Valaris - Q4 2022

Transcript

Operator (participant)

Good day, welcome to the Valaris Q4 2022 results conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then One on your touch-tone phone. To withdraw your question, please press star then Two. Please note this event is being recorded. I would now like to turn the conference over to Darin Gibbins, Vice President of Investor Relations and Treasurer. Please go ahead.

Darin Gibbins (VP of Investor Relation)

Welcome, everyone, to the Valaris Q4 2022 conference call. With me today are President and CEO, Anton Dibowitz, Senior Vice President and CFO, Chris Weber, Senior Vice President and CCO, Matt Lyne, and other members of our executive management team. We issued our press release, which is available on our website at valaris.com. Any comments we make today about expectations are forward-looking statements and are subject to risks and uncertainties. Many factors could cause actual results to differ materially from our expectations. Please refer to our press release and SEC filings on our website that define forward-looking statements and lists risk factors and other events that could impact future results. Please note that the company undertakes no duty to update forward-looking statements. During this call, we will refer to GAAP and non-GAAP financial measures.

Please see the press release on our website for additional information and required reconciliations. As a reminder, this morning, we issued our most recent fleet status report, which provides details on contracts across our rig fleet. An updated investor presentation and ARO Drilling presentation will be available on our website after the call. Now, I'll turn the call over to Anton Dibowitz, President and CEO.

Anton Dibowitz (President and CEO)

Thanks, Darin, and good morning and afternoon to everyone. During today's call, I will start by providing an overview of our performance during the quarter. I will then provide commentary on the outlook for the offshore drilling market, highlight some recent contract awards, and discuss our strategy for maximizing shareholder value during the unfolding industry upcycle. After that, I'll hand the call over to Chris to discuss our financial results and guidance. I'd like to start by acknowledging the focus and efforts of the entire Valaris team, which resulted in us continuing to deliver excellent operational performance, achieving revenue efficiency of 98% in the Q4 and 97% for full year 2022. This is commendable performance given we reactivated four floaters during the year.

These projects required a significant amount of internal resources and attention, and we are extremely pleased to have maintained high levels of operational performance that our customers expect from us under these circumstances. The safety of our offshore crews and onshore personnel is at the core of what we do as an organization, and we achieved some notable milestones during the quarter, including several rigs reaching two years and our Broussard warehouse achieving six years without a recordable incident. These achievements are the result of our highly skilled and dedicated workforce. We believe that our people are the most important element of our success, and we recognize that a motivated, engaged, and diverse workforce is essential to delivering high performance. As a result, we continue to invest in our people, both onshore and offshore.

Our bold leadership training for offshore supervisors was attended by approximately 650 personnel in 2022. We also recently completed 2 pilot workshops for our new onshore leadership program and will be holding more of these courses in 2023 to develop senior leadership throughout the organization. Development of our people is just one element of our ESG program. We are committed to making progress on our sustainability journey, and we have a strong framework in place to advance our efforts. Our sustainability program is primarily focused on reducing emissions from our own operations and partnering with our customers on their ESG efforts. We have already implemented several solutions on board our rigs to help lower emissions, such as engine optimization and SCR systems, and we will continue to make targeted investments in our fleet where it makes economic sense to do so.

During the Q4 , we issued our latest annual sustainability report, which was prepared in accordance with the Sustainability Accounting Standards Board, and we will be further enhancing our disclosures in the 2022 report. Following the release of our 2021 sustainability report, our ESG rating was upgraded by both MSCI and Sustainalytics, two of the leading ESG rating agencies. As a result, we now have the highest ESG rating among offshore drillers with both MSCI and Sustainalytics. Moving to our financial performance for the quarter. We generated adjusted EBITDA of $54 million and adjusted EBITDAR adding back one-time reactivation costs of $75 million. Adjusted EBITDA and EBITDAR were in line with and higher than our prior guidance, respectively, but were lower than the Q3, primarily due to the ongoing weakness in the harsh environment jackup market, which I'll discuss in more detail in a moment.

During 2022, we successfully executed four major floater reactivations, with all four rigs returning to work largely on time and on budget. We are currently reactivating VALARIS DS-17 for a contract with Equinor Offshore Brazil starting later this year, and we're in advanced discussions regarding a further drillship reactivation for a multi-year project expected to commence within the next 12 months. The reactivation of VALARIS DS-17 and any additional reactivations will impact our financial results and cash flow in 2023 as we spend money to return rigs to the active fleet. Based on our contract profile, we believe that 2024 will represent an inflection point for earnings, with at least three drillships expected to complete legacy contracts and be available for recontracting at market rates, along with meaningful contributions from DS-17 and any additional rigs that we begin to reactivate in 2023.

We are optimistic about these repricing opportunities because the fundamental outlook for our industry remains constructive. Despite the macroeconomic uncertainty, demand for hydrocarbons continues to increase. The IEA forecasts that oil and gas demand will increase by 1.9 million barrels per day to approximately 102 million barrels per day in 2023, with nearly half the expected gain attributed to increased demand from China following the lifting of COVID restrictions. Meanwhile, the IEA forecasts supply growth to slow to 1 million barrels per day as compared to 4.7 million barrels per day in 2022, in part due to expected declines in output from Russia. A lack of investment in new sources of production over the past several years has contributed to a tight supply picture.

While events over the past 12 months have brought the topic of energy security to the fore and highlighted the importance of oil and gas in meeting the world's need for secure and affordable energy. A significant increase in investment will be required to rebuild global supplies, with offshore production expected to continue playing an important role due to the scale provided by offshore reserves, attractive break-even prices for most offshore projects, and lower carbon intensity as compared to onshore oil and gas extraction. We believe that these factors, along with a significant reduction in the global rig fleet, especially floaters over the past several years, lay the foundation for a sustained industry upcycle in which Valaris is poised to thrive. Commodity prices remain at levels that are highly supportive of continued investment in offshore oil and gas projects.

