Business Summary
Valaris is the world’s largest offshore drilling contractor, with a diversified fleet of seventh-generation drillships, jackups, and semisubmersibles. The company has prioritized capital discipline and fleet quality, reactivating rigs only when economics justify. Reactivation costs for drillships average $120–125 million, typically funded or reimbursed through customer mobilization fees and contract value. Operational efficiency is strong, with 97% revenue efficiency reported across the fleet. Valaris benefits from its 50/50 ARO Drilling JV with Saudi Aramco, which operates 15 rigs today and will expand to 19 rigs as newbuilds are delivered under 16-year contracts with six-year EBITDA paybacks. Shareholder returns remain a clear focus: the company repurchased $171 million of shares in 2023 toward a $200 million target and has a $600 million open-ended authorization for 2024–2025. Asset sales, including a $64 million divestiture of an older rig and a $100 million+ sale of V-247, further strengthen liquidity. With day rates moving from the low-200s to mid-400s (and selectively over $600k/day), Valaris is positioned to capture rising cash flows as market tightening continues.
Catalysts & Milestones
2022 - $64 million rig sale highlighted strengthening jackup market
2023 - Four floater reactivations delivered on time and budget with 97% revenue efficiency
2023 - Share repurchases reached $171 million (3.5% of shares) toward $200 million target
2024 - $600 million share repurchase authorization launched, covering 2024–2025
2025 - Valaris 247 sale expected to generate more than $100 million in proceeds
2025 - Majority of 2025 floater opportunities expected to favor 7th generation drillships
2026 - Strong demand expected for DS-11, DS-13, and DS-14 deployments in tightening market
2027 - One ARO Drilling leased rig rolls off contract
2030 - Six ARO Drilling rigs contracted through end of decade
Investment Highlights
Average reactivation cost of $120–125m, consistently executed on budget
97% revenue efficiency across fleet underlines operational strength
$600m share repurchase authorization supports shareholder value creation
ARO JV expanding to 19 rigs with 16-year contracts and six-year EBITDA payback
Day rates climbed from $200k lows to mid-400k+, with select fixtures above $600k
Future Growth Drivers
Long-term Saudi ARO newbuild program delivering fleet expansion and stable cash flows
Deployment of DS-11, DS-13, and DS-14 into rising day rate environment
Exploration and development demand growth in Africa, Mediterranean, and Brazil
Increasing customer preference for 7th generation rigs with dual BOPs and MPD systems
Opportunistic M&A or partnerships to strengthen fleet and capture synergies
Risk Factors
Reactivation projects cost $120–125m, with inflation risk on labor and supply chains
Jackup suspensions in Saudi could reduce EBITDA by ~$10m (1% of backlog)
Shareholder return execution may vary despite $600m authorization
Dependence on FPSO deliveries may delay deepwater programs by 1–2 years
High concentration in ARO JV ties cash flow to Saudi market dynamics
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Capital Allocation
02/11/2021 What rate levels justify reactivations, and how do you approach bidding and mobilization fees?
The market has improved significantly since the start of the year, and each job must justify reactivation. Our stacked rigs have been in preservation for less than two years, compared with about three and a half to four years for the average fleet, making reactivations easier. We stand by our reactivation costs, which must be reimbursed or largely covered by customers through mobilization payments, contract value, or a mix of both. Current spot day rates are well ahead of earlier levels, and our hurdle rates for future reactivations will move accordingly.
At the start of the year, only 4 of our 11 drillships were active. We have since added capacity, improving floater fleet backlog from around eight months to about 20 months. We still have three high-quality floaters that we can bring back when economics make sense, and we will remain disciplined in selecting opportunities.
02/11/2021 Are idle rigs ready for Saudi work, or do they require upgrades?
Saudi Aramco requires very specific configurations, API-monogrammed equipment, and strict well-control standards. They frequently upgrade their requirements. Therefore, rigs entering Saudi Arabia, including ours, generally need significant CapEx upgrades. This creates a barrier to entry but also supports stable work once rigs are operating in the Kingdom.
03/05/2022 Are there penalties for retiring $550 million debt early?
Yes, the indenture includes typical reinvestment rights. We still have 11 stacked rigs that may be reactivated, requiring investment. The note has a non-call period ending in April next year, after which there is a step-up. We can buy back notes in the open market, but until then we prefer to maintain liquidity given the potential returns from redeploying rigs. We will decide based on market conditions.
01/11/2022 What are short-term investments, and was the $64 million rig sale at arm’s length?
This is Chris. Short-term investments were simply a time deposit over 90 days to earn extra yield on cash, nothing more.
Yes, the $64 million rig sale was an arm’s-length transaction. Our fleet focuses on high-spec rigs, mostly in the top quartile. The asset sold was 40 years old and required significant capital. For us, reinvesting elsewhere is more attractive, but for another operator in a different market it can make sense. The sale highlights how the jackup market has strengthened significantly over the last six to nine months.
21/02/2023 Will stacked jackups return to work, or is focus only on floaters?
There has been an improvement in the benign jackup market, driven by rigs moving to Saudi Arabia. Opportunities exist for jackups, but our decisions hinge on capital allocation and investment returns. Floater day rates have doubled from the 200s to 400s, while jackups improved from the 70s to above 100, with some contracts above 125.
On a capital allocation basis, drillship reactivations offer superior economics compared to jackups today. That does not mean jackup opportunities are off the table. If we see an attractive case, we will act, but our priority remains allocating capital where returns are strongest.
21/02/2023 Is the CARES Act refund a catalyst for opportunistic returns?
Chris Weber: From a CARES Act refund perspective, we received $55 million in Q4, $45 million in January, and $19 million remains. These were expected and built into our planning models, so we do not view them as catalysts or unexpected windfalls.
Anton Dibowitz: As I mentioned earlier, our focus is disciplined capital allocation to create long-term shareholder value. Including the CARES Act refund, we prioritize reactivations of drillships with attractive economics. We also want cash available for potential M&A, but excess cash should ultimately be returned to shareholders. This could happen through opportunistic buybacks during price dislocations or through rig sales. The CARES Act proceeds are part of our base numbers, not a separate catalyst.
21/02/2023 Do you envision an IPO or divestment for ARO, and what happens to leased rigs?
Absolutely, Fredrik. The value of ARO to Valaris is underappreciated since we do not consolidate it. It is a 50-50 venture with the largest jackup user in the world, in a market where some say the last well will be drilled. Today there are 15 rigs operating, with two contracts for rigs transitioning and two newbuilds this year, taking the fleet to 19 rigs.
The natural timing to evaluate strategic options would be after the first two newbuilds are delivered, contracted, and performing under the model, an eight-year contract with six-year EBITDA payback, while committing to additional newbuilds. That milestone would be a logical point for value realization discussions, but I will not comment further.
02/05/2023 How do you market stacked drillships compared to DS-13 and DS-14?
Anton Dibowitz: Ideally, we would secure longer-term contracts for the DS-13 and DS-14. Our priority is to keep active rigs continuously utilized, then consider high-spec preservation stacked assets, and then the options. We also differentiate between purchase price, reactivation costs, and putting rigs to work.
Anton Dibowitz: Stranded assets have traded in the low to mid-200s, and both the DS-13 and DS-14 have two BOPs, which many stranded assets lack, representing an additional $50 million in value. On a pure steel price basis, the DS-13 is less than half of where assets are trading, making it very attractive and a likely option to exercise. The DS-14 is closer to current trading values, so we will continue to evaluate it against other capital uses.
02/08/2023 Are you considering M&A, or focusing on organic growth with DS-11, DS-13, and DS-14?
We have been clear this industry needs consolidation. We continuously evaluate M&A opportunities. Our high-specification fleet provides a competitive advantage we do not want to dilute. If an M&A opportunity creates real synergies, we would consider it.
At the same time, we have plenty of organic growth ahead. Three reactivations will earn day rates before mid-next year, and we must roll three legacy contracts to market rates within 12 months. Taking DS-13 and DS-14 to market also creates growth. We are comfortable with organic expansion, but we will pursue M&A if opportunities make sense.
05/09/2023 Will you return free cash flow to shareholders or pursue fleet growth?
We intend to return cash to shareholders unless a clearly more attractive use arises. Near term, reactivating rigs like DS-7 generates strong returns. Beyond that, we will not build new rigs. Some investment may go to technology or fleet upkeep, but the priority is shareholder returns. M&A is possible if it maintains fleet quality and adds value through overlap or synergies, but most deals would likely be equity-funded. We want to keep a conservative balance sheet while ensuring clarity on cash returns to shareholders.
07/11/2023 What is your share repurchase outlook for 2024 following the $200 million 2023 target?
We are demonstrating strong commitment to returning capital to shareholders. Year-to-date we have repurchased $171 million of shares, about 3.5% of our outstanding stock, and we are on track to meet the $200 million 2023 target. We will provide more detail on 2024 return plans in the fourth-quarter call.
Our philosophy is simple: when the business generates meaningful and sustained free cash flow, we will return it all to shareholders unless there is a clearly superior value-creative use. That includes dividends, ongoing repurchases, and potentially special dividends after significant liquidity events. The board and management are laser-focused on ensuring excess cash is returned to shareholders.
22/02/2024 How will you pace the $600 million share repurchase authorization?
We remain committed to returning capital to shareholders. Last year we returned $200 million of capital on a $300 million authorization, and our Board has now doubled that to $600 million. This is an open-ended authorization that gives us the ability to opportunistically repurchase shares in 2024 and into 2025.
We believe our stock trades at a discount to intrinsic value. We increased the authorization for a purpose, we intend to use it, and we will be opportunistic about it.
22/02/2024 Is there a limit to pursuing value before distributing all free cash flow?
We expect significant earnings and cash flow growth as we move deeper into an upcycle, and our intention is to return it all to shareholders. It is never wise to make absolute statements, which is why we leave the caveat that if there is clearly a better value-accretive use, we may pursue it. Examples could be additional managed pressure drilling systems or an attractive asset purchase.
That said, our policy is clear. When we generate significant cash, we intend to return it all to shareholders unless a superior value-accretive opportunity emerges.
22/02/2024 Will you scrap or sell stacked jackups and semis, or keep them for optionality?
