Valaris Ltd (VAL) FY 2024 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in conjunction with "Item 1A. Risk Factors" and our consolidated financial statements and the notes thereto in "Item 8. Financial Statements and Supplementary Data" of this report.
The discussion of our results of operations and liquidity in this section includes comparisons for the years ended December 31, 2024 and 2023. For a similar discussion, including comparisons for the years ended December 31, 2023 and 2022, see “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our annual report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 15, 2024.
INTRODUCTION
Our Business
We are a leading provider of offshore contract drilling services to the international oil and gas industry with operations in almost every major offshore market across six continents. We own the world's largest offshore drilling rig fleet, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet. As of February 20, 2025, we own 52 rigs, including 13 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 34 jackup rigs and a 50% equity interest in ARO, our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional nine rigs.
Our customers include many of the leading international and government-owned oil and gas companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies with global operations. The markets in which we operate include the Gulf of Mexico, South America, the North Sea, the Mediterranean, the Middle East, Africa and Asia Pacific.
We provide drilling services on a day rate contract basis. Under day rate contracts, we provide an integrated service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig. We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. Our customers bear substantially all of the costs of constructing the well and supporting drilling operations as well as the economic risk relative to the success of the well.
Our Industry
Operating results in the offshore contract drilling industry are highly cyclical and are directly related to the demand for and the available supply of drilling rigs. Low demand and excess supply can independently affect day rates and utilization of drilling rigs. Therefore, adverse changes in either of these factors can result in adverse changes in our industry. While the cost of moving a rig may cause the balance of supply and demand to vary somewhat between regions, significant variations between most regions are generally of a short-term nature due to rig mobility.
Demand for offshore drilling is impacted by fundamental supply and demand dynamics for crude oil. Since late 2022, Brent crude oil prices have been largely trading in a range between $70 and $90 per barrel, with OPEC+ members managing supply in an effort to keep the market in balance. Importantly, longer-dated Brent crude oil prices have remained stable, with the five-year forward price above $65 per barrel, a level at which nearly 90% of undeveloped offshore reserves are expected to be profitable. As a result, we believe the constructive oil price environment is supportive of continued investment in long-cycle offshore projects.
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Rig attrition in the industry over the last decade, particularly for floaters, has resulted in a smaller global fleet of rigs that is available to meet customer demands. While demand for offshore drilling services has declined modestly since early 2024, global demand for hydrocarbons continues to increase and offshore production, particularly deepwater, is expected to play an important role in providing secure, reliable and affordable energy to meet the world’s growing energy needs. Consequently, our outlook for the offshore drilling business is positive.
Inflationary pressures have continued, resulting in increased personnel costs as well as in the prices of goods and services required to operate our rigs or execute capital projects. We expect that our costs will continue to rise in the near term and although certain of our long-term contracts contain provisions for escalating costs, we cannot predict with certainty our ability to successfully claim recoveries of higher costs from our customers under these contractual stipulations.
Backlog
Our contract drilling backlog reflects commitments represented by signed drilling contracts and is calculated by multiplying the contracted operating day rate by the contract period. The contracted day rate excludes certain types of lump sum fees for rig mobilization, demobilization, contract preparation, as well as customer reimbursables and bonus opportunities. Our backlog excludes ARO's backlog but includes backlog from our rigs leased to ARO at the contractual lease rates, which are subject to adjustment under the terms of the shareholder agreement governing the joint venture (the "Shareholder Agreement").
The ARO backlog presented below is 100% of ARO's backlog and is inclusive of backlog on both ARO owned rigs and rigs leased from us. As an unconsolidated 50/50 joint venture, when ARO realizes revenue from its backlog, 50% of the earnings thereon would be reflected in our results in equity in earnings of ARO in our Consolidated Statements of Operations. The earnings from ARO backlog with respect to rigs leased from us will be net of, among other things, payments to us under bareboat charters for those rigs. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
The following table summarizes our and 100% of ARO's contract backlog of business as of February 18, 2025 and February 15, 2024 (in millions):
| February 18, 2025 | February 15, 2024 | |||||
|---|---|---|---|---|---|---|
| Floaters (1) | $ | 2,024.0 | $ | 2,531.7 | ||
| Jackups (2) | 1,313.0 | 1,167.4 | ||||
| Other (3) | 271.5 | 222.3 | ||||
| Total | $ | 3,608.5 | $ | 3,921.4 | ||
| ARO (4) | $ | 1,422.9 | $ | 2,138.1 |
(1)The decrease for Floaters is primarily due to revenues realized, partially offset by a multi-year contract award for VALARIS DS-17 offshore Brazil and two six-month contract extensions for VALARIS DS-9 offshore Angola, which resulted in incremental aggregate backlog of approximately $570.0 million.
(2)The increase for Jackups is primarily due to various contract awards and extensions executed for incremental aggregate backlog of approximately $690.0 million, including a three-year contract extension for VALARIS 118, which resulted in incremental aggregate backlog of approximately $168.0 million, and a multi-year contract award for VALARIS 144, which resulted in incremental aggregate backlog of approximately $144.0 million. These increases were partially offset by revenues realized.
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(3)Other includes the backlog for our managed rig services and the bareboat charter backlog for the jackup rigs leased to ARO in order for ARO to fulfill certain of its drilling contracts with Saudi Aramco. The increase in Other is primarily due to three-year contract extensions for our managed rigs, which resulted in incremental aggregate backlog of approximately $180.0 million, partially offset by revenues realized and a reduction of backlog of approximately an aggregate $35.0 million attributable to the VALARIS 143, VALARIS 147 and VALARIS 148 contracts, which were terminated during 2024.
(4)The decrease in ARO backlog is due to revenues realized and a reduction of backlog of approximately $125.0 million attributable to the termination of the VALARIS 143, VALARIS 147 and VALARIS 148 contracts.
The following table summarizes our and 100% of ARO's contract backlog as of February 18, 2025 and the periods in which revenues are expected to be realized (in millions):
| 2025 | 2026 | 2027 and beyond | Total | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Floaters | $ | 946.2 | $ | 687.7 | $ | 390.1 | $ | 2,024.0 | ||||||||
| Jackups | 617.2 | 408.6 | 287.2 | 1,313.0 | ||||||||||||
| Other | 92.7 | 114.1 | 64.7 | 271.5 | ||||||||||||
| Total | $ | 1,656.1 | $ | 1,210.4 | $ | 742.0 | $ | 3,608.5 | ||||||||
| ARO | $ | 369.4 | $ | 283.2 | $ | 770.3 | $ | 1,422.9 |
The amount of actual revenues earned and the actual periods during which revenues are earned will be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations and other factors.