According to S&P Global, offshore exploration and production spending is expected to increase by 14% in 2023, following an estimated 18% increase in 2022. In addition, offshore project approvals in 2023 and 2024 are expected to be at their highest levels in more than a decade, which should help drive capital expenditures for several years to come. The constructive macro environment and increased upstream spending have led to increases in contracting and tendering activity across both floaters and jackups. The number of contracted benign environment floaters has steadily increased from the lows in late 2020 and early 2021 and has nearly returned to pre-COVID levels.

Active utilization for drillships is currently above 90% and has been above 85% for more than 12 months, which has led to meaningful improvements in day rates, with leading-edge day rates now pushing in the low to mid $400,000s. As of the end of 2022, rig years of open demand at tender or pre-tender stage for benign floaters were 14% higher than 12 months ago. We continue to see new opportunities coming to market, particularly offshore Brazil. Building on last year's Eight-rig tender, Petrobras has been actively seeking rigs for its BMS-11 and Buzios fields and recently launched a new tender for up to Four floaters on long-term contracts commencing in 2024.

This is in keeping with reports that Brazil is seeking to double production by 2030. With offshore resources that can deliver production at attractive economics, we anticipate that Brazil will be a significant driver of offshore demand over the next several years. We continue to see a mix of short-term exploration and longer-term development programs offshore West Africa, including in Namibia, which was estimated to have the world's largest offshore discovery in 2022. The potential for this market is highlighted by the fact that one major IOC recently announced that 50% of their 2023 exploration budget is allocated to Namibia alone. New discoveries, along with a pickup in activity in other parts of West Africa, could lead to increased rig demand for the floater market going forward.

We have a strong footprint in the region, were recently awarded a 330-day extension with Shell for drillship VALARIS DS-10, which will keep the rig working through March 2024 and is the final priced option under the rig's current contract. We're also in discussions to fill some of the available time in 2023 for VALARIS DS-12. We also see opportunities in the Gulf of Mexico, both on the U.S. and Mexican sides. On the jackup side of the business, the number of contracted jackups has increased by more than 15% from lows in early 2021 and are at their highest level since mid-2015. Most of this increase occurred over the past 12 months, primarily driven by demand from the Middle East.

As a result, active utilization for jackups is above 90%, and day rates continue to trend upwards, as demonstrated by our most recent contract awards at $125,000 per day or higher for work offshore Australia and Trinidad. The outlook for jackups continues to be constructive, with rig years of open demand at tender and pre-tender stage 20% higher at year-end as compared to 12 months ago. While the benign environment jackup market has improved meaningfully over the past 12 months, the timing and pace of a recovery in the harsh environment jackup market is uncertain.

As highlighted on our Q3 call, we do not expect opportunities to materialize in Norway until 2024. The outlook for the rest of the North Sea has softened as we are now also seeing more projects delayed in the UK, with customers citing the uncertainty created by changes to fiscal policy related to windfall taxes. Our three Keppel FELS N-Class rigs, which are capable of operating in Norway, are all now located in the UK, with only the VALARIS Norway partially contracted for the year ahead. The Stavanger is currently undergoing a Special Periodic Survey, and we are actively marketing both the Stavanger and the Norway for projects in the North Sea as well as further afield.

We do not see sufficient prospects over the next 12 to 18 months to keep all Three of these rigs working, and as a result, we are preservation stacking the VALARIS Viking in Dundee to reduce costs while the rig is idle. This uncertainty is expected to have a negative impact on our business in 2023, particularly in the first half. Based on customer discussions, we expect the market outside of Norway to begin improving in the second half of the year. Although most of the opportunities we see at present are short-term in nature. Moreover, given the role that hydrocarbons should play in ensuring European countries' energy security, we expect that demand offshore Norway, the U.K., and other sectors of the North Sea will improve in 2024 and create a more balanced, harsh environment jackup market in future years.

Against this backdrop of a broadly constructive market environment and renewed optimism within our sector, I'd like to spend a few moments discussing our fleet strategy as we navigate the unfolding industry upcycle. We continue to employ a disciplined fleet management strategy with a focus on driving long-term shareholder value. Our priority is to ensure that the acti fleet remains highly utilized, while having a large fleet means that we can pursue a portfolio approach to contracting with a mix of longer and shorter duration contracts, ideally with staggered rollovers. We also continue to regularly assess our fleet for retirement and divestiture candidates. As part of our fleet strategy, we aim to have a critical mass of rigs in priority basins to benefit from economies of scale. Following the reactivation of Valaris DS-17, we will have three floaters operating at each point of the Golden Triangle.

Our other Two drillships in Brazil, VALARIS DS-4 and DS-15, are both expected to finish their current contracts in mid-2024, leaving them well-positioned to roll onto higher day rate contracts in a region where we expect to see continued growth. We have proven our ability to win work for and reactivate our preservation-stacked assets, and we see attractive opportunities to commence reactivation of additional drillships in 2023. We will remain disciplined in exercising our operational leverage by only returning additional stacked rigs to the active fleet for opportunities that provide meaningful returns over the initial contract. Given the opportunities we see in the market today, we believe that investing in our fleet by reactivating our high-specification stacked drillships is an attractive use of our available cash, as we expect that these investments would generate significant returns for our shareholders.

In addition to our stacked fleet, we have options to take delivery of new-build drillships VALARIS DS-13 and VALARIS DS-14 by year-end 2023 for a shipyard price of approximately $119 million and $218 million respectively. VALARIS DS-13 is attractively priced compared to recent market transactions for similar assets, while VALARIS DS-14 is in line with recent transactions. Both drillships are amongst the highest specification assets in the global fleet and have two BOPs, which remains a preference for customers globally. We will continue to evaluate our options regarding these rigs as we see the market evolve over the course of the year. The pool of available supply is shrinking as stacked rigs are absorbed into the active fleet when supported by demand.

Following the recent announcement by a competitor to utilize one of their stacked drillships for non-drilling activities, we count only 14 competitive drillships remaining on the sidelines, 13 of which are owned by Valaris and Two other major drilling contractors. We believe that our demonstrated track record of successfully reactivating rigs leaves Valaris well-positioned to benefit when the right opportunities present themselves. There are a further Eight new-build drillships remaining at South Korean shipyards, including VALARIS DS-13 and DS-14. We expect these rigs to come to market in a staged manner when demand supports incremental supply, and likely only if these rigs are in the hands of established international drilling contractors. Importantly, we currently believe that it is unlikely that we will see another floater new-build cycle given high build costs, long lead times, and limited shipyard availability.