We prioritize getting ships back to work because that is the capital allocation decision that delivers returns. As mentioned earlier, reactivation costs compared to leading-edge day rates support attractive returns on drillships with long-term contracts. For international jackups, the smaller numbers and shorter durations make reactivations less attractive.
That said, jackup durations are increasing, which could create opportunities for some of those assets. For now, with positive market momentum, our stacked assets, including the three, the six and our jackups, remain valuable options to hold.
22/02/2024 Did you consider a JV like Total’s with Vantage, and how do you view such opportunities?
It is a positive sign that operators are contracting rigs beyond approved programs, which shows confidence in a tightening market and rising day rates. Having scale allows us to take a portfolio approach, and with 10 ships working or preparing to work, we would absolutely look at opportunities to secure long-term backlog while remaining opportunistic with other assets.
Each opportunity is assessed on its own merits. If a JV or similar arrangement is commercially attractive, value accretive to shareholders, and fits our portfolio, we would consider it. It all depends on the economics of the opportunity.
22/02/2024 Can you still demand upfront payments for rig activations and contract prep?
Yes. As the market tightens, opportunities for upfront payments are as strong as ever. We led the charge in seeking them, as they are not subject to operational downtime risk, improve cash flow, and strengthen project economics.
Our cost of capital differs from our customers. Some operators even prefer to pay upfront and secure a lower day rate. We evaluate each case, but overall, opportunities for significant upfront payments remain very strong.
22/02/2024 How do you balance share repurchases with potential dividends long term?
Once we generate sustained and meaningful free cash flow, we believe both dividends and share repurchases should be part of our capital return policy. A dividend would be set at a sustainable level through the cycle, while buybacks allow us to capitalize on undervaluation.
Both tools make sense, and we do not think we are far from reaching the stage where they can work together.
02/05/2024 Are there plans to reactivate other stacked assets like DPS-3, DPS-6, or jackups?
Customer preference is firmly for high-specification assets. Our capital allocation has been directed toward drillships, particularly the DS-11, DS-13, and DS-14. While only about ten high-spec reactivation candidates remain globally, tightening supply could create future opportunities for semis, but our current focus remains on drillships.
02/05/2024 What is the likelihood of DS-11, 13, or 14 securing contracts this year, and could a JV be used?
We will consider traditional and nontraditional ventures if they are accretive and make economic sense for shareholders. With critical mass already working and three attractive assets in a rising demand market, we are focused on securing the right contracts with the right customers. We are in active discussions for all three rigs, and if terms deliver meaningful returns on reactivation costs, we will execute. Otherwise, we are willing to wait, as these are the best assets available on the sidelines. Our criteria remain unchanged, initial contracts must provide a strong return on reactivation investment.
01/08/2024 How are you thinking about capital allocation and potential returns to shareholders given idle rigs and deferred reactivations?
We have been clear about our capital return philosophy and already returned capital last year. In the first half of this year, we spent significant cash bringing the DS-7 to work, and we expect to generate more as legacy contracts roll onto new ones. 2025 will be an inflection point for the company. We still see strong opportunities for the DS-13 and DS-14 as we move into late 2025 and 2026, with high-specification rigs in demand.
Our commitment remains to return all generated cash to shareholders. We have authorization capacity in place, though execution will not necessarily be linear. We will act opportunistically while honoring our philosophy of returning capital.
01/08/2024 What is your target free cash flow conversion on expected EBITDA?
We do not have a specific conversion target, but we remain committed to returning capital to shareholders. We have significant authorization capacity and intend to use it opportunistically rather than linearly. We expect free cash flow to improve in the second half of this year. Looking to 2025 and beyond, we anticipate generating meaningful and sustained free cash flow, which we intend to return to shareholders unless a better, more value-accretive use arises.
01/08/2024 Do you expect another round of offshore drilling M&A before year-end?
Timing of M&A is difficult to predict, but we believe there is room for additional consolidation. Some recent deals occurred because companies lacked high-spec rigs and needed to acquire capacity. Valaris is in a strong position, with 12 of 13 ships being seventh generation and additional organic capacity available. We are pro-M&A and will evaluate opportunities. If they are value-accretive and beneficial for shareholders, we will absolutely pursue them.
03/09/2024 Does Valaris plan to pursue another large M&A transaction?
We already have the largest fleet and highest-spec assets on the water, plus organic growth capacity with DS-11, 13, and 14. Consolidation has shaped who we are, and we remain open to strategic combinations if they create value, improve fleet profile, and do not compromise the balance sheet. That said, we do not need acquisitions to maintain a growth story. If a deal is accretive for shareholders, we will consider it, but we are not compelled to pursue M&A to remain a leading player.
03/09/2024 How should we think about your share buyback program?
We intend to be opportunistic rather than steady state at this stage. We recently completed two reactivations and are now focused on generating cash flow through 2024 and into 2025, while managing the balance sheet carefully. Currently, share repurchases are funded directly from the balance sheet. Given confidence in the market, we will act aggressively when dislocations create opportunities. As we transition into steady, sustained earnings and cash flow, the program could evolve into a more regular buyback cadence, but until then, it will remain opportunistic.
31/10/2024 What is Valaris’ view on M&A opportunities and consolidation?
We still believe there is room for additional consolidation in offshore drilling. Much of the M&A so far has involved contractors high-grading fleets or chasing high-spec capacity to gain scale. We already have the largest fleet on water, with 12 of 13 ships being seventh generation, which are preferred by customers.
We feel very good about our fleet position and are not compelled to pursue M&A for scale or high-grading. That said, if an opportunity is accretive and value-creative for shareholders, we will absolutely engage.
20/02/2025 Will ARO Drilling need capital from Valaris to fund Kingdom Three newbuild?
No, neither we nor Aramco expect to inject capital. These newbuilds are backed by 16-year contracts, with an expected six-year EBITDA payback on the initial eight years. They will be funded by ARO cash flow and readily available financing.
For example, Kingdom One and Two had down payments funded by ARO cash and delivery payments financed externally. This is a highly financeable model, and no capital contribution from Valaris or Aramco is anticipated.
01/05/2025 How many 2025 floater opportunities may require rig upgrades?
It is difficult to provide specifics on individual opportunities. What we are seeing, which aligns well with our fleet, is demand from customers who want maximum flexibility to design wells and adapt as they go. Many opportunities now have managed pressure drilling (MPD) as the base, so contractors like us with MPD and dual blowout preventers already on rigs are advantaged. As those systems evolve, we continue to advance our technology.
Often, before starting a new contract, customers request upgrades. This benefits us because they typically cover the capital expenditure, and we end up with a stronger rig. Significant CapEx upgrades are not the norm. Our high-spec 7th gen fleet can handle many programs without major modifications, but it depends on the market and customer. Commercially, we aim to ensure reimbursement for any required upgrades.
31/07/2025 Are there any unusual CapEx requirements for preparing rigs for new contracts?
No, nothing out of the ordinary. Most contracts have some form of capital expenditure requirement, as customers typically request adjustments. However, among the contracts we have signed, none of the CapEx requirements stand out as exceptional.
31/07/2025 What are your plans for share buybacks given strong liquidity and free cash flow?
We remain committed to returning capital to shareholders. The path may not be perfectly linear, but our operational and financial performance this year has been strong, and commercial progress continues. Importantly, the V-247 rig sale expected to close later this year will generate more than $100 million in proceeds, enhancing our flexibility.
Our philosophy on capital returns has not changed. While the timing may vary, the strength of the business gives us confidence in our ability to return capital going forward.
02/09/2025 How do you view Valaris’s positioning and strategy for corporate M&A?
Valaris supports industry consolidation, which strengthens counterparties for customers, enables technology deployment at scale, and benefits investors. We already have the scale needed to capture synergies, share overhead, and deploy technology, so we are not compelled to pursue M&A purely for growth capacity. Our fleet is strong, with 12 of 13 ships being seventh-generation and growth opportunities already built in through the DS-11, DS-13, and DS-14.
That said, we will pursue M&A if it creates value for shareholders without degrading fleet quality. The key test is whether potential deals enhance synergies, maintain high fleet standards, and are accretive. We do not need M&A for growth, but we remain open to opportunities that make strategic and financial sense.
02/09/2025 Should investors expect shareholder returns this year or more in 2026?
Our capital return philosophy is clear: once the business sustains cash generation, we aim to return it all to shareholders unless a more value-creative use exists. Early this year, we prioritized reducing uncertainty and booking contracts before committing capital returns. Operational performance and contracting progress were key milestones for us.
In the first half of the year, we generated significant EBITDA and cash flow. The sale of the Valaris 247 for more than $100 million further increases flexibility. While returns may not be linear, these positive markers give us greater ability to return capital to shareholders, either later this year or in 2026.
Competitive Advantage
05/09/2023 What makes Valaris’ reactivation economics unique compared to peers?
Different drillers took different strategies at the bottom of the cycle. Valaris chose to stack rigs rather than burn cash, which proved right for creditors. We stacked rigs thoughtfully, removing fluids from equipment, keeping people on board from day one, and maintaining a clear idea of reactivation needs. That allowed us to hit budgets and schedules consistently, unlike industry peers that often went 1x or 2x over budget. We have reactivated six rigs while our largest peers combined reactivated eight. The DS-7 contract is an example where our demonstrated track record gave customers confidence. Not all rigs were stacked equally, but we are confident we can reactivate our rigs around the $100 million range, with DS-11, DS-13, and DS-14 expected at similar cost and timeline.
02/05/2024 Will high-spec rigs command premium rates versus lower-spec rigs as supply tightens?
Our philosophy is to maximize economics on our highest-specification rigs. Twelve of our thirteen ships are seventh generation, including DS-11, DS-13, and DS-14, which are sidelined but ready for deployment. We see strong customer demand into 2025 and 2026, and expect to work these rigs at strong rates as opportunities materialize.
01/08/2024 What enabled the DS-17 to secure an attractive standby rate for several quarters?
The DS-17 is a high-specification rig, and Equinor is a valued partner. Our crews did excellent work on the Bakala development, and Equinor invested significant capital in innovative technology on the rig, including thematic robotic arms and automation. This gave them confidence in the rig’s ability to deliver.
