good question.

Okay.

Operator into two answers between floaters and Jackups. Unfortunately, right now I think we've been probably more aggressive than than the average.

Not giving priced options here over the past couple of years.

And while it hasn't been a hard no and we do have a couple of exceptions out there generally speaking, we we started pushing back very aggressively on priced options.

Year, and a half ago I think.

And obviously as the market tightens, you could expect us to to continue or even.

Stop stop giving options, but.

The Jackup side is a little bit different it's a soft market.

And.

More more tentative economics, I think for our customers.

Robert Eifler: Options do serve a purpose in ensuring that certain wells can actually get sanctioned and drilled. I think on the jackup side, that's still a part of the market we see.

Options do serve a purpose and ensuring that certain wells can actually get sanctioned and drilled.

And so I think on the Jackup side that that's still a part of our part of the market we see.

Samantha Hoh: Okay. Maybe if you can help us think about geographically, you know, where you want to have more scale. You know, you're so concentrated in Guyana and the US Gulf of Mexico. Is there a goal in terms of getting to a certain size, in like the Australia market or in the West Africa region?

Okay, and then maybe if you can help us think about geographically.

You know where you want to have more scale.

You know you're still concentrated in Guyana, and the Gulf of Mexico, but yeah.

Is there a goal in terms of getting to a certain size.

And like the Australia market or in the West Africa region.

Robert Eifler: You know, I wouldn't say that we have a defined strategy right now to move. In other words, you know, we're gonna be governed by economics in how or if we move rigs around. If the tightness that we're predicting plays out, I think the market very quickly gets to a point where the price for time between contracts starts to be put to operators, whether that's through mobilization or day rate recovery on a move. That's something that we're thinking through.

We don't have a I wouldn't say that we have a defined strategy right now to move.

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