Therefore, we anticipate that the current rig fleet will form the basis of supply for the foreseeable future. A large portion of demand growth in the jackup market over the past 12 months has been driven by the Middle East, particularly Saudi Arabia. Valaris has significant exposure to this market through ARO Drilling, our unconsolidated 50/50 joint venture with Saudi Aramco. Arrow was recently awarded multi-year contracts with Aramco for VALARIS 76 and VALARIS 108, which will be leased to Arrow following completion of their existing contracts. 2023 is expected to be an important year in the growth of Arrow, with Two new-build rigs due to be delivered. As a reminder, each of the new builds will be backed by an initial 8-year contract with Saudi Aramco at a day rate set to achieve a Six-year EBITDA payback on the total price of the rig.

Following the initial contract, each new build will be contracted for at least Eight more years in aggregate, with pricing set every Three years utilizing a market pricing mechanism. We see significant appetite in the local market for financing the new builds, and we expect funding to be secured prior to delivery. Importantly, we do not expect that Valaris or Aramco will need to provide any additional financing to Arrow to fund the new build program. Furthermore, there is significant investor interest in the Middle East for drilling businesses. Last year, a local driller with both onshore and offshore rigs successfully completed its IPO, raising more than $700 million in a substantially oversubscribed offering at an attractive valuation. We remain focused on highlighting what we believe is the significant value inherent in Arrow, and recent asset transactions and IPOs in the region help to support this view.

I will conclude by reiterating some of the key points from our prepared remarks. First, we continue to deliver excellent operational performance, as demonstrated by achieving 98% revenue efficiency in the Q4 and 97% for 2022. Second, the fundamental outlook for our industry remains highly constructive, with offshore exploration and production spending expected to increase over the next several years, which is anticipated to drive increased demand for our services. Third, we will continue to exercise our operational leverage in a disciplined manner by returning our high-quality stack rigs to the active fleet for opportunities that will generate meaningful returns. We see attractive opportunities to commence reactivation of additional drillships in 2023, including one for which we are in advanced discussions.

In summary, we will continue executing our focused, value-driven, and responsible strategy. We believe that our strategy will drive meaningful earnings and free cash flow during the unfolding industry upcycle. I'll now hand the call over to Chris to take you through the financials.

Chris Weber (SVP and CFO)

Thanks, Anton. Good morning and afternoon, everyone. In my prepared remarks today, I will provide an overview of Q4 results as well as guidance for the Q1 and full year 2023. In addition, I will briefly review our financial position and capital structure. I will also highlight our Q4 results press release, which includes our trailing Q5 results as well as various supplemental data in our latest fleet status report that we published this morning. Moving now to the Q4 results. Adjusted EBITDA was $54 million compared to $76 million in the prior quarter, and adjusted EBITDAR, adding back one-time reactivation costs, was $75 million compared to $94 million in the prior quarter. Revenues were $434 million compared to $437 million in the prior quarter.

Excluding reimbursable items, revenues decreased to $413 million from $416 million, primarily due to lower utilization and lower average day rates for the harsh environment jackup fleet, but partially offset by an increase in utilization for the floater fleet. Jackup revenues decreased primarily due to Valaris Stavanger completing its contract offshore Norway and idle time between contracts for Valaris 123, 144, and 115. This was partially offset by more operating days for Valaris 118 and 92 following a contract startup in a Special Periodic Survey, respectively. Floater revenues increased primarily due to higher revenue efficiency across the floater fleet and a full quarter of revenues for Valaris DS4 and DS9, which commenced contracts early in the Q3 .

Contract drilling expense was $353 million compared to $337 million in the prior quarter. Excluding reimbursable items, contract drilling expense increased to $333 million from $316 million, primarily due to an increase in operating days for the floater fleet, which have a higher per-day operating cost, as well as higher reactivation costs, which increased to $21 million from $18 million. Moving to our shore-based costs, G&A expense increased to $24 million from $19 million in the prior quarter, primarily due to higher personnel costs and professional fees. Onshore support costs, which are included within contract drilling expense in the income statement, increased to $33 million from $30 million, primarily due to higher personnel costs.

The sum of these two items provides our total onshore support costs, which increased to $57 million from $49 million in the prior quarter. Depreciation expense increased marginally to $24 million from $23 million in the prior quarter. Other expense was less than $1 million compared to other income of $30 million in the Q3 of 2022. Other expense in the Q4 included foreign currency exchange losses, primarily related to revaluation of balance sheet accounts of $13 million as it compared to gains of $10 million in the Q3 . Q3 other income also included non-cash interest income of $15 million related to the write-off of the discount attributable to the $40 million of shareholder notes receivable repaid by ARO.

These odd items were partially offset by higher cash interest income and a small gain on sale associated with the rig sold in a prior year. Tax expense was $10 million compared to $14 million in the prior quarter. Adjusted for discrete items, tax expense increased to $13 million from $12 million. Moving now to our Q1 2023 outlook. We expect total revenues will be in the range of $410 million-$420 million as it compared to $434 million in the Q4 . Revenues are expected to decrease primarily due to lower activity for harsh environment jackups in the North Sea and planned out of service days for floaters completing contract specific requirements and BOP recertification. Regarding the North Sea, we expect five rigs to be idle for at least part of the Q1.

The VALARIS Stavanger and VALARIS Viking have both been moved to the U.K. from Norway following completion of contracts in November and January, respectively. The VALARIS Stavanger is currently undergoing a Special Periodic Survey in Dundee and is actively being marketed for work. Given the uncertain near-term outlook in Norway and the rest of the North Sea, our expectation is that the VALARIS Viking will be idle for at least 12 months, and therefore we are preservation stacking the rig in Dundee to reduce costs while the rig is idle. In addition, the VALARIS Norway was idle for the first half of the quarter before it recently started its contract with Centrica. VALARIS 121 and VALARIS 247 are undergoing Special Periodic Survey work during the Q1 in advance of their next contracts.