This arrangement reflects both the quality of our customer relationships and the market outlook. Operators recognize tightening supply in 2025 and 2026 and are willing to invest to secure the right assets ahead of time. It is a strong signal of where the market is headed.
01/08/2024 Are other operators investing in reactivated rigs like Equinor did with the DS-17?
Equinor is particularly forward-leaning on technology, with much of the innovation coming out of Norway. They invested heavily in automation such as AtharTXs. Timing also played a role, as their program lines up with a strong pipeline of opportunities. Matt noted in his prepared remarks that there are 30 opportunities, with 20 potentially awarded in the next 12 months.
As high-spec assets like the DS-17 are contracted, there will be increasing demand for other assets such as the DS-11, DS-13, and DS-14. Reactivations take about a year, and we continue customer discussions on those rigs. We are not in a rush and will wait for the right opportunities, which we expect to become more attractive as we approach late 2025 and into 2026.
01/05/2025 What percentage of 2025 floater opportunities require 7th gen drillships, and how do operators value 7th vs 6th gen pricing?
Absolutely. Part of it depends on where 7th gens are preferred or required, but we clearly see higher utilization compared to 6th gens. They provide efficiency, especially in long-term development programs with multiple wells. The benefit comes from their ability to deliver complex drilling solutions, such as managed pressure drilling, which gives them an advantage.
Not all 6th gens are the same, but hook load is a key differentiator, allowing customers to design wells with fewer or longer casing strings, which lowers costs. Features like dual blowout preventers are far more common on 7th gens. Ultimately, unless the market is completely under supplied, customers will choose the highest-spec asset for more efficiency and optionality. The overwhelming majority of 2025 floater opportunities are drillship related, and within those, customers tend to prefer 7th gen assets.
31/07/2025 What opportunities exist for DS-10, DS-15 and DS-18 in early 2026 short-term contracts?
The average duration varies depending on whether it is one or two wells, and locations are scattered across the Golden Triangle. We have rigs with available time that can be positioned in these areas, and the specifications of our fleet, such as managed pressure drilling (MPD), allow us to provide services that customers may struggle to source elsewhere. This gives us a competitive advantage, but it remains a competitive environment.
Our strategy is clear. We prioritize contracting our rigs into long-term programs and then use short-term work as gap fillers to reduce idle costs. The fact that we are now seeing more short-term opportunities emerging, even if from a low base, is a positive sign for market strength. Whether we pursue them depends on fit and economics, but their emergence is encouraging.
Operations
02/11/2021 Are there active discussions for unreactivated floaters and jackups?
We bid rigs beyond those already active when attractive opportunities arise, but the economics must be justified. Additional work is available in the Gulf of Mexico, Brazil, and West Africa, where tenders are increasing. We see rising opportunities and will pursue them selectively.
02/11/2021 How should we think about the ARO leased fleet evolution with newbuilds arriving?
Saudi Aramco is expanding its drilling program and even bringing in rigs from abroad. ARO has seven owned rigs and seven leased rigs, and we are in discussions to extend several leases. It is fair to expect these rigs to remain under ARO, with additional capacity possible given Saudi Aramco’s growth plans.
Two legacy jackups at ARO, if not extended, are likely retirement candidates. Beyond those, we continue to tender both stacked and working assets for opportunities in the Kingdom, and outcomes will depend on contract developments.
22/02/2022 How should we think about average floater OpEx over the next 12–24 months as rigs reactivate and crew demand rises?
During the downturn, industry OpEx reached very low levels. We are now seeing inflationary pressures as activity picks up, especially on the floater side and in certain regions. Our guidance already incorporates these effects, and while we do not expect to return to the peak OpEx levels of 2012–2013, costs will be higher than the absolute lows of the downturn.
Inflation is linked to activity and varies by region. Shorter-term contracts allow us to re-price in a constructive floater market, and day rate increases more than offset inflationary pressures. For long-term contracts, we seek protective clauses. Inflation remains a challenge, but our best estimates are reflected in current guidance.
02/08/2022 Have customer discussions started on long-term contracts tied to 2024 reactivations?
Yes, we are discussing term contracts that include reactivations. Last year’s four reactivations were planned for nine months and delivered on time and on budget, despite the industry’s poor track record. This shows our operational strength.
Currently, we plan on 12-month lead times due to supply chain challenges, such as for DS-17. Some short-term rigs roll off in 2023, but many tenders extend through late 2023 into 2024, including Petrobras. Customers understand the lead times needed to bring capacity back, and they are planning accordingly.
02/08/2022 How do you prioritize stacked assets and the two newbuilds in Brazil?
Our first priority is to maintain high utilization on the active fleet to avoid gaps. After that, we consider stacked rigs like TSV, DS-8, and DS-11, which we have proven we can bring back. DS-13 and DS-14, the newbuilds, come later. We have until the end of 2023 to decide, and timing is similar to reactivating a cold-stacked rig.
Some customers want newbuilds with specific requirements, but we remain disciplined. We will only bring rigs out when opportunities are attractive and generate strong cash flow. DS-13, with a remaining purchase price just over $119 million, is “in the money,” and DS-14 could be viewed similarly. Still, newbuilds are later in the sequence after active and stacked rigs.
01/11/2022 Is relocating a jackup to the UK about potential work or just lowering stack costs?
Yes, we have been clear about Norway. Historically the market supported up to 15 rigs, but today it is down almost a third. We have already relocated one of the end-class rigs to a UK contract and do not see near-term demand in Norway. Norway’s contracting process has long lead times, often 9 to 12 months, and current visibility shows limited demand.
These rigs are mobile and can work in the UK or the wider North Sea as easily as in Norway. If demand does not materialize in Norway, we will pursue other opportunities. The rigs remain capable of Norwegian operations and will return when the market strengthens.
01/11/2022 Can end-class jackups work outside the North Sea, and what are idle costs?
Yes. The end-class can work outside the North Sea, although it is designed for harsh environments. Ideally, we would keep it closer to the North Sea, but if the right contract appears elsewhere, we would deploy it.
Stacking costs are relatively small, in the range of $3,000 to $5,000 per day, and are not materially different from other jackups.
01/11/2022 How are you sourcing and training new employees, and is it expense or capitalized?
As activity has increased, competition for people has risen. Our Gulf of Mexico training facility focuses on entry-level recruits, many of whom have never worked offshore. We lost a lot of talent in the downturn, so this program helps bring in new people, immerse them in the offshore environment, and ensure they are comfortable before going offshore. They live on a rig for a few weeks, train with real equipment, and learn our culture and safety systems.
This is part of normal business training and recorded as expense. It provides a pipeline of new hires for active rigs, ensures safety and cultural alignment, and helps identify early if someone is not a fit. We view it as a cost-effective way to manage turnover and future crew needs.
21/02/2023 What hinders rig reactivations, and can newbuilds be delivered quickly?
Good question, Greg. One of our strengths is effectively reactivating rigs. We reactivated four last year, on time and on budget, while delivering 97% revenue efficiency across the fleet. For us, it is not only about reactivating but also ensuring rigs perform at the same level as the active fleet when they return. We have extended the timeline for reactivations, such as the 17 project now taking a year instead of nine months.
This organization has strong control of operational delivery. The real focus is on discipline and timing, finding the right opportunities in a constructive market and bringing rigs back at a measured pace. We are in advanced discussions on at least one more drillship, and I am optimistic about 2023 offering more opportunities. It is not a constraint issue, but about being disciplined and choosing the right moments.
21/02/2023 Can you reactivate a cold stacked drillship within 12 months, and what is the cost?
This organization has a strong track record: four reactivations last year and the DS-17 project, on time and on budget. I am confident our team can execute within the timeframe expected by the customer. We are in advanced discussions and constructive about finalizing the contract soon.
For costs, we guided $65–75 million for DS-17. For additional reactivations, you should expect toward the top end of that range. Once finalized, we will update the market with the contract details and related adjustments.
21/02/2023 What day rates justify reactivating Korean newbuild drillships, and when might this occur?
There are ongoing discussions, and demand growth is making these rigs more realistic. I expect they will ultimately come to market with established, prudent drillers. The clearing price for these rigs is above $200 million today, plus $80–100 million in reactivation and mobilization costs.
To justify those economics, contracts must have robust terms and day rates, at or above current market levels in the mid-400s. Our priority is maximizing utilization of the active fleet, then reactivating cold stacked rigs, and only afterward considering newbuild options. Most of the industry views it the same way.
21/02/2023 Are customers contributing more capital upfront to rig reactivations?
Not all customers are the same. Some are more willing to pay capital upfront, while others, like national oil companies, operate under prescribed contract structures with limited upfront flexibility. The trade-off is recouping costs through higher day rates over the term of the contract.
With current day rates above $400,000 and three-year tenures, the economics are attractive regardless of the structure, provided we generate cash during the initial contract. Our discipline means avoiding contracts that fail to deliver returns over the first term. Liquidity planning is about aligning these contracts with our cash and balance sheet needs.
02/08/2023 Could DS-13 or DS-14 secure contracts and begin reactivation this year, or will reactivations be in 2024?
Hi Eddie, thanks. You have it right. We see compelling value in DS-13 and DS-14, which are very similar to DS-11, our only stacked drillship currently marketed. These rigs are almost sister ships with similar specifications. Which rig goes to work first depends on customer needs. Given the investments in DS-13 and DS-14, we would like to put one of them to work earlier, but it depends on the opportunities and customer discussions.
We have already had customers visit the rigs, and they are in excellent condition. I inspected them myself recently. We will see how opportunities develop.
02/08/2023 With DS-11, DS-13, and DS-14 still stacked, can you now be more selective on reactivation terms?
From the start, we have insisted on covering reactivation costs before bringing rigs back. As day rates have risen and more rigs are active, we have raised our hurdle rates, seeking higher returns on each successive contract. This has made us more selective and patient in pursuing opportunities, which is reflected in our actions to date.
Now, with only DS-11 left from our stacked fleet, we are prepared to wait for the right opportunities. We see attractive long-term prospects and strong customer interest. Our discipline requires generating meaningful returns over the initial firm contract before reactivation, so we will only bring rigs back when those criteria are met. As the market strengthens, our expectations rise, ensuring we maintain discipline and maximize returns.