Our drilling contracts generally contain provisions permitting early termination of the contract if the rig is lost or destroyed or by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions. In addition, our drilling contracts generally permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in certain cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.
BUSINESS ENVIRONMENT
Floaters
In recent years, the more constructive oil price environment led to an improvement in contracting and tendering activity for floaters. The number of contracted benign environment floaters increased to a peak of 128 in April 2024 from a low of 101 in early 2021, contributing to an increase in global utilization, from 73% to 86%, for the industry's marketed fleet over the same period, which resulted in a meaningful increase in day rates. During 2024, some customer demand for 2024 and 2025 was deferred to future periods, which slowed the pace of contracting compared to the previous three years. As a consequence, we have seen a modest decline in the number of contracted benign environment floaters to 123 at December 31, 2024, representing 83% utilization of the global marketed fleet, which has tempered day rates in the near term. However, there is a strong pipeline of opportunities for benign environment floaters, particularly for high specification drillships, with anticipated contract commencements in 2026 and beyond.
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From a supply perspective, as of December 31, 2024, the number of benign environment floaters including stacked rigs declined by 41% to 166 from a peak of 281 in late 2014. Given the moderate decline in utilization in the second half of 2024 for benign environment floaters, we could see further rigs retired from the global fleet. Also, given the expected high construction cost and lack of shipyard capacity, we do not believe that market conditions are supportive of floater newbuild construction for the foreseeable future.
Jackups
Contracting and tendering activity for jackups has improved in recent years as a result of the more constructive oil price environment, and we have seen a corresponding increase in utilization. The number of contracted jackups increased to a peak of 412 in March 2024 from a low of 341 in early 2021, contributing to an increase in global utilization, from 78% to 94%, for the industry's marketed fleet over the same period, leading to a meaningful increase in day rates for jackups.
In early 2024, Saudi Arabia announced that they plan to maintain maximum sustainable capacity at 12 million barrels per day. Since this announcement, Saudi Aramco has sent contract suspension notices to several offshore drillers to suspend contracts, totaling 33 rigs, which represents 8% of the marketed jackup fleet. This included notice to ARO with respect to its drilling contracts for VALARIS 143, VALARIS 147 and VALARIS 148. To date, 11 of the 33 suspended rigs have been contracted in other regions and one rig has been retired from the offshore drilling fleet. We believe that less than half of the remaining suspended rigs are likely to be competitive in other higher-specification, benign environment regions. Adjusting for the rigs under suspension that are awaiting to resume their contracts with Saudi Aramco, utilization for the global marketed jackup fleet was 88% at December 31, 2024. The decrease in global utilization from earlier in 2024 is putting some downward pressure on day rates in certain benign environment regions.
From a supply perspective, as of December 31, 2024, the number of jackups declined by 7% to 503 from a peak of 542 in early 2015. While the number of jackups has decreased less than floaters, 28% of the current jackup fleet is more than 40 years of age with limited useful lives remaining. Further, we believe that some of the jackups that are currently idle are not competitive, either due to their age or length of time stacked. Expenditures required to reactivate some of these rigs may prove cost prohibitive and drilling contractors may instead elect to scrap certain rigs. We believe there are only 11 newbuild jackups remaining at shipyards, of which eight are at Chinese shipyards, some of which are expected to be used locally in China.
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RESULTS OF OPERATIONS
The following table summarizes our Consolidated Results of Operations for the years ended December 31, 2024 and 2023 (in millions, except percentages):
| Years Ended December 31, | Change | % Change | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||||||||||
| Operating revenues | ||||||||||||||
| Revenues (exclusive of reimbursable revenues) (1) (3) | $ | 2,211.9 | $ | 1,676.0 | $ | 535.9 | 32 | % | ||||||
| Reimbursable revenues (2) (3) | 150.7 | 108.2 | 42.5 | 39 | % | |||||||||
| Total operating revenues (3) | 2,362.6 | 1,784.2 | 578.4 | 32 | % | |||||||||
| Operating expenses | ||||||||||||||
| Contract drilling expenses (exclusive of depreciation and reimbursable expenses) (1) (3) | 1,618.5 | 1,440.4 | 178.1 | 12 | % | |||||||||
| Reimbursable expenses (2) (3) | 142.4 | 103.2 | 39.2 | 38 | % | |||||||||
| Total contract drilling (exclusive of depreciation) (3) | 1,760.9 | 1,543.6 | 217.3 | 14 | % | |||||||||
| Depreciation | 122.1 | 101.1 | 21.0 | 21 | % | |||||||||
| General and administrative | 116.3 | 99.3 | 17.0 | 17 | % | |||||||||
| Total operating expenses | 1,999.3 | 1,744.0 | 255.3 | 15 | % | |||||||||
| Equity in earnings (losses) of ARO | (11.0) | 13.3 | (24.3) | (183) | % | |||||||||
| Operating income | 352.3 | 53.5 | 298.8 | NM | ||||||||||
| Other income, net | 17.9 | 30.7 | (12.8) | (42) | % | |||||||||
| Provision (benefit) for income taxes | 0.4 | (782.6) | 783.0 | (100) | % | |||||||||
| Net income | 369.8 | 866.8 | (497.0) | (57) | % | |||||||||
| Net (income) loss attributable to noncontrolling interests | 3.6 | (1.4) | 5.0 | (357) | % | |||||||||
| Net income attributable to Valaris | $ | 373.4 | $ | 865.4 | $ | (492.0) | (57) | % |
NM - Not meaningful
(1)For the purposes of our discussion below, we refer to Revenues (exclusive of reimbursable revenues) and Contract drilling expense (exclusive of depreciation and reimbursable expenses) as "Revenues" and "Contract Drilling Expenses", respectively.
(2)We typically receive reimbursements from our customers for purchases of supplies, equipment and incremental services provided at their request. These reimbursements and the related costs incurred are recognized on a gross basis within Reimbursable revenues and Reimbursable expenses, respectively. Changes within these line items generally do not have a material effect on our operating results or cash flows.
(3)Certain previously reported line items presented in the Consolidated Statements of Operations (Total operating revenues and Total contract drilling expenses (exclusive of depreciation)) were further disaggregated to separately disclose Reimbursable revenues and Reimbursable expenses, respectively, to align with the updated presentation of our segment tables upon the adoption of ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The disaggregation of these line items is presentational only and was retrospectively applied to the year ended December 31, 2023. There were no impacts to the overall Total operating revenues or Total contract drilling expense (exclusive of depreciation) line items. See "Note 13 - Segment Information" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
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Overview
Revenues increased in 2024, compared to 2023, primarily due to $401.7 million of incremental revenue earned for VALARIS DS-17, VALARIS DS-8 and VALARIS DS-7, which have commenced new contracts since mid-2023 following reactivations. For the remaining fleet, there was a net increase of $165.8 million from higher average daily revenue, primarily due to certain rigs working under higher day rate contracts as compared to the prior year, which was partially offset by a $30.9 million net decrease attributable to fewer operating days in the current year.