We anticipate that contract drilling expense will be in the range of $380 million to $390 million as compared to $353 million in the Q4. The increase is primarily driven by Three items. First, higher repair and maintenance costs, as we expect to have Four jackups undergoing Special Periodic Survey projects in the Q1. As a point of comparison, we effectively had just One jackup undergo a Special Periodic Survey during the Q4. Second, higher offshore compensation costs driven by wage adjustments that were implemented earlier this year. Third, higher reactivation costs, primarily due to the continued reactivation efforts on VALARIS DS-17 in advance of its contract commencement later this year. Reactivation costs in the Q1 are expected to be approximately $25 million versus $21 million in the Q4.

General and administrative expense is expected to increase to $25 million-$27 million from $24 million in the prior quarter, primarily due to higher professional fees and higher compensation costs. Adjusted EBITDA is expected to range from break even to positive $5 million compared to $54 million in the Q4, and adjusted EBITDAR is expected to be $25 million-$30 million compared to $75 million in the Q4. I will now provide preliminary financial guidance for full year 2023. Consistent with our past practice, this guidance does not account for any incremental reactivations for contracts that have yet to be executed. It does not assume any additional contracted reactivations other than the completion of the DS-17 project.

Based on reactivation lead times of approximately 12 months for floaters, if we were to reactivate additional drill ships in 2023, it would have a negative impact on EBITDA and CapEx, but would increase expected earnings and cash flow in future years. 2023 revenues are expected to be $1.8 billion-$1.9 billion, up from $1.6 billion in 2022. We anticipate that revenues will increase primarily due to higher average day rates. VALARIS DS-17 commencing its contract later this year following its reactivation and the full year impact of Four floaters that were reactivated during 2022. This is partially offset by lower utilization for harsh environment jackups in the North Sea.

Contract drilling expense is anticipated to be $1.43 billion-$1.53 billion as compared to $1.38 billion in 2022. This year-on-year increase is primarily due to more operating days for the floater fleet resulting from a full year impact of 2022 reactivations and a partial year of VALARIS DS-17 operations following the expected completion of this reactivation project mid-year. Higher compensation costs for offshore crews and associated support personnel and higher planned repair and maintenance costs driven by Six Special Periodic Survey projects for jackups. This is Two times the number of projects completed in 2022. Of the Six projects planned in 2023, Five are scheduled to occur in the first half of the year, with four occurring in the Q1 and One in the Q2.

The projects are front-loaded in the year in order to take advantage of idle time between contracts and due to class requirements, they will have an outsized cost impact on the first half of year financial results, especially the Q1. These increased costs versus the prior year are partially offset by lower reactivation spend resulting from fewer rigs returning to the active fleet in 2023 compared to last year. Moving to G&A expense, we expect $105 million-$110 million of cost for the year, up from $81 million in 2022. This increase is mainly due to the company transitioning into a more normal level of G&A cost as we build out corporate infrastructure following our relisting in May 2021.

In 2023, we will have a full year of a complete executive management team and an additional year of long-term incentive plan awards that are granted annually. Since these awards vest over Three years, this component of compensation cost is expected to reach full run rate in the second half of 2023. In addition, G&A will be impacted by a full year of our new sustainability and new energy function, higher compensation costs as we have reinstated some employee benefits that were eliminated in the last downturn, and higher professional fees. When combined with $135 million-$140 million of support costs included within contract drilling expense, this provides total onshore support costs of $240 million-$250 million.

The sum of these items provides adjusted EBITDA of $240 million-$280 million and adjusted EBITDAR, which adds back one-time reactivation costs of $280 million-$320 million. We expect Q1 EBITDA will be the low point for the year and for EBITDA to increase sequentially each quarter thereafter, with approximately 80% of 2023 EBITDA generated in the second half of the year. Q2 EBITDA should improve relative to the Q1 as jackup rigs begin returning to work following their surveys or other idle periods. Floater utilization improves due to lower out-of-service days. Reactivation expense moves lower as the DS 17 project nears completion.

In the second half of the year, we expect EBITDA to move materially higher as the VALARIS DS-17 starts its contract with Equinor in Brazil, rigs complete legacy contracts and roll to higher day rates. Utilization for our North Sea jackups improves, we execute just one Special Periodic Survey project versus five in the first half of the year. Moving now to capital expenditures. Q4 CapEx of $53 million was in line with the prior quarter. Q4 CapEx included $20 million for maintenance CapEx and $33 million for enhancements and upgrades, primarily for reactivations, contract-specific upgrades on reactivated rigs, and steel replacement for the VALARIS 92. Full year 2023 capital expenditures are anticipated to be $260 million-$300 million compared to $207 million in 2022.

Maintenance CapEx is expected to be $120 million-$130 million versus $69 million in 2022. This increase is primarily due to an increase in the number of BOP recertifications and overhaul costs for drilling and well control equipment due to more floaters working during the year, plus an increase in the number of jackup Special Periodic Surveys that I mentioned earlier. We are also restocking capital spares following several floater reactivations that have depleted our levels of long lead equipment. Enhancement and upgrade spend is expected to be approximately $140 million-$170 million, including approximately $80 million-$90 million of reactivation and associated contract-specific CapEx, primarily related to Valaris DS-17.

The remaining enhancement and upgrade costs in 2023 are largely related to life enhancement work for Valaris 72 before continuing its contract with Eni, well control and drilling equipment upgrades on Valaris 76 ahead of its Five-year bareboat charter with ARO, and the purchase of an MPD kit. We expect to receive customer reimbursements for capital expenditures of approximately $27 million in 2023 related to customer-specific upgrades on Valaris DS-17. This represents the second customer reimbursement for capital expenditures on this project, as we previously received $27 million at the end of last year. This CapEx guidance does not include any assumed expenditures for exercising our options to purchase drillships Valaris DS-13 and DS-14.

As a reminder, we have the option to purchase these rigs for $119 million and $218 million respectively through the end of 2023. Given recent drillship contract economics and comparable asset transactions, DS-13 is a very attractive option and DS-14 is priced in line with recent transactions for comparable assets. Q1 CapEx is expected to be $65 million-$75 million, comprised of $25 million-$30 million for maintenance CapEx and $40 million-$45 million for enhancements and upgrades, including $25 million-$30 million of reactivation and associated contract-specific CapEx, primarily related to Valaris DS-17.