07/11/2023 What caused the unplanned Q3 downtime for several floaters and what lessons were learned?
Downtime in the quarter was below expectations. Three events occurred on three floaters, largely subsea-related. In this business, if a blowout preventer fails, bringing it to surface, repairing it, and redeploying takes about two weeks, which explains the impact.
Although this quarter fell short, our year-to-date revenue efficiency is 97% across the fleet. We remain focused on safe and efficient operations and will ensure corrective actions are taken so we continue to deliver at the high levels customers expect.
07/11/2023 With jackup rates rising above $150,000, are you considering reactivating cold-stacked rigs?
We are starting to see encouraging signs, particularly in Asia, where opportunities are longer in duration and lead times are extending. This supports potential reactivations. We are bidding our stacked rigs more frequently for opportunities where we can guarantee availability, although they remain secondary to maximizing our active fleet. Limited availability in 2024 and improving utilization increase the likelihood of stacked rig reactivations.
Reactivating a jackup requires lead time and involves a $20–30 million investment depending on the rig. Historically, floaters offered more attractive paybacks, but rising jackup day rates and longer contract durations improve the economics. We like the stacked assets we hold, and they remain strong options to capitalize on the jackup upcycle.
22/02/2024 How do you weigh reactivating a drillship versus keeping the active fleet utilized?
Our first priority is to keep our active fleet highly utilized, and there are great opportunities for that. For stacked capacity, the 13, 14 and 11, we expect to get a meaningful return on reactivation costs, around $100 million, maybe higher with inflation. With leading-edge day rates now, you can generate about $100 million in EBITDA as long as there is a term contract, and we see some opportunities for that.
We have interest in all three rigs, but we remain focused on attractive contracts for the active fleet first. With 10 rigs and the seven going to work midyear, this is a far cry from a few years ago when only four ships were working. We are willing to be patient given the market momentum and will wait for the right opportunity to put those rigs to work.
02/05/2024 What were the costs and timing around the 144 jackup contract, including mobilization and Saudi market noise?
The discussions were ongoing in late 2023, and the contract was signed in March 2024 after Saudi Aramco announced plans to suspend 22 rigs in January. We cannot disclose the day rate, but mobilization costs are slightly under $10 million. Based on the total contract value we provided, you can make assumptions for the program.
The Saudi fixtures are not representative of the broader jackup market. This is a strong contract, and we are excited to move the 144 to West Africa and start operations.
02/05/2024 If Mexico work falls through for DPS-5, could it pivot to U.S. Gulf well intervention and P&A?
The DPS-5 is both moored and dynamically positioned, offering flexibility for U.S. and Mexican Gulf opportunities. It is currently drilling one moored well and one DP well for ENI, showing versatility. There are active opportunities in well intervention, plug-and-abandonment, and traditional drilling.
Last year we successfully kept the rig active through short-term work. Beyond 2024, there are attractive longer-term programs in the Gulf of Mexico and internationally, providing potential for sustainable utilization and revenue visibility.
02/05/2024 Which of DS-11, 13, or 14 could go first, and how many reactivations are feasible in a year given labor and supply chain limits?
All three rigs are interchangeable, and the customer typically decides whether they want a proven unit like the DS-11 or newer rigs like the DS-13 or DS-14. We aim to put all three to work. We have previously completed four floater reactivations in parallel, demonstrating our ability to execute complex projects. The organization has a strong track record, such as with the DS-8, and we expect similar results with the DS-7. We are confident in reactivating these rigs effectively, whether sequentially or in parallel, once the right opportunities arise.
01/08/2024 Can you provide more insight on the suspension notices for Valaris 147 and 148, and the expected total of 7 suspended jackups in Saudi?
ARO, our joint venture, received notices for the Valaris 147 and 148 last week. We are in constructive discussions with ARO and Aramco and may instead suspend a different leased or ARO-owned rig. Which rigs will be suspended and the timing are still to be determined.
As for the broader context, we do expect around five rigs to be suspended based on market discussions. If it were the 147 and 148, that would represent about $10 million of EBITDA, or $35 million of backlog, against Valaris’ total backlog of $4.3 billion. This equals about 1% of global marketed jackups in a market with 93% utilization. Many rigs from the earlier 22 suspensions this year have already transitioned into international markets, where leading-edge day rates remain north of $150,000 per day. We see no fundamental change in the jackup market and remain confident in its strength.
01/08/2024 Was the Trinidad jackup rate agreed before April or does it confirm minimal impact from Saudi suspensions?
It is the latter. Discussions continued until the contract was finalized recently, after the first round of Saudi suspensions. The rate reflects that some markets and customers remain focused on securing top-tier assets for future developments, regardless of Saudi-driven dynamics.
31/10/2024 How do you manage costs during warm stacking and what are the catch-up costs when reactivating rigs?
Warm stacking involves reducing manning to the class minimum, handling some maintenance and projects, and, if possible, moving rigs quayside to cut fuel costs. Over about 90 days, costs can ramp down to around $60,000 per day. Bringing a rig back requires ramping up crews and catching up on deferred maintenance, typically costing $5 million to $10 million depending on stack duration.
For example, the DS-10 is expected to exit the year at a $60,000 daily OpEx run rate, while the DPS-5 should reach about $50,000 per day by year-end. Contracting cycles give us time to ramp rigs back for opportunities.
31/10/2024 How do you evaluate whether to preservation stack a rig and how does this vary by asset class?
Preservation stacking costs mid-single-digit millions, and reactivation takes longer than warm stacking. We would only preservation stack if there were no line of sight to opportunities within about two years. Given today’s robust pipeline, we favor warm stacking to prudently manage cash and capital while retaining line of sight to accretive opportunities into 2026.
For rigs like the DPS-5, which operate in markets with shorter-term contracts, we aim to secure EBITDA-positive programs in 2025. If we believe short-term work cannot be secured without high in-between costs, preservation stacking may be considered. Ultimately, the decision depends on visibility into near-term opportunities.
31/10/2024 Are you using warm stack periods for rig upgrades ahead of 2026 demand?
Yes. As we ramp rigs down, we minimize costs and cash spend while allowing for a 90-day ramp-up to return to work. That downtime provides an opportunity to complete upgrades without later interruptions. For example, we may install hard piping for managed pressure drilling (MPD) systems so rigs are ready to operate in MPD mode.
We are also pursuing environmental, health, safety, and emissions (EHSE) upgrades to lower fuel usage and emissions by running with fewer engines. These prudent investments during warm stack periods strengthen our fleet as projects pick up in 2026 and beyond.
20/02/2025 How do you manage operating costs when floaters are idle or warm stacked?
For a drillship like the DS-10, costs can be reduced to about $60k per day through minimum safe manning, reduced maintenance, and avoiding fuel burn at quayside. For a semi, we have reduced costs closer to $50k per day. These compare with average OpEx of about $150k per day when operating.
It typically takes about three months to ramp costs down from operating levels to warm-stack levels, and three months to ramp back up when reactivating.
01/05/2025 Are you seeing interest in performance-based contract incentives, and how do you balance the risks and rewards?
Yes. Performance bonuses are already part of our contracts, though not at the same scale as some recent awards. They usually target drilling ahead of the customer’s authorized expenditure or reducing days. We are open to these arrangements, but they can be complex since drilling involves multiple services beyond our control. While we consistently deliver over 96% uptime, bonus outcomes are not always directly tied to our work.
These schemes work best in long-term development programs where efficiency improves as more wells are drilled. Not all customers favor them, but some are interested. I do not expect them to become the industry norm. For customers who want them, we are open to structuring incentives where they make sense.
31/07/2025 How do you weigh stacking costs versus taking short-term contracts?
Our strategy has not changed. We will not carry high operating costs during idle periods just to chase short-term work. We only consider gap-fill opportunities that align with the end of a current contract or the start of a new one.
Doing otherwise would create poor economics and operational inefficiencies. If we find a contract that starts shortly before a long-term program and it makes sense financially and operationally, we will consider it. But keeping rigs active solely for short-term contracts is not part of our approach.
02/09/2025 What is your latest estimate for all-in reactivation costs?
I don’t think there has been a large change in reactivation costs. There has been a little oil field inflation, but we have a strong track record, having done this six times with a great project team. We have consistently delivered rigs successfully, and because we stacked our own rigs, we fully understand what it takes to bring them back. We have typically been on the lower end of the industry range due to our technical and engineering capabilities. I believe $120 million to $125 million on average still holds for our assets.
The timing would still be about a year to complete a reactivation project.
Competition
02/08/2022 Is demand growth shifting toward more direct negotiations versus tenders?
Yes, we are seeing more discussions around direct negotiations, but it depends heavily on geography. In regulated environments like Brazil and West Africa, tender processes are required. In the Gulf of Mexico, direct negotiations are more common due to less regulation and shorter-term visibility.
As demand grows and rig availability tightens, more direct negotiations are occurring alongside tenders. This trend has historical precedent and reflects the geographic differences in contracting practices.
02/08/2023 How would you characterize leading-edge jackup rates for standard and heavy-duty fleets?
You are right. The North Sea, particularly the UK side, continues to disappoint. But our high-spec fleet can find opportunities elsewhere, and leading-edge jackup rates vary by geography. We are pleased to see the 247 working in Australia on a CCS project at a leading-edge rate of 180. We also have contracts in Australia at 150 and above. Southeast Asia is improving, and rates there are well into the hundreds.
Not every contract will be signed at those levels. Rates vary by market, local operating costs, and supply-demand balance. But overall, jackup rates are well into the hundreds and much stronger than last year.
02/08/2023 How should we think about ARO jackup leases expiring in 2024–2025 compared with leading-edge rates?
Saudi Arabia is a long-term sustainable market with plenty of work. Rates there, like elsewhere, have been rising. While it is early to discuss those leases, we see attractive opportunities in Saudi. It is the largest high-spec jackup market globally and is often described as the last place that will drill oil wells.
Our strong position with ARO includes owned rigs, leased rigs, and the 20-rig newbuild program. This platform allows us to continue securing attractive work.
02/08/2023 How do you think about pricing strategy for drillships as day rates move higher?