Contract Drilling Expenses increased in 2024, compared to 2023, primarily due to incremental costs of $73.2 million incurred for VALARIS DS-17, VALARIS DS-7 and VALARIS DS-8 and $25.0 million of expense recognized in 2024 related to an accrual for a legal matter. We also incurred an aggregate $16.3 million in incremental costs related to the stacking of VALARIS DS-13 and VALARIS DS-14, which were delivered in December 2023 and stacked in early 2024, and three jackups, which were stacked during 2024 upon termination of their leases with ARO. For the remaining fleet, we had an increase in personnel-related costs of $32.7 million, partially driven by wage increases in certain regions and higher incentive compensation costs.
Depreciation expense increased in 2024, compared to 2023, primarily due to new assets placed in service for certain rigs that underwent reactivation projects and capital upgrades.
General and administrative expenses increased in 2024 compared to 2023, primarily due to higher professional fees and higher compensation related to our long-term incentive plans.
Other income, net, decreased in 2024, compared to 2023, primarily due to a $27.3 million gain on the sale of VALARIS 54 recognized in the prior year, a $15.9 million increase in interest expense, net, and a $15.3 million decrease in interest income. These decreases were partially offset by a $29.2 million loss from the extinguishment of the Senior Secured First Lien Notes due 2028 (the "First Lien Notes") recognized in 2023 (see "Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information) and a $17.3 million increase related to net foreign currency gains relative to the prior year, largely driven by favorable exchange rate movements in certain currencies.
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Rig Counts, Utilization and Average Daily Revenue
The following table summarizes the total and active offshore drilling rigs for Valaris and ARO as of December 31, 2024 and 2023:
| 2024 | 2023 | ||
|---|---|---|---|
| Total Fleet | |||
| Floaters | 18 | 18 | |
| Jackups(1) | 28 | 27 | |
| Other(2) | 7 | 8 | |
| Total Valaris | 53 | 53 | |
| ARO(3) | 9 | 8 | |
| Active Fleet (4) | |||
| Floaters | 13 | 13 | |
| Jackups (1) | 18 | 20 | |
| Other (2) | 7 | 8 | |
| Active Fleet - Valaris | 38 | 41 | |
| ARO (3) | 9 | 8 |
(1)During 2024, we leased VALARIS 108 and VALARIS 76 to ARO. Separately, during 2024 the contracts with ARO for VALARIS 143, VALARIS 147 and VALARIS 148 were terminated and the rigs have been preservation stacked.
(2)This represents the jackup rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. Rigs leased to ARO operate under long-term contracts with Saudi Aramco. During 2024, we leased VALARIS 108 and VALARIS 76 to ARO. Separately, the contracts with ARO for VALARIS 143, VALARIS 147 and VALARIS 148 were terminated.
(3)This represents the jackup rigs owned by ARO, which are operating under long-term contracts with Saudi Aramco, including Kingdom 2, which was delivered in the second quarter of 2024. This table does not include Kingdom 3, a newbuild jackup ordered by ARO in October 2024, as the rig is under construction.
(4)Active fleet represents rigs that are not preservation stacked and includes rigs that are in the process of being reactivated.
We provide management services in the U.S. Gulf of Mexico on two rigs owned by a third-party not included in the table above.
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Operating results for our contract drilling services segment are largely dependent on two primary revenue metrics: utilization and day rates. The following table summarizes our and ARO's rig utilization and average daily revenue by reportable segment:
| Years Ended December 31, | |||||||
|---|---|---|---|---|---|---|---|
| 2024 | 2023 | ||||||
| Rig Utilization - Total Fleet (1) | |||||||
| Floaters | 61% | 58% | |||||
| Jackups | 58% | 59% | |||||
| Other(2) | 100% | 100% | |||||
| Total Valaris | 67% | 66% | |||||
| ARO | 80% | 93% | |||||
| Rig Utilization - Active Fleet (1) | |||||||
| Floaters | 83% | 75% | |||||
| Jackups | 83% | 79% | |||||
| Other(2) | 100% | 100% | |||||
| Total Valaris | 87% | 83% | |||||
| ARO | 80% | 93% | |||||
| Average Daily Revenue (3) | |||||||
| Floaters | $ | 345,000 | $ | 265,000 | |||
| Jackups | 121,000 | 106,000 | |||||
| Other(2) | 38,000 | 42,000 | |||||
| Total Valaris | $ | 165,000 | $ | 130,000 | |||
| ARO | $ | 104,000 | $ | 96,000 |
(1)Rig utilization for the total fleet and active fleet are derived by dividing the operating days by the number of days in the period for the total fleet and active fleet, respectively. Active fleet represents rigs that are not preservation stacked and includes rigs that are in the process of being reactivated. Operating days equals the total number of days that rigs have earned and recognized day rate revenue, including days associated with early contract terminations, compensated downtime and mobilizations and excluding suspension periods. When revenue is deferred and amortized over a future period, for example, when we receive fees while mobilizing to commence a new contract or while being upgraded in a shipyard, the related days are excluded from operating days.
(2)Includes our two management services contracts and our rigs leased to ARO under bareboat charter contracts.
(3)Average daily revenue is derived by dividing Revenues (exclusive of reimbursable revenues) by the aggregate number of operating days.
Operating Income by Segment
Our business consists of four operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups, (3) ARO and (4) Other, which consists of management services on rigs owned by third parties and the activities associated with our arrangements with ARO under the bareboat charter arrangements (the "Lease Agreements"). Floaters, Jackups and ARO are also reportable segments.
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Our onshore support costs included within Contract Drilling Expenses are not allocated to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items." Further, general and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items."
Because ARO is a 50/50 unconsolidated joint venture, its full operating results included below are not included within our consolidated results and thus are deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
Segment information for the years ended December 31, 2024 and 2023 is as follows (in millions).