The remaining spend on enhancements and upgrades is primarily related to contract preparation costs for VALARIS 115 in advance of the rig commencing a multi-year contract with Shell and Brunei, as well as the Valaris 72 life enhancement work. I'll move to the Q4 results, as well as the Q1 and full year 2023 outlook for ARO Drilling, our 50/50 joint venture with Saudi Aramco. As a reminder, ARO is not consolidated in the financial results of Valaris. ARO EBITDA increased to $29 million from $17 million in the prior quarter, primarily due to higher utilization as certain rigs returned to work following out-of-service days for planned maintenance.

ARO's Q1 EBITDA is expected to decrease to $21 million-$23 million from $29 million in the Q4 , largely due to higher planned maintenance costs and higher expected bareboat charter expense in the Q1. ARO's full year 2023 EBITDA is expected to be approximately $110 million-$120 million as compared to $99 million in 2022. The expected EBITDA increase is largely due to the startup of newbuild rigs one and two, which are expected to be delivered this year. As Anton mentioned earlier, we expect both rigs to receive financing prior to their delivery, and we do not expect to provide additional financing to ARO to fund the newbuild program. I'll now provide a brief overview of our financial position and capital structure.

At the end of the Q4, we had cash and cash equivalents of $724 million plus restricted cash of $24 million. Our total liquidity increased by $104 million during the quarter, primarily due to positive cash flow from operations of $155 million, partially offset by CapEx of $59 million. Included in cash flow from operations was a $55 million refund payment from the IRS related to the CARES Act. In January, we received an additional $45 million payment related to the CARES Act, and we still have a further $19 million outstanding. However, the timing of this receipt is uncertain.

On a full year 2022 basis, our total liquidity also increased by $104 million, primarily due to positive cash flow from operations of $128 million, which included the $55 million CARES Act refund I just mentioned, net asset sale proceeds of $150 million, primarily from the sale of Jacobs Valaris 113 and 114, and the $40 million of shareholder note receivable repaid by ARO. Partially offsetting these positive cash inflows was $207 million of CapEx, which included $117 million of reactivation and associated contract-specific CapEx. Looking to 2023, we expect to be cash flow positive, assuming no further reactivations and no spend on the DS-13 or DS-14 new build options.

Regarding our capital structure, we have only one tranche of debt, our $550 million senior secured notes due in 2028 that has a first call in April 2023. As a reminder, the cash in our balance sheet is our only source of liquidity as we do not currently have a revolving credit facility. Ideally, we would like to implement a new capital structure that includes a revolver and a more regular way high yield note. Putting in place a revolver with retractive terms would improve the cost and efficiency of our capital structure, while the extra liquidity would allow us to hold less cash on the balance sheet over time and give us more flexibility when making capital allocation decisions.

However, in contrast to many of our offshore drilling peers, we are in the fortunate position of not having to do something. We plan to be opportunistic and only execute a revolver and a refinancing of our existing note if the size, pricing, and terms are attractive and do not significantly impact our operational and strategic flexibility in both strong and weak market environments. Now I'll hand it over to Anton, who will make a few closing remarks.

Anton Dibowitz (President and CEO)

Thanks, Chris. I want to wrap up the call with a few comments on capital allocation priorities, including shareholder returns. We have ongoing discussions regarding capital allocation as a management team and with our board. We are all aligned on the priorities for our cash. The first of these priorities being to execute the operational leverage in our business in a disciplined manner in order to create long-term shareholder value. We have Three stack drillships and purchase options for Two newbuild drillships. We are currently actively pursuing contracting opportunities for these rigs. With drillship day rates in the $400,000 per day range, we are able to generate meaningful returns on the reactivation investment over just the initial contracts, and we are able to generate significant earnings and cash flow. We are constructive on the market.

We cannot predict with precision the timing or terms of new contracts. We could have several reactivation projects in one year, or they could be spread over a longer period of time. We may enter into contracts where a material portion of upgrades and reactivation costs are reimbursed up front, or contracts where a more significant portion of the upgrades and reactivation costs are recouped in the day rate over the initial term, but which are nonetheless attractive opportunities. These variables lead us to be somewhat conservative from a cash planning and capital allocation perspective today, because most importantly, we want to be able to execute on all attractive contract opportunities. The second priority for our cash is pursuing strategic growth opportunities. The offshore drilling industry has benefited from the efficiencies enabled by prior combinations, and Valaris has been a major driver of those efforts.

There are opportunities for additional consolidation, whether it is at the corporate or asset level, and we want to help drive it further as long as the transaction is value enhancing and accretive to our shareholders. We believe having cash available to fund all or a portion of a transaction depending on its size is valuable. Our priority for any excess cash is returning it to shareholders. With a positive long-term market outlook ahead of us, we are focused on transitioning Valaris into a consistent cash generating and yielding investment for our shareholders. While our first priority is putting our stack rigs to work for attractive returns, there may still be catalysts for opportunistic return of capital, like value accretive rig sales or a significant dislocation in our stock price.

Looking forward, we expect 2024 to represent an inflection point in our results as legacy drillship contracts roll to market rates.

We get a full year benefit of the DS-17 contract and the expected recovery in the North Sea takes hold. Rig reactivations, depending on their timing, could further improve our results in 2024 or beyond. We expect that as we complete reactivations and the active fleet has rolled to market rates, we will generate meaningful free cash flow, providing the ability for us to shift from an opportunistic to a consistent and structured return of capital program. In conclusion, I remain excited about the outlook for Valaris. We will continue executing our strategy of being focused, value-driven and responsible, and believe that our strategy will drive increased earnings and meaningful free cash flow during the unfolding industry upcycle. We've now reached the end of our prepared remarks. Operator, please open the line for questions.

Operator (participant)

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. Today's first question comes from Greg Lewis with BTIG. Please go ahead.