On average, our fleet is high-spec, with about half in the top quartile, and DS-13 and DS-14 will strengthen that. Floater and drillship markets are moving higher. The DS-7 demonstrates this. It is a high-spec rig requiring no major upgrades, operating in low-cost West Africa on a long-duration contract. When bid in January, it was a leading-edge rate, and day rates have since risen into the mid to high 400s.
Rates have progressed from the 300s into the 400s, and we now see bids in the mid to high 400s. We expect them to continue rising as supply and demand tighten.
02/08/2023 Are you seeing new inquiries for North Sea projects given semi shortages, and where else could North Sea jackups find work?
We have been clear the North Sea is challenging through late 2024. In the UK, regulators are considering changes to the tax regime, but so far these have not been enough to spur activity. That said, rigs 92, 120, and 122 are contracted well into 2025, and there is work available, though mostly short term. CCS work is growing, with projects like Northern Endurance, Acorn, and Viking creating longer-term opportunities. Sometimes when rigs leave the region, it spurs regulators and operators to act to retain assets.
Outside the North Sea, opportunities exist in Australia, the Middle East, and Southeast Asia. High-spec rigs can operate across harsh and benign environments if customers compensate for mobilization. Southeast Asia is recovering with longer durations and higher day rates. There is also potential crossover between jackups and semi-subs in shallower harsh environments, though this has not yet significantly impacted jackup demand. Moves like relocating the 247 to Australia provide both opportunity and downside protection if the North Sea recovers.
02/05/2024 Will suspended Saudi jackups pressure day rates, possibly down to $130K–$140K?
Of the 22 suspended rigs, only about half are competitive internationally. High-spec utilization is 95%, which should absorb rigs in an orderly way. Some near-term pressure may occur for contractors fixing rates quickly, but we do not view this as a long-term trend.
We operate 19 rigs outside Saudi, with most in the North Sea, Trinidad, and Australia. Only four are potentially affected, three of which are on long-term contracts. We expect rigs leaving Saudi to be absorbed globally or return to home markets like China or Egypt. We remain patient and confident in opportunities for our fleet.
02/05/2024 Will sidelined rigs face discounts compared to hot rigs for 2–3 year floater contracts?
We do not expect discounts for sidelined rigs. The DS-11, 13, and 14 are among the highest-specification seventh-generation rigs with dual BOPs, and demand for such rigs remains strong. Leading-edge rates for 2–3 year contracts are in the mid- to high-$400,000 range, with potential to rise further.
Average floater day rates have already moved from the mid-$400,000s to $480,000 in the first four months of the year. We expect rates to continue climbing as supply tightens and demand increases. We look forward to placing our rigs in the right long-term opportunities.
02/05/2024 Could DS-10 and DPS-5 see materially lower short-term rates versus leading-edge?
Term contracts of two to three years are in the mid- to high-$400,000s and can reach into the $500,000s. For gap-filling work, we focus on securing the right long-term program first, then evaluate short-term bridge economics. This means short-term rates may vary but are managed strategically.
Growth
03/05/2022 What is IOC appetite for rigs in Brazil, and benefits of having rigs already in-country?
Brazil currently offers the best of both worlds, with strong IOC interest alongside Petrobras, which aims to double production by 2030. Some rigs will roll over, but we also expect incremental demand from Petrobras and IOCs. Entering Brazil requires capital expenditure to meet Petrobras’ specifications. Once established, incumbency provides a significant marketing advantage. That is why we focused on taking DS-4 there last year. Building a critical mass in priority basins is a core strategy, and we intend to expand our presence further.
02/08/2022 Is increased floater demand driving longer contracts, or are operators locking rigs due to shrinking availability?
We see higher activity levels and a strong tender pipeline, but not a broad increase in contract duration. Customers remain thoughtful about making long-term commitments, even though they see work in their pipelines. Other than Petrobras’ current tender for four-year contracts, most deepwater or ultradeep programs are around two years plus options, or three years.
Caution stems from the industry’s tough past seven years, so customers are avoiding very long-term commitments. Still, fundamentals are strong. Of roughly 90 ultra-deepwater floaters in the market, about 30 are on exploration or step-out programs. Exploration activity is a good sign for demand, but contract lengths remain shorter than in prior cycles.
01/11/2022 Do Brazil tenders at $500,000 rates justify bringing DS-7 and DS-8 back, or are other markets possible?
Good observations. I cannot share specifics on our bidding strategy, but I can say economics are attractive for reactivation. Some of the figures you mention include customer contributions to reactivation costs, which were not common a year ago. Those additions are now part of the day rates.
We see opportunities to reactivate assets given demand growth of 7% to 8% annually in deepwater floaters. Discipline is critical. Day rate matters, but so do basin location, customer quality, and contract structure. We concentrate rigs in the Golden Triangle to maximize scale and efficiency. We will be patient and disciplined, bringing rigs like DS-7, DS-8, and DS-11 back only in the right basin, with the right customer, and under the right terms.
02/08/2023 How many idle assets will incremental demand of 12–15% absorb?
We see continuing demand growth. Some rigs may shift regions, but generally rigs under contract are extended. Like peers, we aim to avoid idle time because moving rigs carries economic cost, even with partial compensation.
Demand has risen from 15–20 to 25–30 opportunities we are tracking, and that number keeps growing. The market is tightening, and we expect all attractive high-spec rigs, including DS-11, DS-13, and DS-14, plus some economically viable reactivations, will be needed to meet customer demand.
02/05/2024 What is the outlook for 30 rig opportunities in Africa and the Med, including durations and East Africa?
The 30-plus opportunities across Africa and the Mediterranean are based on contracts longer than one year, starting in 2025 and 2026. About half of these are in Africa, showing strong potential growth in the region. Using Rystad CapEx data, we see a 26% increase in spend from 2022–2030 compared to prior estimates, with Africa showing up to a 52% increase, evenly split between shallow and deepwater.
This supports the 144’s move to West Africa and broader opportunities, including East Africa, particularly Mozambique. Overall, Africa could need seven incremental rigs, making it a bright spot in the market.
03/09/2024 Are customers shifting from near-field to frontier exploration?
Yes. The first step is usually near-field expansion in existing basins, but we are also seeing frontier exploration, such as the complex work in Namibia. We drilled Bacalhau with Equinor in Brazil, and after that program, the rig drilled a rank exploration well in Argentina. Our customers know they need to replace reserves to meet long-term supply targets, so exploration must be part of the plan. The fact that operators are returning to rank and frontier exploration is a very positive sign for the market.
31/07/2025 What is the mix between development and exploration work in contracting opportunities?
As a rule of thumb, longer-term contracts are typically development programs, while exploration tends to fall within shorter-term or option-based work. Customers often build exploration wells into programs to secure rig capacity ahead of market tightening expected in 2027 and 2028.
Exploration opportunities have been growing and generally result in shorter contracts due to their multi-country nature. These shorter programs often serve as a slot for exploration before development begins, whereas longer-term projects are usually focused on development. Thus, opportunistic short-term work is more weighted toward exploration.
Financials
21/02/2023 When could a new capital structure with a revolver and high yield be achieved?
Chris Weber: We have been clear about our desire for a regular capital structure, including a revolver, which requires refinancing our note. We would like to execute this in 2023 and see potential opportunities, and we are already in discussions with our banks.
Importantly, we are not forced to do this. If terms, size, or pricing are unattractive, we will not move forward. For us, this is opportunistic. We want to act if we can secure favorable terms that make sense strategically and operationally without imposing undue restrictions.
02/08/2023 What day rate and duration are needed for strong economic returns on DS-13 and DS-14?
We manage the fleet as a portfolio. Some rigs secure long-term contracts to build a stable backlog, while others are kept available to capture leading-edge rates. With our scale, we can balance both approaches.
Today’s long-term contracts generate north of $90 million in EBITDA per rig annually. We will continue to balance backlog stability with opportunistic exposure to rising rates. DS-11, DS-13, and DS-14 give us three new opportunities alongside rigs rolling off legacy contracts.
02/05/2024 Does 97% revenue underwritten refer to the low end or midpoint of guidance?
It refers to the midpoint of the $2.3 billion revenue guidance.
31/07/2025 Has the dual activity arbitration now been fully resolved?
There is technically a right to appeal, but the bar is very high and limited to procedural issues, not the facts or findings of the arbitration. We are very pleased with the favorable outcome. While we will monitor how it develops, the matter is effectively resolved in our favor.
Outlook & Guidance
22/02/2022 What is the status of DS-11 after TotalEnergies’ exit from North Platte?
TotalEnergies has stepped back and is transferring the project to Equinor, but we have not received a termination notice. If we did, compensation would exceed our commitments. Equinor has indicated its intention to proceed, and we are in constructive discussions on the transition. DS-11 was scheduled to work after upgrades in mid-2024. It is a high-spec rig with strong demand potential, and we remain confident in its future regardless of contract adjustments.
22/02/2022 Could the DS-11 contract transfer directly from Total to Equinor, or require renegotiation?
We will not comment on contract details, but the agreement includes provisions for transferring operatorship along with the drilling contract. The contract remains in full force and effect, and we will see how the process develops.
22/02/2022 Could floater day rates reach $500k in 2023 given current utilization?
Floater market momentum has been strong, with day rates moving from the high-100s last year to much higher levels now. Each contract depends on timing, location, start-up needs, and duration. Drillship availability for late 2022 and early 2023 is extremely limited, which supports a price premium.
We are optimistic about the market and our position. We have re-contracted stacked ships successfully, with only two drillships left that have been stacked less than two years. We established a base load and are disciplined in adding capacity as the market develops. Overall, we feel positive about future opportunities.
02/08/2022 Do rigs rolling off in spring 2023 have options, and what are prospects in West Africa and Brazil?
DS-15 in Brazil has options, and we expect it to continue with Total given strong activity there. In West Africa, there is a solid pipeline of tenders. Our priority is to find the right opportunities for rigs to roll onto.
There is plenty of work, and it is an attractive time to have rigs available. Recent fixtures are generally 18 months to 2 years, with some in Brazil stretching to 3–4 years. We may use short-term work to bridge into longer-term programs. The rigs are attractive, have strong track records, and customers like them. DS-10 and DS-15 options are now disclosed in our fleet status report.