Year Ended December 31, 2024
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating revenues | ||||||||||||||||||||||
| Revenues (exclusive ofreimbursable revenues) (3) | $ | 1,382.8 | $ | 686.5 | $ | 512.5 | $ | 142.6 | $ | (512.5) | $ | 2,211.9 | ||||||||||
| Reimbursable revenues (1) (3) | 57.9 | 68.4 | — | 24.4 | — | 150.7 | ||||||||||||||||
| Total operating revenues (3) | 1,440.7 | 754.9 | 512.5 | 167.0 | (512.5) | 2,362.6 | ||||||||||||||||
| Operating expenses | ||||||||||||||||||||||
| Contract drilling expenses(exclusive of depreciation andreimbursable expenses) (3) | 930.3 | 477.1 | 367.7 | 63.6 | (220.2) | 1,618.5 | ||||||||||||||||
| Reimbursable expenses (1) (3) | 54.9 | 64.3 | — | 23.2 | — | 142.4 | ||||||||||||||||
| Total contract drilling(exclusive of depreciation) (3) | 985.2 | 541.4 | 367.7 | 86.8 | (220.2) | 1,760.9 | ||||||||||||||||
| Loss on impairment | — | — | 28.4 | — | (28.4) | — | ||||||||||||||||
| Depreciation | 58.1 | 45.0 | 89.2 | 9.5 | (79.7) | 122.1 | ||||||||||||||||
| General and administrative | — | — | 23.7 | — | 92.6 | 116.3 | ||||||||||||||||
| Equity in losses of ARO | — | — | — | — | (11.0) | (11.0) | ||||||||||||||||
| Operating income | $ | 397.4 | $ | 168.5 | $ | 3.5 | $ | 70.7 | $ | (287.8) | $ | 352.3 |
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Year Ended December 31, 2023
| Floaters | Jackups | ARO | Other | Reconciling Items | Consolidated Total | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating revenues | ||||||||||||||||||||||
| Revenues (exclusive ofreimbursable revenues) (1) (3) | $ | 902.8 | $ | 620.6 | $ | 496.6 | $ | 152.6 | $ | (496.6) | $ | 1,676.0 | ||||||||||
| Reimbursable revenues (2) (3) | 45.9 | 39.0 | — | 23.3 | — | 108.2 | ||||||||||||||||
| Total operating revenues (3) | 948.7 | 659.6 | 496.6 | 175.9 | (496.6) | 1,784.2 | ||||||||||||||||
| Operating expenses | ||||||||||||||||||||||
| Contract drilling expenses(exclusive of depreciation andreimbursable expenses) (1) (3) | 768.4 | 480.4 | 365.9 | 52.6 | (226.9) | 1,440.4 | ||||||||||||||||
| Reimbursable expenses (2) (3) | 43.6 | 37.0 | — | 22.6 | — | 103.2 | ||||||||||||||||
| Total contract drilling(exclusive of depreciation) (3) | 812.0 | 517.4 | 365.9 | 75.2 | (226.9) | 1,543.6 | ||||||||||||||||
| Depreciation | 55.8 | 40.0 | 65.9 | 5.0 | (65.6) | 101.1 | ||||||||||||||||
| General and administrative | — | — | 22.2 | — | 77.1 | 99.3 | ||||||||||||||||
| Equity in earnings of ARO | — | — | — | — | 13.3 | 13.3 | ||||||||||||||||
| Operating income | $ | 80.9 | $ | 102.2 | $ | 42.6 | $ | 95.7 | $ | (267.9) | $ | 53.5 |
(1)For the purposes of our discussion below, we refer to Revenues (exclusive of reimbursable revenues) and Contract drilling expense (exclusive of depreciation and reimbursable expenses) as "Revenues" and "Contract Drilling Expenses", respectively.
(2)We typically receive reimbursements from our customers for purchases of supplies, equipment and incremental services provided at their request. These reimbursements and the related costs incurred are recognized on a gross basis within Reimbursable revenues and Reimbursable expenses, respectively. Changes within these line items generally do not have a material effect on our operating results or cash flows.
(3)Certain previously reported line items presented in the Consolidated Statements of Operations (Total operating revenues and Total contract drilling expenses (exclusive of depreciation)) were further disaggregated to separately disclose Reimbursable revenues and Reimbursable expenses, respectively, to align with the updated presentation of our segment tables upon the adoption of ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. The disaggregation of these line items was presentational only and was retrospectively applied to the year ended December 31, 2023. There were no impacts to the overall Total operating revenues or Total contract drilling expense (exclusive of depreciation) line items. See "Note 13 - Segment Information" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
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Floaters
Floater Revenues increased $480.0 million, or 53%, in 2024 as compared to 2023, primarily due to incremental revenue of $401.7 million from VALARIS DS-17, VALARIS DS-8 and VALARIS DS-7, which have commenced new contracts since mid-2023 following reactivations. For the remaining floater fleet, there was a net increase of $113.5 million from higher average daily revenue, primarily due to certain floaters working under higher day rate contracts in the current period as compared to the prior year. These increases were partially offset by a $34.8 million decrease attributable to fewer operating days in the current year, largely driven by VALARIS DPS-5 and VALARIS DS-10, which completed their contracts in the third quarter of 2024.
Floater Contract Drilling Expenses increased $161.9 million, or 21%, in 2024 as compared to 2023, primarily due to incremental costs of $73.2 million incurred for VALARIS DS-17, VALARIS DS-8 and VALARIS DS-7 in 2024 and $25.0 million of expense recognized in 2024 related to an accrual for a legal matter. For the remaining fleet, there were increases of $34.7 million in personnel-related costs, partially driven by wage increases in certain regions and incentive compensation costs, $18.6 million from higher repair and maintenance costs, primarily due to planned maintenance during the current year, and $10.8 million incurred related to the stacking of VALARIS DS-13 and VALARIS DS-14 during 2024.
Jackups
Jackup Revenues increased $65.9 million, or 11%, in 2024 as compared to 2023, primarily due to a net increase of $56.0 million from higher average daily revenue, largely driven by certain rigs working under contracts with higher day rates than the prior year, and incremental operating days in 2024 of $9.2 million.
Jackup Contract Drilling Expenses decreased $3.3 million, or 1%, in 2024 as compared to 2023, primarily due to a $15.4 million decrease in repairs and maintenance costs, largely attributable to maintenance activities performed for certain rigs during special periodic surveys in the prior year period, and a net decrease in personnel-related costs of $4.0 million, partially driven lower costs as a result of leasing VALARIS 76 and VALARIS 108 to ARO during the first half of 2024. These decreases were partially offset by increased mobilization costs of $10.9 million, primarily driven by the amortization of mobilization costs related to VALARIS 247, which mobilized from the U.K. to Australia for a new contract in 2024, and $5.5 million in incremental costs related to the stacking of VALARIS 143, VALARIS 147, and VALARIS 148 after the termination of their leases with ARO.
ARO
The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for both the ARO-owned jackup rigs and the rigs leased from us. Contract Drilling Expenses are inclusive of the bareboat charter fees for the rigs leased from us. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements.
ARO Revenues increased $15.9 million, or 3%, in 2024 as compared to 2023, primarily due to $80.7 million of incremental revenue from Kingdom 1 and Kingdom 2, which commenced operations in November 2023 and August 2024, respectively, and VALARIS 108, which we began leasing to ARO during the first quarter of 2024. This increase was partially offset by decreases of $44.3 million related to the contract terminations for VALARIS 143, VALARIS 147 and VALARIS 148 during the current year and $17.6 million related to certain rigs which were undergoing maintenance projects or had unplanned downtime in the current year.