Gregory Lewis (Managing Director and Energy and Infrastructure Analyst)

Yeah, thank you and good afternoon and good morning, everybody. Anton, yeah, thanks a lot for the prepared remarks, super helpful, but I was hoping to get just a little bit more color around the rig reactivations and the new builds and your comments around capital allocation. You know, I guess I'll just ask a few questions at once. As we think about the ability to reactivate rigs, you know, realizing that there's a lot of customer demand, as we think about recertifications and supply chain and crewing, is that more of the hindrance and realizing that if, you know, the market looks pretty firm and there could be opportunities to reactivate and take delivery of the new builds in a compressed window, is that really... Is that possible given all of the things I just mentioned?

Anton Dibowitz (President and CEO)

Good question. Absolutely, Greg. Look, what I will say is one of the true, you know, prowess of this organization is the ability to effectively reactivate rigs. There's a demonstrated track record. We reactivated Four rigs last year, and as importantly as bringing those rigs to market largely, you know, on time and on budget, on average, is the fact that as an organization, we delivered 97% revenue efficiency over the year. It's as important to execute the reactivation project as it is to have those rigs operate at the same level as the rest of the active fleet when they get back to work. We have extended the duration that we expect the new reactivation. On the 17, for example, you know, that project is One year versus Nine months before.

This is an organization that has great control of executing operational delivery. For us, it's more, you know, if I go back to the strategy of being, you know, focused and disciplined, it's about finding the right opportunities as the constructive market continues and those incremental demand comes to market, to find the right opportunity to bring those rigs back in a measured pace. We see that those opportunities are there. I think we had made some comments about being in advanced discussions for at least one more drillship to go back. I'm optimistic about 2023 in general, that where there will be additional opportunities. I wouldn't say there's a constraint because of the project.

I think it's more about being focused and disciplined and finding the right timing and the right opportunities to bring those rigs back.

Gregory Lewis (Managing Director and Energy and Infrastructure Analyst)

Okay, great. Super helpful. You know, realizing that the focus has been on, you know, the focus of that conversation is around the floaters, and realizing, understanding that, you know, one of the N-Class rigs is being idled. You know, as I guess we look around other basins like West Africa and, you know, let's say the Golden Triangle area and even in Asia, we still do have some stacked jackups. You know, as we think about, you know, as we think about the next 12 or 18 months, do you see a scenario where we could see some of those rigs go back to work or at least in the near term, the focus really is on just bringing floaters that are on the sidelines back into the working fleet?

Anton Dibowitz (President and CEO)

No, there's certainly been an improvement in a more constructive, you know, benign jackup market driven largely by what's happened in the Middle East with, you know, a lot of rigs being relocated to Saudi in particular. There are opportunities for jackups, but again, for us it's about the capital allocation decision and if you call it the investment return we get on those reactivation economics. Today, given the fact that, you know, floater day rates, if you look at drill ships have in essence, you know, doubled from $200s-$400s over the last couple of years. Jackups have improved kind of from the $70s north of $100. You know, we've executed some contracts in certain markets above $125.

On the absolute, you know, looking at it on a capital allocation basis, the economics of allocating capital to a reactivation of a drill ship is superior to that of doing a jackup today. That's not to say that those opportunities aren't there, and we continue to look for attractive opportunities for our jackups, and if we find one, we'll absolutely execute on those.

Gregory Lewis (Managing Director and Energy and Infrastructure Analyst)

Okay, great.

Anton Dibowitz (President and CEO)

It's just a question of priority and where we get the best returns.

Gregory Lewis (Managing Director and Energy and Infrastructure Analyst)

Okay, understood. Thank you for the time, and have a great day.

Anton Dibowitz (President and CEO)

Thanks. Appreciate the questions.

Operator (participant)

Our next question today comes from David Smith at Pickering Energy Partners. Please go ahead.

David Smith (Director)

Hey, good morning, thank you for taking my questions.

Anton Dibowitz (President and CEO)

Morning.

David Smith (Director)

In your prepared remarks, Anton, you mentioned that there may be catalysts for opportunistic returns of capital. You mentioned rig sales as a potential catalyst. Would you consider the CARES Act refunds to be a catalyst for opportunistic returns?

Anton Dibowitz (President and CEO)

Yeah. Let me let Chris start and just kinda update everybody on where we are on our CARES Act refunds, and then I'll come back and cover your question after.

Chris Weber (SVP and CFO)

Yeah. From a, you know, from a CARES Act refund perspective, we got the $55 million in the Q4, we got $45 million in January, We've got $19 million remaining. You know, as we think about, you know, these CARES Act refunds, these aren't surprises to us. These obviously been. We've been waiting for a long time for them. They've been in our planning models. We don't necessarily consider them, you know, a catalyst or found money from that perspective.

Anton Dibowitz (President and CEO)

Yeah. Dave, I'll reiterate kind of some of my prepared remarks. I mean, we have, you know, ongoing discussions, you know, in the management team and with our board about capital allocation. Our focus, again, is following the strategy of being focused and disciplined and investing capital to create long-term shareholder value. For us today, you know, including that CARES Act refund, it's about allocating capital to attractive economics on reactivations, particularly of our drillships. There is some opportunity for M&A and we want to have, you know, cash available if those attractive opportunities, you know, are available. Our priority is to return any excess cash to shareholders.

Today that means today that means being opportunistic, you know, in the case of dislocation in stock price or if we do have some opportunistic rig sales. That's largely driven by the fact that our first priority being return of drillships to the market for attractive economics, I can't tell you exactly what those contracts are gonna look like. You know, you could saw it in the, you know, high class scenario. We have multiple reactivations of our remaining drillships all going on this year, right? Heading to that, you know, increasing that inflection point in 2024 where we're generating, you know, even more significant cash and return and can get to a structural return, you know, scenario of returning cash.

If the market has, as it develops this year, it becomes, you know, a little more spread out and those reactivations are over a greater period of time and/or, you know, we have to enter into contracts where we're recovering those reactivation economics over the term of the contract, but it's still a great attractive opportunity. We need a couple of those pieces to fall in place for us to, you know, to get to that place of structural return. The CARES Act kinda just goes into our basic numbers, and we'll see how the rest of the year as some of these pieces fall in place.