01/11/2022 Are customers starting to seek longer contracts as day rates rise?
Hi, Greg, I think that is a fair observation. Leading-edge day rates for drillships have doubled from about $200,000 in 2020 to $400,000 in 2022. In the last down cycle, many customers were caught holding long contracts and spent heavily on terminations. That has created reluctance to commit longer than their immediate programs require. Exploration programs are shorter, trending toward one year as rig availability tightens. Development programs are typically one to three years, and I expect this pattern to persist.
Even so, reactivation economics can work well. For example, on the DS-17 we secured an 18-month to two-year contract at rates in the high 300s to low 400s, which is attractive. While some stacked rigs and stranded assets remain that can re-enter the market at these levels, it is still a market where we can make good business.
01/11/2022 How do you avoid cannibalizing the active fleet given weaker backlog than past cycles?
You are exactly right. Our first priority is to keep the active fleet fully utilized. We will only bring back stacked rigs when opportunities justify it. Unlike prior cycles, we do not yet see long-term four to five year contracts across the floater fleet, which means we must be careful in fleet management.
Still, when the initial reactivation program delivers meaningful returns, we do see incremental demand that allows additional reactivations. The key is balancing timing with discipline so that we grow without undermining our existing fleet.
01/11/2022 Outside of ARO, could there be another jackup newbuild cycle?
In the medium-term, no. Building jackups is less costly than floaters and more yards are capable of building them, so the chance of a newbuild cycle is higher for jackups than floaters. That said, we are still a long way from seeing that happen.
01/11/2022 How do you decide where to reactivate cold-stacked floaters across the Golden Triangle?
We currently have three high-spec drillships in each part of the Golden Triangle. Ideally, we would add one more in each corner, but we will deploy based on the most attractive opportunities. Each basin has specific requirements, particularly Brazil and Petrobras, which demand certain equipment setups and limit upfront mobilization payments to around 70 days of day rate. That means day rates must reflect additional CapEx and mobilization.
There are also opportunities in Africa, both West and North, that could support reactivations. Recent tenders show a difference between operators already active in Brazil, who bid to maintain operations, and those bringing rigs from outside, who need compensation for upgrades and mobilization. With scale positions in each basin, we have flexibility to act where the economics are strongest.
21/02/2023 Is North Sea recovery in 2024 driven by customers or your own forecasts?
Matt Lyne: In 2022 we were optimistic about 2023 demand, but the windfall tax created headwinds, causing operators to pause and reassess project economics. This led to short-term delays rather than cancellations.
We now see projects rescheduled into late 2023 and 2024, providing a stronger outlook. This view is largely driven by customer discussions in the North Sea. Anton Dibowitz: It is mainly about timing. Projects have shifted to the back half of 2023 and into 2024 as operators adjust their capital allocation.
02/05/2023 What costs are involved in reactivating a drillship and how could that impact EBITDA guidance?
Chris Weber: From a cost perspective, we’ve guided $65 million to $75 million for reactivation, and we are at the top end around $75 million. About two-thirds of that would be expensed and one-third capitalized, so there would be an EBITDA hit in the year if another project starts.
Anton Dibowitz: On opportunities, many rigs are being recontracted by the same customers in the same basin, but we also see incremental opportunities for reactivated rigs, stacked drillships, or stranded assets. With day rates in the low to mid-400s and potential to go higher, we remain clear that we seek to recover reactivation costs and earn a meaningful return under the initial firm contract, which is achievable given current market conditions.
02/05/2023 Will leading-edge day rates exceed $500,000 per day by year-end?
Chris Weber: Day rates have more than doubled over the last two years from the low 200s to the mid-400s, with the general clearing range today in the low to mid-400s. Some contracts fall outside that band, either lower or significantly higher. For example, we signed one last year that averaged over $600,000 per day. Overall, day rates continue to grind higher despite occasional fixtures that are not sequentially higher.
Chris Weber: It is possible we will see rates above $500,000 a day as the market tightens, but it depends on the type of contract, market, and rig positioning. Rolling an existing rig may favor contract duration and cash flow, while reactivating requires discipline and higher day rates to cover costs. Effective rates vary depending on circumstances, but the upward trend continues.
02/05/2023 At what oil price would customers pull back activity given recession concerns?
Anton Dibowitz: Customers are focused on long-term pricing, not short-term spikes. Even when Ukraine drove prices higher, we did not see a major shift. As long as oil is above $60 to $70 per barrel, customers remain committed to replacing reserves after years of underinvestment. Demand continues to grow and customers, making record profits, see a strong need to maintain production.
Anton Dibowitz: We are now discussing contracts beyond sanctioned projects, as customers want long-term access to drillships. That shows confidence in the market and industry outlook. Offshore remains attractive with meaningful production potential and lower carbon intensity compared to U.S. land barrels, which are in decline. The market is volatile, which is why we maintain a disciplined capital structure, low leverage, and ample liquidity to stay focused and value-driven for the long term.
02/05/2023 If you purchase the DS-13, how long until it could begin a contract?
Anton Dibowitz: Timing for the DS-13 and DS-14 would be similar to reactivating one of our preservation stacked assets. We now expect reactivations to take about 12 months, versus six to nine months a year ago. That is the plan for the DS-17 and DS-8, which are currently on schedule. I would think of the 13 and 14 in the same timeframe.
05/09/2023 What payback period do you expect for DS-11?
The DS-7 contract was bid in January, and since then the market has improved. With 10 of 11 rigs working and supply dwindling, we have raised our hurdle rates. We will be thoughtful and opportunistic on DS-11, expecting a higher hurdle and not necessarily the same one-year payback as DS-7.
05/09/2023 Could leading-edge day rates reach $600,000 next year?
Yes, newbuild parity is the limiting point. Building a rig today would cost north of $1 billion, so day rates could theoretically reach very high levels. Practically, there are reasons they may not, but limited supply will pressure rates. Only a few stranded assets remain, and opportunities outnumber rigs. This imbalance should tighten the market further. Customers may also favor high-spec semis as an alternative, creating some balance. Still, $450,000 to $600,000 day rates with $150,000 OpEx are highly attractive economics.
05/09/2023 Do you expect another newbuild cycle?
No. To justify building, costs in Korea would exceed $1 billion, requiring day rates near $900,000 with 90% utilization for 30 years. That math is unrealistic. We do not expect another newbuild cycle.
05/09/2023 How many contracted floater rigs do you expect by end of next year?
Today there are about 125 to 130 rigs. By the end of next year, most high-spec stacked and newbuild rigs will be needed in the market. Lead times mean not all will be working immediately, but we expect to be well on our way toward a much tighter market.
07/11/2023 How many five-year opportunities exist and are they region-specific or broad-based?
Good question, Eddie. We know of at least two international oil companies considering long-term jobs beyond the typical two to three years. That is a strong sign, as demand is projected to grow around 8% annually, and customers want to secure attractive rates in advance.
There is always a trade-off with longer contracts. You may take a slightly lower rate for longer earnings visibility, but not at any price. We are comfortable with current mid-400s rates and expect them to increase. We have walked away from unattractive opportunities before and will continue to do so. If a long-term contract is sensible and the trade-off manageable, we will take it; otherwise, we let others pursue it.
07/11/2023 How much stacked and stranded new-build drill ship capacity could realistically join the active fleet?
On stranded new-builds, we see about five rigs as credible entrants, including the DS-13 and DS-14, which are the highest-spec seventh-generation units and the only ones with two blowout preventers. On stacked drill ships, you could argue up to 10, but realistically closer to four seventh-generation rigs are most likely, depending on age, stacking duration, and special periodic survey cycles. Reactivation costs will also factor heavily.
Overall, the pool of attractive stacked and shipyard assets is shrinking. Our priority remains utilizing the active fleet first, with reactivations tied to incremental demand. Drill ship utilization has been around 90% for a significant period, and we expect new demand to absorb the remaining attractive assets over the coming years.
07/11/2023 How do operators view rising day rates given constrained supply and project needs for 2024–2025?
We feel very good about the market today and the longevity of the cycle. Lead times for tenders are increasing, and customers are extending contract durations by connecting programs. This shows they recognize tightening supply and want to secure rigs for longer. Utilization is rising, supply is decreasing, and these supply-side dynamics point to continued improvement in day rates.
No operator wants to pay more than necessary, and we do not want to put rigs to work for less than we can achieve. It comes down to simple supply and demand. Day rates do not move in a clean curve, but as the market tightens further and incremental demand enters, we gain more leverage. As long as demand continues to grow into a sustained cycle, rates will keep moving upward regardless of personal opinions on where they “should” be.
22/02/2024 How do you view the trend in floater day rates through year-end?
Over the last 12 to 18 months, lead times for tenders have increased and contracting durations are lengthening, which supports the longevity of the market. Majors are even picking up rigs on what could be called speculative demand, as seen in a recent joint venture, securing rigs before all programs are approved to lock in favorable rates. That shows the strength of the market.
We are cautious about predicting exact milestones, but leading-edge day rates have continued to grind higher on average. The market is tightening with fewer idle assets and growing demand, which will drive rates higher over time. There may be gaps due to lead times, repositioning, or upgrades, but overall we remain positive on the trend.
22/02/2024 If demand is tight, why do oil companies retain leverage to cap pricing?
Leading-edge day rates are generating about $100 million annually of EBITDA, which reflects a strong market. Incremental demand continues to emerge while attractive stacked capacity has dwindled to around 10 rigs. This tightening balance will keep pressure on day rates to move higher over time.
We see this as a long-duration cycle. The key is to stay patient and disciplined as we reintroduce capacity like the 11, 13, and 14 into the market at the right time.
02/05/2024 Is 2024 EBITDA guidance of $500–$600 million maintained, and what is needed from DS-10 and DPS-5 to hit midpoint?
Yes, we are maintaining guidance at $500 million to $600 million. To reach the midpoint, we need incremental work on the DS-10 and DPS-5. The organization is focused on securing that work, and discussions with customers are active.
At present, 97% of 2024 revenue is underwritten. We modeled some idle time for these rigs, but as last year showed with the DPS-5, we can fill gaps with opportunistic work. We must see pieces fall into place to deliver the midpoint of guidance.