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ARO Contract Drilling Expenses remained relatively flat, with an increase of $1.8 million in 2024 as compared to 2023, primarily due to $16.8 million of incremental operating costs related to the operation of Kingdom 1, Kingdom 2 and VALARIS 108 in the current year and higher personnel-related costs of $2.2 million for the remainder of the fleet. These increases were largely offset by $16.9 million of lower bareboat charter lease expense, inclusive of certain adjustments, primarily driven by the terminations of the VALARIS 143, VALARIS 147 and VALARIS 148 contracts and corresponding bareboat charter leases during 2024.
During the year ended December 31, 2024, ARO recorded non-cash losses on impairment totaling $28.4 million with respect to the contract terminations for VALARIS 143, VALARIS 147 and VALARIS 148. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the impairment.
ARO depreciation expense increased $23.3 million, or 35%, in 2024 as compared to 2023, primarily due to the additions of Kingdom 1 and Kingdom 2 to the fleet.
Other
Other Revenues decreased $10.0 million, or 7%, in 2024 as compared to 2023, primarily due to a $16.6 million decrease in revenue from lease agreements with ARO, primarily driven by contract terminations for VALARIS 143, VALARIS 147 and VALARIS 148 during 2024. This decrease was partially offset by a $6.3 million increase in average daily revenues earned by our two managed rigs as a result of contract extensions executed in the first half of 2024 at higher rates.
Other Contract Drilling Expenses increased $11.0 million, or 21%, in 2024 as compared to 2023, primarily due to higher repairs and maintenance costs of $6.8 million related to special periodic survey related projects on the leased rigs and higher personnel-related costs for our managed rigs of $2.1 million.
Other Income (Expense), Net
The following table summarizes other income (expense), net, (in millions):
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| Interest income | $ | 86.1 | $ | 101.4 | ||
| Interest expense, net | (84.8) | (68.9) | ||||
| Net foreign currency exchange gains (losses) | 13.8 | (3.5) | ||||
| Net periodic pension and retiree medical income | 2.4 | 0.9 | ||||
| Net gain (loss) on sale of property | (0.2) | 28.6 | ||||
| Loss on extinguishment of debt | — | (29.2) | ||||
| Other, net | 0.6 | 1.4 | ||||
| $ | 17.9 | $ | 30.7 |
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Interest income decreased by $15.3 million, or 15%, in 2024 as compared to 2023, primarily due to a $21.2 million decrease in interest income on cash equivalents due to a lower average balance in 2024 and a $5.9 million decrease in interest income earned on our outstanding 10-year shareholder notes receivable due from ARO (the "Notes Receivable from ARO"), which was driven by lower outstanding principal balances as a result of a partial net settlement agreement executed in the second quarter of 2024 (the "Net Settlement Agreement") and lower interest rates relative to the prior year period. These decreases were partially offset by an increase from the recognition of non-cash interest income of $13.9 million for an adjustment to the discount on our outstanding Notes Receivable from ARO, which resulted from the Net Settlement Agreement. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on this matter.
Interest expense, net increased by $15.9 million, or 23%, in 2024 as compared to 2023, primarily due to higher interest expense of $26.1 million related to a higher principal debt balance through 2024. This increase was partially offset by higher capitalized interest of $10.2 million, primarily due to VALARIS DS-13 and VALARIS DS-14, which were delivered at the end of 2023, and certain rigs that underwent capital projects in 2024.
Net foreign currency exchange gains increased $17.3 million in 2024 as compared to 2023, primarily driven by favorable exchange rate movements in the euros, Brazilian reals, Mexican pesos, Angolan kwanza and Australian dollars, partially offset by unfavorable exchange rate movements in the Nigerian naira and Egyptian pounds. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for further information on our functional currency.
Net gains on the sale of property decreased by $28.8 million in 2024 as compared to 2023, primarily due to the sale of VALARIS 54 in 2023.
We recognized a $29.2 million loss from the extinguishment of the First Lien Notes in 2023. See "Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on this matter.
Provision for Income Taxes
Valaris Limited is domiciled and a resident for tax purposes in Bermuda. Our subsidiaries conduct operations and earn income in numerous countries and are subject to the laws of taxing jurisdictions within those countries. The income of our non-Bermuda subsidiaries is not subject to Bermuda taxation.
Income tax rates and taxation systems in the jurisdictions in which our subsidiaries conduct operations vary and our subsidiaries are frequently subjected to minimum taxation regimes. In some jurisdictions, tax liabilities are based on gross revenues, statutory deemed profits or other factors, rather than on net income, and our subsidiaries are frequently unable to realize tax benefits when they operate at a loss. Accordingly, during periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Furthermore, we will continue to incur income tax expense in periods in which we operate at a loss.
Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in profitability levels and changes in tax laws, our annual effective income tax rate may vary substantially from one reporting period to another.
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Effective Tax Rate
During the year ended December 31, 2024, we recorded an income tax expense of $0.4 million and had an effective income tax rate of 0.1%. Our 2024 consolidated effective income tax rate includes a discrete tax benefit of $85.8 million, primarily attributable to change in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Excluding the impact of the aforementioned discrete tax items, the consolidated effective income tax rate was 21.8% as of December 31, 2024.
During the year ended December 31, 2023, we recorded an income tax benefit of $782.6 million and had an effective income tax rate of (929.5)%. Our 2023 consolidated effective income tax rate includes a discrete tax benefit of $42.0 million primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years, including unrecognized tax benefits described below. Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rate was (872.3)% for the year ended December 31, 2023.
The tax benefit in 2023 includes a $799.5 million deferred tax benefit recognized in the fourth quarter of 2023 to reduce our valuation allowance due to the determination that sufficient positive evidence existed to conclude that a portion of the allowance was no longer needed. During 2023, we also recognized tax benefits for the reduction of unrecognized tax benefit liabilities related to the lapse of statutes of limitations applicable to certain of our tax positions of $73.6 million and settlements reached with taxing authorities of $41.8 million. These benefits were partially offset by a $88.6 million increase in unrecognized tax benefit liabilities for tax positions taken during prior years, including $66.0 million recognized in the fourth quarter of 2023 related to tax assessments received from the Luxembourg tax authorities. See "Note 10 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
The changes in our consolidated effective income tax rate excluding discrete tax items during the two-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from cash and cash equivalents and cash flows from operations. Additionally, we have liquidity available under our senior secured revolving credit agreement, which matures in 2028 (the "Credit Agreement."). We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures, from cash and cash equivalents, cash flows from operations, as well as cash to be received from maturity of our Notes Receivable from ARO and from the distribution of earnings from ARO. We may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. However, the Indenture governing our Second Lien Notes, as defined below, dated as of April 19, 2023 (the "Indenture"), and the Credit Agreement contain covenants that limit our ability to incur additional indebtedness.