David Smith (Director)

Very much appreciated. If I can ask a quick follow-up.

Anton Dibowitz (President and CEO)

Sure.

David Smith (Director)

Chris, going back to your comments, you know, about the interest in a new capital structure, you know, a revolver and high yield notes. Wanted to kinda gauge your optimism and outlook for, you know? Is that something achievable, you know, this year? Or what do you need to see kinda happen before you would hope to get that in place?

Chris Weber (SVP and CFO)

I mean, you know, we've been pretty vocal for a while talking about our desire to get a regular way capital structure in place, which includes a revolver. Obviously to do that, we need to refinance the note, given the terms of the note. That's been on the table for a long time. We'd like to be able to execute that this year. You know, think that there could be opportunities to do that. We are talking to our banks about that. You know, I think it's really important for us is that we don't have to do that. If we, you know, we don't like the terms, the size, or the pricing that we see, you know, we don't have to do it.

It's, for us, this is opportunistic. If we can, you know, find something that allows us to do that, we wanna be able to execute on that. Again, needs to be on, you know, size, pricing terms that make sense for us and doesn't, you know, overly restrict us from an operational or strategic perspective.

David Smith (Director)

Appreciate it. That's it for me.

Anton Dibowitz (President and CEO)

Thank you. Our next question today comes from Fredrik Stene with Clarksons Securities. Please go ahead.

Fredrik Stene (VP of Equity and Credit Research)

Hi, Anton Dibowitz and team, thanks for the comprehensive remarks today. Super helpful. I think a few of my questions have been answered already, but I wanted to pivot a bit into ARO and your plans there. You mentioned financing of the Two new builds with the local money, if not ample, at least available. Then you talked about the different IPOs that have been done in the Middle East for these local drillers. I think right now, you know, ARO, it's a growth story. For some time maybe the market has kind of neglected a bit what could happen there. I was wondering if you envision going the route of an IPO with that asset.

Do you have any timeline in mind? Do you have any kind of events that would need to happen before you do something like that? If you do some sort of IPO or strategic divestment on that side, what do you think will happen with the rigs that you leave into ARO? Would that likely that those will be part of such a transaction, or do you think you'll continue to lead them into that if you're kind of fully letting it go. Any thoughts that you can spare would be super helpful.

Anton Dibowitz (President and CEO)

Absolutely, Fredrik. It's a great question because I think the value of ARO as a strategic asset to Valaris is somewhat underappreciated by many people because we don't consolidate it. What I will say, you know, at a high-end macro level, this is a 50/50 joint venture with the biggest user of nine jackups in the world in a market where, you know, some could say colloquially, the last well in the world will be drilled. You know, 15 rigs operating today. You know, we recently announced two contracts of rigs that would transition, plus two newbuilds this year. This will be 19 rigs operating once that process happens. I think there are some...

I'm not gonna get into details of, you know, what the thinking is at ARO Drilling, but I think there are some natural kind of timing points where it may make sense to look at more strategic options for ARO Drilling as far as, you know, value realization. That is, you know, particularly the Two new builds. The new build story with 20 rigs being built, you know, in ARO Drilling and the last 18 in Kingdom is an important part of ARO Drilling's growth story. With those first 2 rigs being delivered this year, getting on contract, demonstrating that contract model with the first contract 8 years with 6-year EBITDA payback, and along with that, committing to, you know, the additional rigs in the new build cycle is an important milestone for ARO Drilling and the venture.

I think, you know, you know, although we continue to have discussions at the, at the board level and in ARO, that would be a natural point for us to start looking at what's next. I don't wanna, don't wanna comment, you know, more than that.

Fredrik Stene (VP of Equity and Credit Research)

That's very helpful. Thank you so much. That's it from me. Thanks.

Anton Dibowitz (President and CEO)

Thanks, Fredrik.

Operator (participant)

Our next question today comes from Eddie Kim at Barclays. Please go ahead.

Eddie Kim (Analyst)

Hi, good morning. It's just regarding the cold stacked asset you're in advanced discussions on reactivating, you noted this was for a program expected to commence within the next 12 months. We've heard from NOV that it would take around that long to complete a reactivation, and I believe you also mentioned 12-month lead times in your prepared remarks. Just curious about your confidence level in being able to reactivate that rig in time for this contract's commencement date. Separately, what would be your estimate of the reactivation cost for this particular cold stacked drillship?

Anton Dibowitz (President and CEO)

Yeah. You know, I think I answered in one of the earlier questions, Eddie. You know, one thing this organization has a demonstrated track record of with 4 in the last year and the 17 project going on, which is, you know, on pace and largely on budget, is the ability to reactivate rigs on the timing and on the budgetary, you know, numbers that we say we're going to do it. We are in advanced discussions, and I'm confident in the team that they can execute that project and have that rig reactivated in the timeframe that we need it to be and as expected by the customer.

As far as the budgetary estimate, you know, we, you know, we're in a discussion and, you know, I'm very optimistic and constructive on us, closing out that contract here in the near future. When we do, we will, you know, update the market, including, you know, the adjustments to our numbers as a result of adding in that additional reactivation. You know, we said $65 million-$75 million for the VALARIS DS-17. I think you can be looking at numbers towards the, you know, the top end of that range if we're looking at, you know, additional reactivations today. We will certainly update the market as, as we go through that process.

Eddie Kim (Analyst)

Got it. Understood. We'll be looking forward to learning more about that. Anton, secondly, you mentioned eight newbuild drillships currently stranded in Korean shipyards and that you expect these rigs to come to market in a staged manner. What headline day rate do you think would be required to bring one of those drillships out? Is it $500 or $550? Or would you argue we're even close to it now in the mid $400s, you know, depending on the contract structure? What, and when might you expect us to see an announcement about one of those rigs coming into the supply stack?

Anton Dibowitz (President and CEO)

Look, there are quite a few discussions going on. You know, the market and incremental demand that keeps, you know, coming to market is making it more realistic for those rigs. What I will say, you know, I expect them largely to come to market in the hands in some way, shape, or form of kind of established prudent drillers. When you look, I don't wanna get into, you know, to day rate speculation on what others may do, but I will say, you know, with market clearing prices to take out, you know, we have two options, one at $119, the other at $218 million. You know, the clearing price on those rigs is, you know, north of $200 million today.