02/05/2024 Can you quantify the expected increase in contracting pace in 2H 2024?
We cannot assign a precise percentage, but tendering activity for 2024 is very solid. Seasonal fluctuations may shift awards between quarters, particularly as long-term, multi-jurisdictional programs require extended approvals. Based on active tenders, we expect an acceleration in contracting pace and awards over the remainder of the year.
02/05/2024 Is strong revenue efficiency continuing in Q2, and what underpins guidance?
Revenue efficiency remains solid in Q2, and EBITDA guidance is consistent with expectations set earlier in the year. Some may model a linear progression, but we see more of a ramp into Q3 and Q4 due to rigs transitioning, special surveys, and relocations. For example, the DS-247 is moving to Australia, and the DS-7 starts in midyear.
Compared to Q1, Q2 growth is driven by more operating days in the floater fleet, including contributions from DPS-5 and DS-12, plus rigs rolling to higher rates. Jackups that were idle or in preparation in Q1 are returning to work in Q2. We expect EBITDA to increase almost 80% from Q1, with further growth in the second half as DS-7 begins, DS-16 contributes, and North Sea and Australian jackups add higher-rate work.
01/08/2024 What is your outlook for net incremental seventh-generation deepwater demand through 2026?
From our prepared remarks, we see around 30 opportunities with durations averaging 2.5 years. Of those, about 10 could provide incremental opportunities by region. Customers generally prefer seventh-generation rigs, and 12 of our 13 drillships fall into that category. Not all of those 10 will necessarily be filled by sideline capacity, but our sidelined rigs , the DS-11, DS-13, and DS-14 , are the highest-spec available and well-positioned for those opportunities.
01/08/2024 Are you seeing shrinking lead times for floater contracts like in other regions, and should we worry about slower contracting pace in 2025?
We are not concerned about the pace of contracting, which is not linear through the year. Data can be influenced by geography and mix. Formal Petrobras or West Africa negotiations may have longer processes compared to more direct negotiations elsewhere. Overall, we see lead times increasing as demand and supply dynamics tighten into late 2025. Contract durations are extending, and day rates continue to climb, with six fixtures above $500,000 a day so far this year versus only two last year. These trends support a constructive outlook for the floater market.
03/09/2024 What is the status of DS-10 in Nigeria and near-term work outlook?
The DS-10 has been drilling in Nigeria since 2018 with excellent performance and a strong crew. Customers are satisfied, but the client is pausing activity, leaving the rig without immediate work. We expect incremental demand in Nigeria over the next few years, so the goal is to find short-term work until long-term programs begin in late 2024 or 2025. The DS-12 is also rolling off next year, creating short-term dislocations. Our commercial team has historically kept rigs working continuously, though I cannot promise the same outcome this year. Some programs we were pursuing slipped into 2025 or were split, so for now we are chasing Q4 work, which led us to adjust guidance.
03/09/2024 Do you expect near-term day rates to remain in the high 400s to low 500s?
We have never projected a sudden hockey-stick move in day rates. This is a structural upcycle where rates continue to grind higher, though not every contract is higher than the last. Comparing second-half 2023 with 2024, average floater day rates moved from 450 to 480, with several contracts above 500 already this year. That shows the trend is upward. Near-term, rates may show more variability as we focus on keeping crews together and rigs working, but customers are willing to pay for the right rig. One client is paying a significant portion of day rate just to hold a rig for six months. Increasing contract durations and higher average rates confirm the market’s positive direction.
03/09/2024 Where will leading-edge deepwater contract day rates likely be by 2026?
I try to be realistic, not overly bullish. By late 2025 and into 2026, contracts will reflect new demand visibility, including 30 identified opportunities, West Africa growth, and potential sidelined capacity. This should tighten the market and support higher day rates. We openly acknowledge 2024–2025 as a period to manage through, but by this time next year, I expect day rates to be solid or higher versus today.
03/09/2024 Could day rates reach the inflation-adjusted $800,000 peak of 2011–2014?
We do not expect to reach $800,000, nor do we need to. Economics of new builds do not support that level. At current day rates in the high 400s to low 500s, a rig can generate around $100 million in EBITDA, which is a very strong position for the company and industry. Customers are not pushing back on rates, and there remains headroom. While the absolute peak is uncertain, the economics clearly allow for further upside without needing to return to historic extremes.
03/09/2024 What is the expected cadence for reactivating DS-11, 13, and 14?
Three years ago we had four ships working; now we have ten, and the three best assets still sidelined. These are dual BOP, 7th generation rigs, and we have ongoing discussions with interested customers. We have declined deals that lacked attractive economics, focusing instead on maintaining high utilization of the active fleet. Based on demand trends, bringing back about one rig per year over three years is reasonable. None of the rigs reactivated so far displaced incumbents; all came back for incremental demand. With demand expected in late 2025–2026, we will be patient and deploy these rigs only under the right opportunities.
03/09/2024 Update on ARO rig suspensions and Aramco pricing requests?
We have not received any pricing reduction requests at ARO, though I know others in the industry have. For the suspensions, rigs 147 and 148 will handle those. Earlier this year, 22 rigs were released, about half of which can compete internationally. We’ve seen them transition in an orderly fashion into the market, with leading-edge jackup day rates still around 150. Internationally, we see good opportunities, particularly in Trinidad and Australia, where premium rates are paid for super high-spec jackups. While the release of rigs in Saudi creates challenges, utilization remains above 90% and leading-edge rates around 150, so this is a manageable transition.
03/09/2024 Are leading-edge jackup rates higher than 150 in some regions?
Yes. In markets like Trinidad and Australia, rates can reach the high 100s. Australia is a higher-cost area, but customers are willing to pay for the right rig, especially for specialized work such as carbon capture and storage. Rates vary, as some contractors bid lower to enter markets. We will continue to be patient and disciplined, as with rigs 143, 147, and 148, avoiding desperation to force entry. We see incremental demand and will wait for the right opportunities.
31/10/2024 What is your outlook for day rates over the next 12–18 months?
It is gratifying to see day rates increase quarter-over-quarter this year. We expect some variety next year with whitespace, but customers remain willing to pay mid- to high-400s and into the 500s for high-specification assets in the right markets. Recent contracts, like the 2017, demonstrate this.
Rates will depend on asset quality and the market, with some variety as customers chase bridge work or shorter programs before longer-term projects. Overall, we see the outlook for day rates as solid.
31/10/2024 Are demand deferrals affecting both deepwater and shallow water, and when might FPSO bottlenecks ease?
It is mainly a deepwater phenomenon tied to large, long-term developments. Yards are very busy, FPSOs are taking longer to complete, and delays have occurred. Customers are prudently aligning drilling schedules with when FPSOs and production equipment will be ready.
We see this as a transitory issue rather than a structural one. Even if FPSO deliveries are delayed a year or two, the supply chain ultimately stabilizes, much like what we have seen with oilfield equipment deliveries.
31/10/2024 What is the updated outlook for DS-11, 13 and 14 and potential scrapping of older assets?
Our fleet has organic growth potential with DS-11, 13 and 14, all high-spec seventh generation rigs. We acquired 13 and 14 at attractive prices and expect them to be accretive as opportunities materialize in 2026 and beyond. For now, our priority is keeping the active fleet highly utilized. These rigs will return when the right opportunities arise, but the timeline is slightly later than expected six to nine months ago. Warm stacking remains prudent cash and fleet management.
It is also possible we will see less capable sixth generation assets leave the market. Preservation stacking or maintaining lower-spec rigs for long periods does not make sense, so some capacity could come out of the market over the next year.
31/10/2024 How do you prioritize strategy for idle assets during current market softness?
We feel good about fundamentals and the pipeline of opportunities into 2026 and beyond. Scale allows us to manage our fleet as a portfolio, lowering costs and warm stacking rigs during near-term headwinds while waiting for the right opportunities.
Our focus is on long-term accretive programs that support earnings and cash flow growth. If meaningful bridge programs exist, we will put rigs to work. What we will not do is incur full operating costs chasing low-value, non-accretive opportunities. We are willing to warm stack rigs until attractive long-term contracts emerge, while relying on our scaled fleet and rigs on long-term contracts to carry us through.
31/10/2024 Why does the stock trade as if the cycle is ending when fundamentals remain strong?
Markets can be fickle, but global hydrocarbon demand continues to grow. Offshore production, especially deepwater, is set to remain a solid and increasing source due to compelling program economics and the need for secure, affordable energy. Our customers must replace reserves as depletion continues, which supports strong demand.
We feel confident about the strength and duration of this cycle. Our focus is on managing effectively through the upcycle. While we cannot speculate on stock movements, we remain positive about the long-term fundamentals driving our business.
31/10/2024 At $70 oil, what portion of offshore projects remain profitable, and where do deepwater projects stand?
The $70 figure applies to all offshore. Our investor deck shows production cost bands by price level, with the majority of offshore production well clear of $70, in the $20 to $40 range. Many of the large developments customers are pursuing fall into that $20–30 band.
This provides a wide margin versus current spot and long-term Brent, making program economics compelling. Deepwater projects are included in this, and most remain attractive well below $70 per barrel.
20/02/2025 How much of the $530m 2025 EBITDA midpoint is already booked versus dependent on new awards?
When we look at the midpoint, about 94% of revenue is contracted for the year. The remaining 6% is later in the year, but roughly 94% is already secured.
20/02/2025 Does this 94% contracted level tie to the midpoint of guidance?
Yes, that percentage is tied to the midpoint.
20/02/2025 What is the likelihood one of DS-11, 13, or 14 is working by year-end 2027?
Our focus is on putting the active fleet to work, with several rigs rolling next year. The DS-11, 13, and 14 are high-spec seventh-generation assets with two BOPs and strong thrust capacity. Based on the pipeline of activity we see, there will be good long-term opportunities for them.
We are going to be patient in returning them to the market. This is not about a calendar target but about timing the market. Offshore demand continues to grow, and these rigs will have their place, but we are in no rush to reactivate them in the near term.
20/02/2025 What gives you confidence that 2026–2027 programs will materialize on schedule despite delays in this industry?