Our cash and cash equivalents as of December 31, 2024 and 2023, were $368.2 million and $620.5 million, respectively. We have no debt principal payments due until 2030 and had $375.0 million available for borrowing, including up to $150.0 million for the issuance of letters of credit, under the Credit Agreement as of February 14, 2025. See "Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the Credit Agreement and the 8.375% Second Lien Notes due 2030 (the "Second Lien Notes").
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Cash Flows and Capital Expenditures
Absent periods where we have significant financing or investing transactions or activities, such as debt or equity issuances, share repurchases, debt repayments, business combinations or asset sales, our primary sources and uses of cash are driven by cash generated from or used in operations and capital expenditures. Our net cash provided by operating activities and capital expenditures were as follows (in millions):
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| Net cash provided by operating activities | $ | 355.4 | $ | 267.5 | ||
| Capital expenditures | $ | (455.1) | $ | (696.1) |
During the year ended December 31, 2024, we generated $355.4 million of cash flow from operating activities primarily due to operating income for the year of $352.3 million. Our primary uses of cash were $455.1 million for maintenance and upgrades of our drilling rigs, reactivation costs and costs to mobilize VALARIS DS-13 and VALARIS DS-14 to their stacking location after their delivery. Additionally, we spent $126.4 million under our share repurchase program during the year, which is discussed further below.
During the year ended December 31, 2023, we generated $267.5 million of cash flow from operating activities, primarily due to operating income for the year of $53.5 million, the collection of $45.9 million for certain tax refunds and other changes in working capital. Our primary uses of cash were $337.0 million for the purchase of VALARIS DS-13 and DS-14 and $359.1 million for maintenance and upgrades of our drilling rigs, including reactivations. Other primary sources and uses of cash during 2023 resulted from the First Lien Notes redemption, the corresponding Second Lien Notes issuance and our share repurchase program, which are each further discussed below, combined with the sale of VALARIS 54 for net proceeds of $30.3 million.
We continue to take a disciplined approach to reactivations of our stacked rigs, only reactivating them to the active fleet for opportunities that provide meaningful returns. Generally, most of the reactivation cost are operating expenses, recognized in the income statement, related to de-preservation activities, including reinstalling key pieces of equipment and crew costs. Capital expenditures during reactivations include rig modifications, equipment overhauls and any customer required capital upgrades. Reactivation costs incurred for VALARIS DS-13 and VALARIS DS-14 would be capitalized as such activities would be required to prepare the rigs for their intended use. We would generally expect to be compensated for any customer-specific enhancements.
Based on our current projections, we expect capital expenditures during 2025 to approximate $350.0 million to $390.0 million, primarily relating to maintenance and upgrade projects, including contract-specific capital expenditures. Depending on market conditions, contracting activity and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and acquire additional rigs.
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We review from time to time possible acquisition opportunities relating to our business, which may include the acquisition of rigs or other businesses. The timing, size or success of any acquisition efforts and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with cash on hand and proceeds from debt and/or equity issuances and may issue equity directly to the sellers. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend on our future operating performance, restrictions to incur additional debt in the Indenture and the Credit Agreement, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, any additional debt service requirements we take on could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to shareholders.
Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. Consistent with this strategy, we sold VALARIS 54 in April 2023 for $28.2 million. At the time of sale, the rig had a net book value of $0.9 million and we recognized a pre-tax gain on sale of $27.3 million within the Jackups segment during the second quarter of 2023. Further, in the first quarter of 2025, we sold VALARIS 75 resulting in a pre-tax gain on sale of approximately $23.0 million in 2025. Of the proceeds, approximately $14.0 million were collected upon closing, with the remaining $10.0 million expected to be received in equal installments on the first and second anniversaries of the closing. The rig had an immaterial net book value as of December 31, 2024.
We continue to focus on our fleet management strategy in light of the composition of our rig fleet. While taking into account certain restrictions on the sales of assets under our debt agreements, as part of our strategy, we may act opportunistically from time to time to monetize assets to enhance stakeholder value and improve our liquidity profile, in addition to reducing holding costs by selling or disposing of lower-specification or non-core rigs.
In connection with our sustainability-related efforts, during 2024, we spent approximately $9.0 million. Our sustainability initiatives will continue to require, among other actions, investment in systems and equipment and cooperation with our customers.
Financing and Capital Resources
First Lien Notes
The First Lien Notes were redeemed on May 3, 2023 for an aggregate redemption price of approximately $571.8 million (excluding accrued and unpaid interest) with a portion of the net proceeds from the issuance of the Initial Second Lien Notes, as discussed below. See “Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the First Lien Notes.
Second Lien Notes
On April 19, 2023, the Company and Valaris Finance Company LLC (“Valaris Finance,” together, the "Issuers"), issued and sold $700.0 million aggregate principal amount of Second Lien Notes (the "Initial Second Lien Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The Initial Second Lien Notes were issued at par for net proceeds of $681.4 million, after deducting the initial purchasers’ discount and offering expenses. A portion of the proceeds were used to fund the redemption of all of the outstanding First Lien Notes as discussed above.
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Additionally, on August 21, 2023, the Issuers issued $400.0 million aggregate principal amount of additional Second Lien Notes (the "Additional Notes") in a private placement conducted pursuant to Rule 144A and Regulation S under the Securities Act. The Additional Notes were issued at 100.75% of par, plus accrued interest from April 19, 2023, for net proceeds of approximately $396.9 million after deducting the initial purchasers’ discount and estimated offering expenses, and excluding accrued interest received of $11.4 million. We used a portion of the proceeds to finance the purchase of VALARIS DS-13 and VALARIS DS-14.
The Initial Second Lien Notes and the Additional Notes were issued under the Indenture and form a single series. The Second Lien Notes mature on April 30, 2030 and bear an interest rate of 8.375% per annum. Interest is payable semi-annually in arrears on April 30 and October 30 of each year. See “Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the Second Lien Notes.
Senior Secured Revolving Credit Agreement
On April 3, 2023, the Company entered into a senior secured revolving credit agreement (the “Credit Agreement”). The Credit Agreement provides for commitments permitting borrowings of up to $375.0 million (which may be increased, subject to the satisfaction of certain conditions and the agreement of lenders to provide such additional commitments, by an additional $200.0 million pursuant to the terms of the Credit Agreement) and includes a $150.0 million sublimit for the issuance of letters of credit. Valaris Finance and certain other subsidiaries of the Company (together with Valaris Finance, the “Guarantors”) guarantee the Company’s obligations under the Credit Agreement, and the lenders have a first priority lien on the assets securing the Credit Agreement. The commitments under the Credit Agreement became available to be borrowed on April 19, 2023.