You need to think that on top of that, you would have another reactivation type expense, you know, plus immobilization. Call it another maybe, you know, $80 million-$100 million all in in order to do that project, that there needs to be a, you know, kind of a robust day rate, both in contract term and day rate in order to justify those economics. I'd say it would be, you know, at the, at the rate levels we're seeing today or north of those rate levels. I think the most folks priority and definitely ours is to take priority to our active fleet to make sure that that is highly utilized, you know, for us, you know.

Secondly, to look at our reactive, you know, our cold stacked, preservation stacked ships and return those. Then to look at, you know, kind of, you know, new build options after that. I think most folks in the market see it the same way.

Matt Lyne (SVP and Chief Commercial Officer)

Great. Thanks, Anton. I'll turn it back.

Anton Dibowitz (President and CEO)

Thanks.

Operator (participant)

Our next question today comes from Kurt Hallead with Benchmark. Please go ahead.

Kurt Hallead (Analyst)

Hi. Good morning, everybody.

Anton Dibowitz (President and CEO)

Morning.

Matt Lyne (SVP and Chief Commercial Officer)

Morning.

Kurt Hallead (Analyst)

I appreciate the in-depth color. Kind of curious here, right? As you look at the market tightness for the drill ships, you mentioned that there were 14, you know, idle assets with 13 of those with Three companies. Obviously, Five of those being yours. Or at least Three of those being yours, excuse me, not including the potential drill ships. When, when you think about, you know, your balance sheet, when you think about protecting your cash, when you think about the demand factor for, you know, these rigs being activated, you mentioned some upfront costs being borne by the customer base, order of magnitude of $27 million. Seems like a very low percentage given still the capital risk and the balance sheet strength that your customers have.

Long-winded way of getting around to my question, which is, how are the discussions going with your customer base about them putting up more capital up front to bring these assets into the market? Because at the end of the day, again, they're in limited hands. There's not so much competition out there as there had been. And you guys just should be preserving capital and making the customer base pay for it. Just kind of curious on how those discussions are evolving, if they've evolved, and if you have some greater leverage going forward?

Anton Dibowitz (President and CEO)

No, I mean, you can see what we did on the VALARIS DS-17 contract, but they're not all customers are the same, right? There's a great variety in customer and appetite and ability. Ultimately, there's a trade-off in one way, shape, or form. There's a market clearing price that a rig can be recontracted at. There are certainly some customers that we have discussions with who are more apt or, you know, to pay more capital upfront towards the reactivation, you know, in some manner that can be offset by the day rates that you're going to get under the contract.

There are other contracts on, you know, point more to kinda national oil companies, let's say, you know, where they have a very prescribed upfront, you know, mobilization or upfront payment mechanism because it's a very regimented contract structure. Then, you know, our job is to make sure that we look at the economics and the ability to recoup those reactivation economics over the term of the contract.

What I will say is the contracts that are available in the market, you know, whatever flavor they are, whether it's recouping more of that, those economics over the term of the contract, you know, with day rates north of, you know, kind of $400,000 a day and, you know, and contract tenors in the three-year range, it's an attractive opportunity that generates cash, you know, under the initial contract, whichever form of contract that you're looking at. For us, when we do your question about, you know, balance sheet and cash management, it's about, you know, understanding how those contracts will stack up as we recontract those rigs. What is the, you know, the timing of our liquidity and cash needs.

You know, we've been very clear in being focused and disciplined and for us, discipline means, you know, not taking on contracts where we are not generating return over the initial contract. That is what is most important to us.

Kurt Hallead (Analyst)

That's great. Appreciate that. My follow-up is on the North Sea market. You mentioned you expect, you know, improvement, you know, next year. Is that kind of your team's kind of, you know, forecast or perspective or is that coming from your customer base that's basically saying '2023 is gonna be what it is, but, you know, 2024, we'll be in a much better position, we plan to move forward on projects'? Just wondering if it's customer driven or just kind of more your? Neither answer is wrong. I'm just trying to gauge whether it's coming from the customer or coming from your internal team.

Anton Dibowitz (President and CEO)

Yeah. Let me let Matt start off with that question 'cause he's having a lot of the customer discussions. Maybe I'll cover up afterwards to give you some more color on the, on the North Sea.

Matt Lyne (SVP and Chief Commercial Officer)

Hi there.

Kurt Hallead (Analyst)

Hi.

Matt Lyne (SVP and Chief Commercial Officer)

Thanks, Anton. I think if we dial back the clock and you look at where we felt in 2022 regarding the 23 opportunities, we felt quite good about what the North Sea was bringing to the table on demand. There was obviously the fiscal change with respect to the windfall tax that added some headwinds to where operators had to take a pause to think about how they view going forward with projects. What I would highlight is that it's less about going forward and more about possibly delaying while they digest the new economics.

I think that's what we're starting to benefit from and what we see as visible demand in the second half of 2023 and into 2024, where a number of those projects that likely had short-term delays are now being stacked into the next 12-18 months and giving us a better outlook and a more positive outcome for that market. I would, to answer your question, it's largely driven by what we see demand coming from customer conversations on the ground in the North Sea.

Anton Dibowitz (President and CEO)

What we see is more a question of timing. These are not programs that have been taken off the table. It's a question of, you know, relooking at their capital allocation and the timing of them doing those projects. You know, the snowplow and stuff moving to the back end of 2023 and into 2024.

Kurt Hallead (Analyst)

Okay, that's great. Really appreciate that color. That's it for me.

Matt Lyne (SVP and Chief Commercial Officer)

Sure. Thanks.

Operator (participant)

Thank you. Ladies and gentlemen, this concludes today's question and answer session. I'd like to turn the conference back over to Darin Gibbins for any closing remarks.

Darin Gibbins (VP of Investor Relation)

Thanks, Rocco, and thank you to everyone on the call for your interest in Valaris. We look forward to speaking with you again when we report our Q1 2023 results. Have a great rest of your day.

Operator (participant)

Thank you. Today's conference has now concluded. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.