We review the same macro models and customer CapEx plans as everyone, and those spending plans continue to rise into 2026 and 2027. More importantly, I spend significant time with our customers, both in their offices and offshore. The programs they have on the books are being actively planned, and they are seeking reliable partners to deliver them.
Yes, projects can move left or right due to macro or supply chain issues. But based on direct conversations with customers about specific programs, I feel very confident about the demand pipeline in 2026 and 2027.
20/02/2025 Are ultra-deepwater rigs fixing in the mid-high $400k range and sixth-gen in mid-$300k?
We only have one sixth-generation rig, the DS-4, contracted until Q4 2027. For us, the focus is seventh-generation rigs, which customers prefer for long-term programs. Recent fixtures for high-spec assets have been in the mid to high $400k range, and that is where the market sits.
Our strategy is clear: deliver strong operations for customers, minimize costs while rigs are idle, and place our high-spec fleet into attractive long-term contracts. We will be patient and disciplined in pursuing those opportunities.
20/02/2025 Does 94% contracted revenue midpoint also translate to EBITDA?
Yes, that is a fair way to look at it.
20/02/2025 Do the two high-spec floater opportunities under discussion have 2025 start dates?
Those opportunities are more likely to start in the first half of 2026. There is little work starting in 2025, and our priority is to secure long-term contracts that can span years and include follow-on work.
Once long-term programs are secured, we may look at adding short-term work ahead of them if it makes sense. What we want to avoid is ramping rigs up and down for small contracts that do not lead into those long-term development programs.
20/02/2025 Are smaller tie-back or exploration programs also being delayed, or just large projects?
Smaller tie-back and exploration programs are not being pushed back disproportionately. They act as gap-fill after operators allocate capital to their major development programs.
These decisions depend on operator capacity and budget in a given year. They remain a secondary priority relative to large-scale projects but are pursued when circumstances allow.
01/05/2025 Has the move lower in day rates created more subsea tie-back opportunities in the Gulf of Mexico?
I would not directly link the two. For the past several quarters, we have expected industry white space in 2025, with most Gulf of Mexico and international programs starting in 2026 and beyond. That outlook has not changed, despite some macro uncertainty. Customer behavior remains consistent with what we had expected.
There will always be opportunistic operators who may initiate wells in 2025, but this is not rate-driven. As we enter this period of white space, rates will vary, yet we have not seen a material shift. Most term contracts are still starting with a “four” in front of them.
01/05/2025 What pricing levels are you seeing on the five-year jackup extensions in Saudi, and do they signal the end of rig suspensions?
We cannot disclose day rates without customer approval. What I can say is that rates are above historic levels, and back-calculations by some observers have been fairly accurate. These are solid contracts, and we are proud of the work done with ARO to secure 25 years of backlog on those rigs. We are very comfortable with them.
As for Saudi Aramco’s future plans, ARO is a key partner and part of their infrastructure. We continue building new capacity through IMI, and our joint venture with Aramco is strong. With these extensions, from Valaris’s perspective, one leased rig rolls in 2027 and the rest into 2030, which we are very pleased about.
31/07/2025 Of the 30 floater opportunities, how many have been delayed or replenished this year?
A year ago, we were tracking about 30 opportunities, but many were pushed forward by roughly a year. We expected awards to accelerate in 2024, and that has happened. The pipeline remains at about 30 because as contracts are awarded, new ones enter the set. This is not the same 30 from last year. Customer discussions and ongoing awards give us confidence that these contracts will continue.
While some timing has shifted, windows for rig startups are narrowing, and consistency from customers is improving. These delays are mostly linked to equipment delivery rather than cancellations. The trend has moved from “if” to “when,” which is a very positive signal.
31/07/2025 What are your thoughts on leading-edge day rates trending into low 400s, and could they soften further?
Seventh generation utilization could exit 2026 in the 90s, which is very positive. As utilization increases, day rates typically follow. The pace will depend on availability, tendering, and duration of contracts. Recent contracts we secured were all in the 400s, which shows the resilience of the market.
This comes down to supply and demand. When utilization tightens, day rates rise, and when availability increases, day rates face pressure. We expect some pressure through 2025 as rigs are released and utilization troughs in early 2026. Still, with most of our rigs fixed above 400, and seventh gen rigs maintaining a clear premium over sixth gen, we expect them to lead the recovery and exit 2026 at high utilization with upward pressure on day rates.
31/07/2025 When might cold-stacked drillships be reactivated, 2027 or later?
We will not speculate on specific timing. Our near-term focus is on the active fleet and securing contracts for the DS-12. Three of our four rigs with near-term availability are already fixed, and we see good opportunities for the DS-12 in 2026.
As the market tightens over the next couple of years, having three high-specification seventh generation rigs with dual blowout preventers on the sidelines gives us valuable optionality. We will bring them back when the market is ready, but we will remain patient and disciplined.
31/07/2025 What is your outlook on Petrobras tenders for Buzios, Mero and a potential third round?
It is positive to see Petrobras back in the market. The consensus among peers and analysts is that Petrobras will maintain a flat rig count through the end of the decade, which shapes their tendering schedule. Our intelligence suggests the current Buzios tender under evaluation could award more than one rig, possibly three or four. A follow-on tender could look similar, though formally it starts with one.
Petrobras demand for high-spec rigs is a key driver of global floater demand. Alongside Petrobras, we are also seeing exploration work from IOCs such as Equinor and Shell. This combination of stable Petrobras demand and growing IOC activity points to a very healthy Brazilian market over the coming years.
31/07/2025 What is the current Saudi rig count outlook and your position there?
Saudi is currently running a rig count in the mid-50s, slightly above pre-ramp-up levels of 2022–2023. There will always be some fluctuation in customer needs, but from our perspective with ARO, we are in a strong position.
We executed extensions last quarter, and our Valaris fleet is largely contracted through the end of the decade, with only one rig rolling in 2027. This gives us good visibility and confidence in our Saudi position.
02/09/2025 What is your outlook for the jackup market, including benign and North Sea segments?
Jackups are an important part of Valaris and a productive business for us, adding scale, customer relationships, and earnings. Our position includes the 50/50 ARO Drilling joint venture with Saudi Aramco, where we lease seven rigs. This year we extended five of them through 2030 at significantly higher rates. Six rigs are contracted through 2030 and the other through 2027. We are selective in the jackup market, operating on long-term contracts in Qatar, Trinidad, and Australia, where high-spec assets command premium day rates. Despite Saudi releasing rigs, global jackup utilization has remained at 90% or above, making this a strong cash-generating market.
On the harsh environment side, we have a leading North Sea presence with solid contract coverage and customer relationships. While some operators have shifted focus to other basins, we see about 20 opportunities across the UK, Netherlands, and Denmark. Our jackup fleet is 70% contracted for 2026 and 60% for 2027. Year over year in 2025, we expect growth in both average day rates and operating days. Overall, the jackup business remains a strong contributor of cash flow and EBITDA.
02/09/2025 What oil price assumptions underlie your outlook for the 2026 cycle?
We see customers rotating from short-cycle onshore projects, which struggle at current prices, to large-scale offshore developments. These programs provide scale, compelling economics, and lower emissions intensity. Data from RESTAR indicates that 75% of expected projects over the next three years are economic below $50 per barrel.
With the forward strip north of $65, offshore development looks resilient. Our discussions with customers confirm this rotation, with expectations for increased exploration and greenfield development. We feel confident about the outlook.
Risks & Macro
22/02/2022 Could expected West Africa tenders slip into next year?
West Africa tenders usually involve long cycles and strict regulation, so operators generally plan ahead to secure rigs on schedule. Timing depends on regulatory approvals and local company processes. Some projects may need re-planning if rigs are unavailable, but activity is picking up in Angola and Nigeria, and new discoveries in the region support growing demand. Overall, we see strong momentum in West Africa.
22/02/2024 Will Saudi curtailments reduce jackup demand or affect your leased rigs?
It is still early to judge the exact impact, but we believe it will be minimal to none for our business. Saudi delayed expansion of Safaniyah and Manifa, two oil-focused fields, but expects to develop resources and sees increasing long-term demand for oil and gas. The global jackup market is very tight with active utilization near 95% and the rig count at its highest in almost nine years. We also see 10 to 15 incremental rigs of demand outside and inside the Middle East.
Valaris has eight rigs leased into ARO, with two more entering under new contracts this year. Saudi Aramco and the Kingdom remain committed to the ARO joint venture, and the IMI newbuild program is a cornerstone of Saudi Vision 2030. Two of our leased rigs are on gas fields, not the focus of recent announcements, and overall this represents about 5% of our backlog. We are comfortable with our position in Saudi and globally.
20/02/2025 What are Aramco’s plans for jackups, and do you expect further suspensions or recontracting?
I am not aware of any discussions about additional rig suspensions in Saudi Arabia. I cannot comment on other fleets, but for our rigs, we secured short-term extensions at the end of last year to support ongoing talks.
“Advanced discussions” is accurate. They are constructive, and if needed, further short-term extensions will help conclude them. I feel good about being able to roll those rigs in Saudi and continuing our strong relationship with ARO to support Aramco’s needs in the kingdom.
01/05/2025 At what oil price level could offshore FIDs begin to be delayed?
We have not seen any offshore final investment decisions (FIDs) or programs pushed back. We remain in ongoing tenders and customer discussions, particularly for long-term opportunities in 2026, 2027, and beyond. These are long-cycle developments that will produce toward the end of the decade, and we have seen no changes so far.
While macro uncertainty has increased, offshore project economics remain compelling. They are attractive well below current oil prices and even below the five-year forward curve. Offshore production remains advantaged relative to other sources, which is why customer behavior has not materially changed.
31/07/2025 How are customers feeling about the current macro environment compared to earlier this year?
Customers have not lost confidence. Offshore projects remain highly economic, with more than three-quarters of expected projects over the next few years breakeven below $50 per barrel. Even with OPEC+ adding supply and geopolitical uncertainty, oil has held in the mid-60s, which many would have doubted six months ago.
As a result, customers feel confident contracting rigs and moving ahead with developments. Compared to earlier in the year, we see a more constructive outlook from them and a willingness to advance programs.
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