See “Note 6 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the Credit Agreement.
Investment in ARO and Notes Receivable from ARO
We expect to receive cash from ARO in the future both from the maturity of our Notes Receivable from ARO and from the distribution of earnings from ARO.
The distribution of earnings to the joint-venture partners is at the discretion of the ARO board of managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and long-term capital requirements of ARO. ARO has not made a cash distribution of earnings to its partners since its formation.
The Notes Receivable from ARO, which are governed by the laws of Saudi Arabia, mature during 2027 and 2028. In the event that ARO is unable to repay the Notes Receivable from ARO when they become due, we would require the prior consent of our joint venture partner to enforce ARO’s payment obligations. In June 2024, the Company and ARO executed a Net Settlement Agreement whereby approximately $50.7 million of our accounts payable due to ARO relating to our bareboat charter arrangements were net settled against a portion of the principal of our Notes Receivable from ARO. Furthermore, the 2024 interest owed by ARO on the Notes Receivable from ARO of $24.6 million was paid in kind in December 2024 by increasing the principal balance of the Notes Receivable from ARO.
See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our investment in ARO and Notes Receivable from ARO.
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The following table summarizes the maturity schedule of our Notes Receivable from ARO as of December 31, 2024 (in millions):
| Maturity Date | Principal Amount | |
|---|---|---|
| October 2027 | $ | 213.6 |
| October 2028 | 163.0 | |
| Total | $ | 376.6 |
Contractual Obligations
The following table summarizes our significant contractual obligations as of December 31, 2024 and the periods in which such obligations are due (in millions):
| Payments due by period | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2025 | 2026 and 2027 | 2028 and 2029 | Thereafter | Total | ||||||||||||||
| Principal payments on long-term debt | $ | — | $ | — | $ | — | $ | 1,100.0 | $ | 1,100.0 | ||||||||
| Interest payments on long-term debt | 92.1 | 184.3 | 184.3 | 46.0 | 506.7 | |||||||||||||
| Operating leases | 32.7 | 52.2 | 8.5 | 3.0 | 96.4 | |||||||||||||
| Total contractual obligations(1) | $ | 124.8 | $ | 236.5 | $ | 192.8 | $ | 1,149.0 | $ | 1,703.1 |
(1)Contractual obligations do not include $128.3 million of unrecognized tax benefits, inclusive of interest and penalties, included within Other liabilities on our Consolidated Balance Sheet as of December 31, 2024. We are unable to specify with certainty whether we would be required to and in which periods we may be obligated to settle such amounts.
In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. The Shareholder Agreement specifies that ARO shall purchase 20 newbuild jackup rigs over an approximate 10-year period. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash on hand and from ARO's operations and/or funds available from third-party financing. The first newbuild jackup, Kingdom 1, was delivered and commenced operations in the fourth quarter of 2023, and the second newbuild jackup, Kingdom 2, was delivered in the second quarter of 2024 and commenced operations in the third quarter of 2024.
In January 2020, ARO paid 25% of the purchase price from cash on hand for each of the two newbuilds, and in October 2023, entered into a $359.0 million term loan to finance the remaining newbuild payments due upon delivery and for general corporate purposes. The term loan matures in eight years following the related drawdown under the term loan and requires equal quarterly amortization payments during the term, with a 50% balloon payment due at maturity. The term loan bears interest based on the three-month Secured Overnight Financing Rate (SOFR) plus a margin ranging from 1.25% to 1.4%. Additionally, in the second quarter of 2024, ARO entered into a revolving credit facility which provides for borrowings of up to $100.0 million. As of December 31, 2024, there was $10.0 million outstanding under this facility. Our Notes Receivable from ARO are subordinated and junior in right of payment to both ARO’s term loan and credit facility.
In October 2024, ARO ordered the third newbuild jackup, Kingdom 3, for a purchase price of approximately $300.0 million, and paid the 25% down payment from cash on hand. The final payment will be due upon delivery of the rig. ARO is expected to commit to order one additional newbuild jackup in the near term. ARO intends for these newly ordered jackup rigs to be financed out of cash on hand or from operations or funds available from third-party financing.
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In the event ARO has insufficient cash or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Beginning with the delivery of the second newbuild, each partner's commitment shall be reduced by the lesser of the actual cost of each newbuild rig or $250.0 million, on a proportionate basis. Following the delivery of Kingdom 2, our commitment to fund the newbuild program has been reduced to $1.1 billion. See "Note 3 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO.
Other Commitments
We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of December 31, 2024, we were contingently liable for an aggregate amount of $27.0 million under outstanding letters of credit, which guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2024, we had collateral deposits in the amount of $10.8 million with respect to these agreements.
The following table summarizes our other commitments as of December 31, 2024 (in millions):
| Commitment expiration by period | ||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2025 | 2026 and 2027 | 2028 and 2029 | Thereafter | Total | ||||||||||||||
| Letters of credit | $ | 9.8 | $ | 17.2 | $ | — | $ | — | $ | 27.0 |
Tax Assessments
In February 2024, one of our Malaysian subsidiaries received an unfavorable court decision regarding a tax assessment for the 2012-2017 tax years totaling approximately MYR117.0 million (approximately $26.0 million converted at current period-end exchange rates), including a late payment penalty. In July 2024, we received a payment demand from the Malaysian tax authority for the full assessment amount. In order to further contest the assessment, we agreed to a seven-month payment plan which commenced in August 2024. As of December 31, 2024, we made payments of approximately $18.0 million, which are included within Other assets in the Consolidated Balance Sheets, and had approximately $8.0 million of remaining payments. We have not recorded a liability for uncertain tax positions as of December 31, 2024 related to this assessment based on a more-likely-than-not threshold. We believe our tax returns are materially correct as filed and we will vigorously contest this assessment.
In December 2023, one of our Luxembourg subsidiaries received tax assessments for fiscal years 2019, 2020, 2021 and 2023. In February 2024, the Luxembourg tax authorities rescinded the portion of the assessment relating to 2023, resulting in a revised aggregate tax assessment of approximately €60.0 million (approximately $65.0 million converted at then-current exchange rates). We recorded a liability for uncertain tax positions for this amount during the fourth quarter of 2023 and contested the validity and amount of the assessments. In April 2024, we received a favorable decision from the Luxembourg tax authorities stating that the assessments for the 2019-2021 tax years are not enforceable. As a result, we reversed the uncertain tax position liability for the previously issued assessments and recognized a tax benefit of approximately $65.0 million in our Consolidated Statements of Operations for the year ended December 31, 2024.
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During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101.0 million (approximately $63.0 million converted at current period-end exchange rates) plus interest related to the examination of certain of our tax returns for the years 2011 through 2016. During the third quarter of 2019, we made a A$42.0 million payment (approximately $29.0 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. In December 2024, we reached a settlement agreement with the Australian tax authorities for A$4.0 million (approximately $2.0 million at current period-end exchange rates). As a result, we expect to receive a refund of A$38.0 million (approximately $24.0 million at current period-end exchange rates) in the first half of 2025. Accordingly, we released approximately $18.0 million of the uncertain tax position liability previously recognized and recognized a corresponding tax benefit in our Consolidated Statements of Operations for these assessments in the fourth quarter of 2024.
See "Note 10 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on these tax assessments.
Share Repurchase Program
Our board of directors has authorized a share repurchase program under which we may purchase up to $600.0 million of our outstanding common shares. The following table summarizes shares repurchase, aggregate cost (exclusive of fees) and the average per share price (in millions, except average per share price):
| Years Ended December 31, | ||||||
|---|---|---|---|---|---|---|
| 2024 | 2023 | |||||
| Shares repurchased | 2.2 | 3.0 | ||||
| Total aggregate cost | $ | 125.0 | $ | 200.0 | ||
| Average per share price | $ | 56.11 | $ | 66.77 |
As of December 31, 2024, we had approximately $275.0 million available for share repurchases pursuant to the Share Repurchase Program.
Effects of Climate Change and Climate Change Regulation
GHG emissions have increasingly become the subject of international, national, regional, state and local attention, and in recent years, the U.S. has taken evolving and divergent positions on GHG regulations and commitments. For example, the U.S. has initiated the process of withdrawing from the Paris Agreement in January 2025, after previously reentering it in February 2021. In November 2021, the U.S. and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy. New regulatory action and/or legislation targeting GHG emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, may be proposed and/or promulgated at the state or local level of the U.S.
In an effort to reduce GHG emissions, governments have implemented or considered legislative and regulatory mechanisms to institute carbon pricing mechanisms, such as the EU’s Emission Trading System, and to impose technical requirements to reduce carbon emissions. Governments have also proposed or implemented new or enhanced disclosure requirements related to climate change matters and GHG emissions that may increase compliance and disclosure costs. In January 2023, the EU enacted the Corporate Sustainability Reporting Directive, which will require sustainability reporting across a broad range of sustainability topics for both EU and non-EU companies. We anticipate that these requirements will apply to us as early as 2026 (for fiscal year 2025) for certain of our EU subsidiaries and at the consolidated entity level in 2030 (for fiscal year 2029).
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During 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish permitting requirements, including emissions control technology requirements, for certain large stationary sources that are potential major sources of GHG emissions. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain onshore and offshore oil and natural gas production facilities. Although a number of bills related to climate change have been introduced in the U.S. Congress in the past, comprehensive federal climate legislation has not yet been passed by Congress. If such legislation were to be adopted in the U.S., such legislation could adversely impact many industries. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs and commitments to contribute to meeting the goals of the Paris Agreement.
Future legislation or regulation of GHG emissions could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. Depending on the particular program, we, or our customers, could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. It is uncertain whether any of these initiatives will be implemented and what the impact of such initiatives would have on our financial condition, operating results and cash flows.
MARKET RISK
Interest Rate Risk
Our outstanding debt at December 31, 2024 consisted of our $1.1 billion aggregate principal amount of Second Lien Notes. We are subject to interest rate risk on our fixed-interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates impacting the fair value of the debt.
Our Credit Agreement provides for commitments permitting borrowings of up to $375.0 million at December 31, 2024. As the interest rates for such borrowings are at variable rates, we are subject to interest rate risk. As of December 31, 2024, we had no outstanding borrowings under the Credit Agreement.
Our Notes Receivable from ARO bear interest based on the one-year term SOFR rate, set as of the end of the year prior to the year applicable, plus 2.10%. As the Notes Receivable from ARO bear interest on the applicable SOFR rate determined at the end of the preceding year, the rate governing our interest income in 2025 has already been determined. A hypothetical 1% decrease to SOFR would decrease interest income for the year ended December 31, 2025 by $3.8 million based on the principal amount outstanding at December 31, 2024 of $376.6 million.
Foreign Currency Risk
Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in the foreign currency or revenue earned differs from costs incurred in the foreign currency. We do not currently hedge our foreign currency risk.
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the U.S. requires us to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Our significant accounting policies are included in "Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements.
We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, income taxes and pension and other post-retirement benefits.
Property and Equipment
As of December 31, 2024, the carrying value of our property and equipment totaled $1.9 billion, which represented 44% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.
We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. We have identified the significant components of our drilling rigs and ascribed useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.
The judgments and assumptions used in determining the next overhaul or the economic lives of the components of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of the significant components our rigs, would likely result in materially different asset carrying values and operating results.
The useful lives of our drilling rig components are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rig components on a periodic basis, considering operating condition, functional capability and market and economic factors.
Our fleet of 18 floater rigs represented 59% of the gross cost and 61% of the net carrying amount of our depreciable property and equipment as of December 31, 2024. Our fleet of 35 jackup rigs represented 38% of the gross cost and 37% of the net carrying amount of our depreciable property and equipment as of December 31, 2024.
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Income Taxes
We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2024, our Consolidated Balance Sheet included a $819.4 million net deferred income tax asset, a $44.8 million liability for income taxes currently payable and a $128.3 million liability for unrecognized tax benefits, inclusive of interest and penalties.
The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.
We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we may be subject to additional income taxes.
The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on our interpretation of applicable tax laws and incorporate estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.
We operate in several jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information.
Tax returns are routinely subject to audit in most jurisdictions and tax liabilities occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:
•During recent years, the number of tax jurisdictions in which we conduct operations has increased.
•In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed and challenged by tax authorities.
•We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.
•Tax laws, regulations, agreements, treaties and the administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.
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Pension and Other Postretirement Benefits
Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, mortality rates, annual compensation increases, and other factors. Key assumptions at December 31, 2024, included (1) a weighted average discount rate of 5.54% to determine pension benefit obligations, (2) a weighted average discount rate of 4.97% to determine net periodic pension cost and (3) an expected long-term rate of return on pension plan assets of 6.88% to determine net periodic pension cost. The assumed discount rate is based upon the average yield for either Moody’s or Standard & Poor's Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations.
Using our key assumptions at December 31, 2024, a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $53.2 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $4.6 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which decreased to 6.44% at December 31, 2024 from 6.88% at December 31, 2023. See "Note 9 - Pension and Other Post Retirement Benefits" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on our pension and other postretirement benefit plans.
NEW ACCOUNTING PRONOUNCEMENTS
See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on new accounting pronouncements.